August 21, 2017
ENERGY WATCH #1 by Karel Beckman
Trends in energy storage
August 21, 2017
A new study has strengthened previous evidence that energy storage is getting more distributed, more tied to solar, more long-term and more based on lithium-ion, according to specialist publication Energy Storage Report (ESR).
ESR notes that the Grid-Connected Energy Storage Market Tracker published by IHS Markit shows “1.3GW of grid-connected energy storage was installed in 2016. The figure is expected to grow to 4.7GW in 2020 and 8.8GW by 2025. IHS Markit predicts the market will grow from USD$1.5bn in 2016 to more than $7bn in 2025, a 16% compound annual growth rate.”
However, what is more interesting than these (theoretical) figures is the real trends that IHS Markit sees taking place. Until recently, author Julian Jansen of IHS Markit notes, energy storage was driven by “single applications”. Now, however, the trend is “to add new application and value streams to storage assets, to help improve the project payback time and return on investment.”
This, in turn, “is helping to drive energy storage adoption, particularly by utilities. New value is emerging for utility-side-of-meter storage, primarily from capacity requirements, the integration of utility-scale solar and island micro-grids.”
However, IHS Markit also forecasts that “behind-the-meter installations will overtake front-of-meter installs by 2020”, writes , writes Jason Deign of ESR .
This is particularly due to the growth of solar-plus-storage, which has been booming both in Europe and the U.S. “States such as California, Hawaii and New York are increasingly requiring solar to be tied to battery storage so energy can be delivered to the grid outside peak production times.” In Germany around 50% of new PV installations already have a battery attached.
Another trend in utility-level storage is an increasing demand for longer duration. “For frequency response, you only needed 30 minutes, maybe an hour maximum,” said Jansen. “When you’re looking at integrating solar, you’re starting to need longer-duration storage, of three or four hours.” Forecast growth in energy storage for longer-duration applications was “much more robust than in the sub-one-hour segment,” he added.
For longer-term storage, flow batteries are usually considered better suited than lithium-ion. However, ESR notes, “the IHS Markit research confirms another trend previously reported on in Energy Storage Report: the plummeting cost of lithium-ion batteries is increasingly allowing them to compete even in longer-duration applications.”
Because lithium-ion costs have come down so fast, even at four hours most projects are lithium ion, said Jansen. “It’s going to be difficult for others because the segment they’ve always seen as a sweet spot is starting to be occupied by lithium ion.”
An added problem for non-lithium-ion contenders is that many utilities show a marked preference for buying from dominant vendors, which in the battery market almost invariably limits choice to lithium-ion products.
There is more alarming news for non-lithium-ion battery producers, because it looks like one of the major drawbacks of lithium-ion batteries is capable of being solved.
This requires a little explanation. Currently, one of the major disadvantages of lithium-ion batteries is that they use liquid electrolytes (this is the material between the positive and negative electrodes), which are flammable and have been known to set devices on fire.
Liquid electrolytes are also prone to the formation of dendrites – “thin, fingerlike projections of metal that build up from one electrode and, if they reach all the way across to the other electrode, can create a short-circuit that could damage the battery”.
For this reason, developers would like to replace liquid with solid electrolytes, such as certain ceramics – but that has always proven to be problematic, because these materials perform “somewhat erratically and are more prone to short-circuits than expected”.
Now new research by a group of academics from MIT, published in Advanced Energy Materials, shows that the problem could be solved. As MIT News reports, “the prevailing idea was that the material’s firmness or squishiness (a property called shear modulus) determined whether dendrites could penetrate into the electrolyte. But the new analysis showed that it’s the smoothness of the surface that matters most. Microscopic nicks and scratches on the electrolyte’s surface can provide a toehold for the metallic deposits to begin to force their way in, the researchers found.”
This suggests, according to one of the researchers, “that simply focusing on achieving smoother surfaces could eliminate or greatly reduce the problem of dendrite formation in batteries with a solid electrolyte. In addition to avoiding the flammability problem associated with liquid electrolytes, this approach could make it possible to use a solid lithium metal electrode as well. Doing so could potentially double a lithium-ion battery’s energy capacity — that is, its ability to store energy for a given weight, which is crucial for both vehicles and portable devices.”
What the MIT researchers describe is still theory at the moment, but given the interests at stake there can be little doubt that developers will jump on this.
Over at Toyota in Japan they already seem to be working on a similar track, because, as the website CleanTechnica reported recently, the Japanese car maker has said it is working on an all-electric car with solid-state lithium-ion batteries “that offer long range and fast recharging”. The plan is for the car to be introduced by 2022.
As author Steve Hanley writes, “no one doubts that solid-state batteries are the future. Replacing the liquid electrolyte found in today’s lithium-ion batteries will eliminate the risk of fire and explosion associated with current battery technology. That danger, while low, remains a concern for many people considering the purchase of an electric car. To limit such risks, electric cars today must use sophisticated cooling systems to stabilize the temperature inside battery packs. Such systems add cost, weight, and bulk to the cars. Solid-state batteries will not need such elaborate cooling systems, which will help bring down the cost of building an electric car. As an added bonus, they are capable of being recharged in much less time than a conventional lithium-ion battery.”
Hanley mentions several research groups that are working on solid-state batteries and indeed planning introductions of cars with solid-state lithium-ion batteries. Toyota is a relative latecomer to the EV market, previously having placed its bet on hydrogen cars.
But Toyota, the largest car manufacturer in the world, “like all major carmakers, is focused on the booming automobile market in China”, notes Hanley. “It plans to introduce an electrified version of its C-HR sport utility vehicle using conventional [i.e. with liquid electrolytes] lithium-ion batteries there in 2019, spurred in part by the insistence of the Chinese government that at least 10% of the new cars sold in the country be EVs by that date. It also brought its highly imaginative Concept-i to the 2017 CES show in Las Vegas last January.”
Nevertheless, not all is lost for flow batteries and other competitors of lithium-ion. Energy Storage Report recently reported on research by Imperial College in London, which showed that “flow batteries could achieve significant levels of cost reduction with relatively minor increases in production volume.”
The study showed “redox flow batteries achieving a ‘competitive’ capital cost threshold of USD$650 per kWh of capacity by 2019, once around 7GWh or $4bn of projects had been installed. Lithium-ion batteries, in contrast, would require at least 33GWh of installations to reach the same level. This would take until 2023 and cost $94bn, the authors concluded.”
Note that the $650 price point was chosen “as a level at which energy storage systems could be competitive based on their ability to deliver multiple services simultaneously”, but the authors acknowledge that Tesla with its Powerwall is already offering systems at below $500 per KWh.
ESR notes that flow batteries have a difficult time competing with lithium-ion for two reasons. “Part of this is because flow battery makers mostly lack the corporate clout of big lithium-ion manufacturers such as LG Chem or Panasonic. That has made lithium-ion a much safer bet for battery buyers such as utilities.
But a perhaps much greater reason for lithium-ion’s predominance is its increasingly widespread use in the electric vehicle market.”
Still, what the Imperial College study confirms is that flow batteries could become commercially attractive at much lower installed volumes than those required for lithium ion. “That means a few very large projects could make a big difference to the flow battery industry.”
One such project was announced recently by German utility EWE which is proposing to build “the world’s largest battery”, a brine-based redox flow battery.
And EWE is not alone in developing alternatives for lithium-ion batteries.
The US-based company Aquion, for example, is developing “a relatively inexpensive battery for grids and microgrids, promising to make it cheaper and easier to integrate renewable energy sources like wind and solar. The company initially said it expected to manufacture batteries for less than $300 per kilowatt-hour of capacity, using technology that paired a saltwater electrolyte with a manganese oxide cathode and a carbon-based anode.”
One small problem is that the company – which counted Shell and Bill Gates among its investors – went bankrupt earlier this year.
Now, however, it has found new investors and is starting up again. As MIT Technology Review reports, in July the company was acquired by “a majority-American joint venture that is closely affiliated with China Titans Energy Technology Group, a publicly traded investment holding company focused on grid technology.”
Aquion’s battery is intended to be used with electricity grids and microgrids. The fact that the company was acquired by a Chinese buyer means that its manufacturing may move to China.
“The new backers intend to invest tens of millions more to put the company back on track, re-establishing the supply chain and setting up manufacturing over the course of at least the next six months … once that happens, the product will have a more direct and clear business path. Aquion’s original sales strategy was to go after niche markets, supplying batteries to small grid operators and renewable projects, mainly in developing countries. But now it will be able to sell directly to big grid operations in China, providing a huge advantage.”
Moving away from batteries to other storage alternatives, the website Climate Central reports that Alphabet, the mother company of Google, is researching the possibilities of molten salt as storage.
“Alphabet’s X research lab is developing a cutting-edge molten salt technology that aims to store wind and solar power for longer periods of time and for less cost than the giant lithium-ion batteries Tesla and other companies are designing”, writes Bobby Magill of Climate Central.
As Climate Central writes, “big batteries aren’t the only way to store electricity. There is a plurality of contenders (for power storage technologies) including pumped hydro, compressed air, flywheels. … Electricity storage is hugely complex and will be satisfied not by a single solution.”
“Malta” – the code name of Alphabet’s project – stores “wind and solar power by converting electricity to thermal energy. Heat is stored in molten salt, and cold is stored in a vat of liquid antifreeze solution. When the power is needed, the hot and cold energy are converted back into electricity by a heat engine.”
It remains to be seen of course how competitive this project will turn out to be.
In fact, some researchers go even further: they are working on batteries that last (almost) forever, as a recent article on The Conversation noted.
The research relates to batteries used in sensors and other applications that use “energy harvesting”, i.e. energy collected from the environment, through the sun or through vibrations. Sensors are often used in remote or difficult-to-access places where recharging is expensive or impossible. The problem is that energy harvesting is also intermittent and unpredictable, like solar and wind.
To address this problem, researchers from CSIRO, Australia’s national science agency and one of the largest research organisations in the world, “have designed a software framework that can adapt a device’s sensing and computation tasks based on a forecast of harvested energy. This ensures that the sensor can collect and dispatch the necessary data without running out of power”.
This software, says the CSIRO researchers, “aims to help devices operate in an energy-neutral way, so that the battery can last indefinitely or until its recharge cycles are exhausted.”
One example they mention is their Camazotz tracking device that they use for researching flying foxes. “This device is attached to the animals using collars and collects GPS data to understand their movements. It also has a tiny battery and solar panel to recharge each day. Our software can predict the likely movement of the animal and energy availability, and use this data to determine suitable schedules for the use of on-board sensors. This ensures that the energy needed for obtaining the GPS samples does not exceed the energy we expect to have available through the solar panels.”
The software framework “can also be used for consumer devices such as smartphones and wearables. But while there is no hard battery lifetime for this approach, how long the battery lasts will still depend on the maximum number of times the battery can be recharged before dying.”
Fascinating stuff. Self-sustaining, everlasting batteries could even lead to the creation of “indefinitely powered devices that can sense, think, and act moves us closer to creating artificial life forms.
Couple that with an ability to reproduce through 3D printing, for example, and to learn their own program code, and you get most of the essential components for creating a self-sustaining species of machines.”
For more on energy storage, note that last week in our Brussels Insider section we gave an overview of the latest developments in the European market, including the UK’s new huge research initiative, the Faraday Challenge.
Over in Australia, Elon Musk and his Tesla won a much-talked about government tender to build a 100 MW/129MWh lithium-ion battery storage installation – the largest of its kind in the world. What this big Tesla battery can and cannot do, you can read here.
For some useful basic “guidelines” on how to read and interpret all the battery and storage news that you encounter in the media, see here.
Finally, for market watchers, we recommend this article by the Regulatory Assistance Project, which explains very clearly why large retail organisations (in this case in the U.S.) are very likely to massively increase their reliance on solar plus storage (a warning to utilities!).
ENERGY WATCH #2 by Karel Beckman
Shale gas in the UK: 55 million years too late?
August 21, 2017
The UK is one of the very few countries in Europe doggedly pursuing the development of shale gas. Indeed, last week, on 17 August, the company Cuadrilla Resources conducted the first exploratory drilling at its Preston New Road site in Lancashire.
Planning consent for Cuadrilla to explore for shale gas at the site using fracking was granted by the government in October 2016, when it overruled local councillors’ rejection, reports Carbon Brief.
The UK government’s insistence on developing the country’s shale gas is controversial. The BBC notes that the government’s opinion tracker, published this month, showed public support for fracking has fallen to 16%, with opposition at 33%. But it also reported a lack of knowledge of the technology, with 48% of people neither supporting nor opposing it.
Now, however, a researcher, Professor John Richard Underhill, Chief Scientist and Professor of Exploration Geoscience at Heriot-Watt University, has questioned whether the UK’s shale reserves are all that they are cracked up to be. To be more precise: the reserves may be there, but Underhill argues that they will not be as accessible as in the U.S.
In The Conversation he writes that for all the discussion around fracking in the UK, little attention had been paid to “whether the country’s geology is suitable for shale oil and gas production. The implication is that because fracking works in the US, it must also work here. In fact, the UK’s geological history suggests this is probably wrong.”
As Underhill explains: “For a ‘sweet spot’ to be suitable for commercial fracking, a number of geological criteria need to be met. The source rock needs a relatively high organic content, a good thickness, sufficient porosity and the right mineralogy. The organic matter must have been buried and heated in such a way as to produce large amounts of gas. There must also be a relatively simple geological structure.”
“The most successful US shale areas, such as the Marcellus, Barnett, Haynesville and Bakken, all lie at depths and temperatures that mean they are ready to expel their oil and gas when fracked. The basins in which these occur are primarily in relatively stable, undeformed areas away from the edges of active tectonic plates, which geologists refer to as intracratonic basins. They are characterised by continuous layers of rock with only gentle dips and few fractures or major faults. This all aids subsurface imaging, gas/oil detection and the directional drilling needed for shale exploration.”
Howver, a “cursory look at the geological map of the UK shows a very different proposition. The whole land mass has been significantly uplifted by a chain of geological events that started some 55 million years ago with the upward rise of a plume of magma under Iceland. This helped break the tectonic plate in two, pushing Greenland and North America in one direction and the eastern segment containing the British Isles in the other, forming the Atlantic Ocean in between. The crust moving east buckled against the stable tectonic interior of continental Europe, not only uplifting the British Isles but also tilting it so that north-west Scotland was elevated the most. For this reason, the oldest rocks in the UK are in places such as Lewis and Harris while the youngest ones occur in south-east England.”
“This movement profoundly affected many of the basins of sedimentary rock that make up the British Isles – including those considered to contain large shale resources. Areas once buried sufficiently deeply to experience temperatures where oil and gas are generated were lifted to levels where this could no longer occur – unlike in the US where the relevant rock formations remain at their greatest depth of burial today. The UK rock formations have also been highly deformed by the buckling to create folds and faults that cause the shales to be offset and broken up into compartments. At the same time, the activity created pathways that have allowed some of the oil and gas to escape.”
What all this means, then, according to Underhill, is that “even where a shale source in the UK may have high organic content and thick and favourable mineralogy, the complex structure of the basins will be detrimental to ultimate recovery. Yet the only question that has been addressed to date is how large the shale resource could be in the UK. The inherent geological complexity of the sedimentary basins has not been fully appreciated or articulated. As a result, the opportunity has been overhyped and reserve estimates remain unknown.”
He concludes that “it would be extremely unwise to rely on shale gas to ride to the rescue of the UK’s gas needs only to discover it is 55 million years too late”.
In The Guardian, the body representing the UK’s shale gas industry, UK Onshore Oil and Gas (UKOOG) responded to Underhill’s article by acknowledging that more exploration is needed. Ken Cronin, the chief executive of UKOOG, said: “The industry is currently in the process of seismic surveying, core drilling and flow testing in various parts of the country to determine a number of questions including the extent of the geology and whether gas will flow commercially. This process is an industry standard around the world. It is too early to make any firm predictions, but with imported gas predicted to rise to 80% [of UK gas consumption] by 2035, it is important that we get on and complete this work.”
Quentin Fisher, a professor of petroleum geoengineering at the University of Leeds, said more work was needed as the disadvantages pointed out in the seismic imaging could be balanced by other factors with an advantage for shale extraction. “Prof Underhill is quite correct to highlight the great uncertainties that exist regarding the likely productivity of shale in the UK and is correct that the geology in the UK tends to be structurally more complex than in the US. Many of us involved in this debate have regularly highlighted the large uncertainties that exist,” Fisher said.
But Fisher noted that “Although geological complexity and late tilting may be detrimental to shale gas prospects in the UK, there are other factors that may be more favourable, such as having thicker shale sequences.” He said the only way to find out was through testing. “The bottom line is that the only way to truly assess the viability is to drill wells, and we need to get on with that.”
Technical director Mark Lappin of Cuadrilla Resources told the BBC: “We have noted the BGS [British Geological Survey] estimates for gas-in-place and consider that volume to be indicative of a very large potential reserve. It’s the purpose of our current drilling operations to better understand the reserve, reduce speculation from all sides and decide if and how to develop it. I expect Professor Underhill would be supportive of the effort to understand the resource including geological variation.”
Professor Richard Davies, from Newcastle University, has another interesting response. He said to BBC News: “It’s correct to say geology could yet surprise the companies who are investing. But the bottleneck, I think, is how many wells one can drill economically in a small space in the UK. Shale gas wells in the USA produce very small volumes of gas (2-6 billion cubic feet of gas each), and therefore thousands would be needed to impact on our reliance on imports. The BGS estimated resources in Northern England of 1,327 trillion cubic feet (2012). I estimated it would require circa 52,000 wells to produce 10% of this.”
Note that the U.S. has proved reserves of 307 trillion cubic feet (8.7 trillion m3), the UK currently has proven natural gas reserves of just 7 trillion cubic feet (200 billion m3).
So the resources the BGS estimates for Northern England – 1,327 trillion feet (37 trillion m3) – are enormous. Even 10% of this amount (3700 billion m3) would cover current UK consumption (75 billion m3) for 50 years. The UK is the second largest gas user in the EU, after Germany, and imports around half of its gas.
ENERGY WATCH #3 by Karel Beckman
Does the U.S. nuclear industry have a future? (And if not, what are the consequences?)
August 21, 2017
If even someone like specialised (pro-)nuclear energy journalist Dan Yurman asks the question – Does the U.S. nuclear industry have a future? – and answers it with “Maybe not” – it is clear that we are talking about a major crisis in the U.S. nuclear industry.
The reason for the crisis mood is the cancellation, on 31 July, of two partially-built AP1000 Westinghouse reactors at the V.C. Summer nuclear plant in South Carolina by the builders, South Carolina Electric & Gas (SCE&G), a subsidiary of Scana Corp, and Santee Cooper.
This is not just any cancellation. Over $10 billion has already been spent on the construction of the two reactors. A large part of this money has been furnished by South Carolina ratepayers. SCE&G is a regulated electricity and gas utility, Santee Cooper stands for South Carolina Public Service Authority and is owned by the State of South Carolina.
In other words, we are talking about a big disgrace.
As Jim Green, editor of Nuclear Monitor, a nuclear-critical publication, writes in the August issue, Scana CEO Kevin Marsh had gone as far as approaching the Trump Administration to ask for help, but no dice. “We went as high as Rick Perry, Secretary of Energy”, Marsh has said – asking for a non-repayable grant of between $1 and $3 billion, but he never heard back from Washington.
As Yurman points out, the failure of the VC Summer Plant (5,000 workers were laid off immediately) will have a huge impact on any further nuclear plans in the U.S.: “There is a strong likelihood that future plans by U.S. electric utilities to build full size nuclear reactors are now being put on indefinite hold”, he notes.
“Even though the NRC [Nuclear Regulatory Commission] has issued licenses, investors may not see a reason to proceed with projects like DTE’s Fermi III in Michigan, Dominion’s North Anna III in Virginia, and Duke’s William States Lee in South Carolina.”
The reasons for the nuclear crisis are well known: “Record low prices for natural gas are likely to persist for decades. The regulatory barriers to building new natural gas plants are surmounted with ease compared to gaining approval for a new reactor.”
Worse, Yurman says, “the failure of the V C Summer plant proved two things – the U.S. supply chain for nuclear components is broken and the lack of political support for the industry makes the likelihood that it will be fixed to help SMRs [small modular reactors] is unknown. If you want a list of all the ways the V C Summer project failed to meet expectations, Cheryl Rofer at Nuclear Diner has a list that will make your head spin.”
He also notes that “Secretary of Energy, Rick Perry, has no expertise associated with his agency’s mission and he once famously proposed to abolish it.” The nuclear industry, in fact, may have fared better with Perry’s predecessor under Obama, Ernest Moniz, who is a nuclear physicist.
The fall-out from VC Summer will most immediately impact another similar construction project going on in the neighbouring state of Georgia, the Vogtle project, which is being built by Georgia Power and a number of other utility companies. Georgia Power is a subsidiary of the Southern Company, one of the largest electric utilities in the U.S.
Vogtle has somewhat better chances than VC Summer. It is closer to completion, notes Jim Green in Nuclear Monitor. It is 66% complete, and the first of the two AP1000-reactors is supposed to go online in 2021 or 2022. What is more, Toshiba, the bankrupt mother company of Westinghouse, the supplier of all four AP1000 reactors in South Carolina and Georgia, has settled for a payment of $3.68 billion to Vogtle, considerably more than the $2.2 billion it will pay VC Summer.
However, Green adds, there are also important similarities between the two projects. They are both long-delayed and billions over budget. Georgia ratepayers to date have furnished $1.2 billion to pay for the nuclear plant, which was originally said to cost $14 billion, but whose costs are currently estimated at $25 billion! And even that figure could prove to be an underestimate, Green notes.
It is beginning to sink in among analysts in the U.S. that the demise of the U.S. nuclear industry could have far-reaching geopolitical implications. The United States has traditionally been the world leader in nuclear technology and has exported a lot of its knowledge to its allies and partners across the world. More: many alliances have been built at least partially on nuclear cooperation.
But this position is now increasingly being taken over by China and Russia. Those two countries are the only ones who are currently expanding their nuclear power capacity and successfully exporting their nuclear technology. Japan and France have long since fallen behind and South Korea, the one remaining nuclear leader outside Russia and China, looks ready to abandon its nuclear power sector under its new president.
On 10 August, Mark Hibbs, described by Yurman as a world class expert on nuclear energy, associated with the Carnegie Endowment for International Peace, issued a warning that the current nuclear crisis “could have far-reaching strategic impact on U.S. exports and on the economic viability, safety, and security of nuclear power installations in the United States and beyond.”
Hibbs notes that the United States still generates one-fifth of its electricity from 100 nuclear power reactors. “That’s more reactors than in any other country, but until 2013 the last construction start in the United States was in 1977. During the intervening years, nuclear power plant constructors were saddled with challenges: more demanding safety and regulatory requirements following nuclear accidents at Three Mile Island, Chernobyl, and Fukushima; rising input costs; lack of political support; power market deregulation; and competition from other sources, chiefly wind and natural gas.”
Until recently, the US still had two major players in the nuclear sector: Westinghouse, which had been acquired by Toshiba, and is now bankrupt, and GE, which cooperates with another Japanese firm, Hitachi. GE-Hitachi is now the last big nuclear company left standing in the U.S.
Hibbs notes that “by contrast, the nuclear industries in China and Russia appear immune to and poised to capitalize on the problems that have beset Western firms. Both have made big plans to aggressively export nuclear power plants.”
“Russia aims to build nuclear power plants in Bangladesh, Egypt, Iran, Jordan, and Turkey. China’s ambitions mirror Russia’s. Beijing’s leading champion, the China National Nuclear Corp., predicts that by 2030 China will build nearly one-third of the one-hundred power reactors that will be exported in the world, led off by projects in Algeria, Argentina, Ghana, Pakistan, Saudi Arabia, and the United Kingdom.”
Although many of the plans will not come to fruition, writes Hibbs, “there are four basic reasons why nuclear power plant exporters and their governments in the United States and other Western countries should be keenly concerned about China’s and Russia’s understandably ambitious forays into future nuclear power plant markets.”
First, “Chinese and Russian nuclear-power-plant-exporting companies are state-owned enterprises (SOEs). They serve the goals of their national governments’ energy-fuel diplomacy; they benefit from close, even direct relationships between heads of government and top management (the Chinese Communist Party in fact must approve appointments of senior executives in Chinese nuclear firms); they also benefit from privileged access to money and information, in some cases without transparent oversight. They offer financing terms to potential clients that Western firms, bound by OECD export credit rules, cannot match. Western vendors for these reasons are at a competitive disadvantage.”
Secondly, “During the heyday of American nuclear industry dominance, roughly from about 1960 through the 1980s, companies in the United States exported nuclear fuel, technology, expertise, and equipment under a U.S. government international program called Atoms for Peace. This was designed to expand U.S. influence during the Cold War, and it succeeded. Now, regardless of whether and when Russia and China will build power plants in the dozens of countries they are courting, memorandums of understanding and other bilateral agreements will provide Beijing and Moscow access to strategic decisionmaking in these countries concerning technology, energy, and foreign policy for decades to come.”
Thirdly, “Countries that import nuclear power plants commit to managing this technology over a project life cycle of a hundred years. They will be less inclined to buy turnkey wares from partners that do not inspire confidence that they will be using nuclear power for more than one or two decades. Siemens, Germany’s leading nuclear power plant builder, withered and then left the nuclear sector after political support for nuclear power there evaporated after the Chernobyl accident. Areva, France’s nuclear engineering champion, which gobbled up most of Siemens’ nuclear business, now nervously waits for President Emmanuel Macron to re-commit France to nuclear power development. During the last two decades, when leading Western vendors virtually halted new domestic nuclear power plant construction, industry in China and Russia built scores of reactors at home. By comparison, Western firms’ long-term loss of domestic expertise and political support will negatively ripple across their entire supply chain, and both the economics and the safety of installations operating in these countries may in coming years be threatened.”
Fourthly, “questions about international governance have been raised in the face of a future shift toward newcomers and away from the established nuclear-technology-owning countries that, beginning half a century ago, made the rules for nuclear exporting, nonproliferation, nuclear security, and business transparency. Consideration of possible Chinese nuclear investment in the UK led to a probe of possible security vulnerabilities that would have been dismissed outright in the case of, say, investment by an EU firm. Very recent concerns have been raised in the United States about alleged Russian cyberattacks against nuclear power targets. The U.S. Department of Justice in 2014 charged an officer in China’s People’s Liberation Army with economic espionage against Westinghouse related to the company’s nuclear project work in China. Most members of the Nuclear Suppliers Group, the world’s leading multilateral nuclear export arrangement, believe that both China and Russia have not strictly adhered to the group’s guidelines concerning their exports to India and Pakistan, respectively. China’s support for international efforts to rein in North Korea’s dangerous nuclear weapons program has proved limited and conditioned upon other Chinese strategic interests.”
Professor Michael E. Webber of the Energy Institute at the University of Texas at Austin has similarly warned that “the withering nuclear power industry is threatening US national security”. He notes, among other things, that “as the nuclear power industry [in the U.S.] declines, it discourages the development of our most important anti-proliferation asset: a bunch of smart nuclear scientists and engineers.”
Webber writes that it is “the irony of nuclear power” that while “many worry that the prominence of nuclear materials for power production increases the risks of weapons proliferation, the opposite is also a problem. The loss of expertise from a declining domestic nuclear workforce makes it hard for Americans to conduct the inspections that help keep the world safe from nuclear weapons. And with the recent news about North Korea’s nuclear ambitions, the need for inspections feels like a pressing priority.”
Both Hibbs and Webber argue that the U.S. should put a price on carbon emissions to support the U.S. nuclear industry – although they realise that any such proposal faces formidable political challenges with Trump in power.
The contrast between the U.S. and Chinese nuclear sectors was symbolized last week by a report in China Daily that China has set up a venture to build floating nuclear power plants in the South China Sea.
This is a plan that has been around for a while, but as Dan Yurman reports, now a joint venture has been set up that is bringing the project closer to reality. State-owned China National Nuclear Power Co has teamed up with four other domestic companies who have put up with 1 billion yuan ($150 million) in registered capital.
The joint venture “will seek to strengthen China’s nuclear power capabilities in line with its ambitions to become a strong maritime power, the company said in a statement. The statement did not say how or where the technologies will be used, but observers told Reuters it is likely they will be deployed in areas such as the South China Sea.’”
According to Reuters, “Wang Yiren, vice-director of the State Administration for Science, Technology and Industry for National Defense, said earlier this year that the expansion of China’s nuclear energy capabilities was a vital part of its five-year plan. The country will prioritize the development of a floating nuclear power platform in order to support its offshore oil and gas activities, and its presence in the Paracel and Spratly Islands, he told state media.”
While deploying floating nuclear reactors in the South China Sea has obvious geopolitical implications, “China emphasized in its announcement that the floating reactors have commercial uses. They can be used to operate drilling machinery for offshore oil and gas fields, and remote power and desalination needs. These objectives are expected to bring investors to support the new venture and with the parallel support from the military as the first customer for the plants, the effort seems positioned for growth.”
Incidentally, Russia is ahead of China in the development of floating nuclear plants. The Akademik Lomonosov, a floating nuclear power plant consisting of two 35 MW reactors, is currently under construction at the Baltic Shipyard, in St Petersburg. According to Andrey Bukhovtsev of Rosatom, it is 96% complete. It will be launched later this year, towed to Murmansk, and then transported to Pevek, a port in Russia’s Far East, where it will begin generating power in 2019. The reactors are expected to be fueled and operating prior to starting the journey.
All of this raises the question of what the world’s nuclear future will look like – and what the EU and “western” countries should do – whether they should want to continue to play a prominent role in the nuclear power sector. It is a question that will have to be answered by policymakers – and the sooner the better.
Certainly the International Atomic Energy Agency (IAEA) is far from certain how nuclear energy will fare the coming decades. In its International Status and Prospects for Nuclear Power 2017, an annual overview of the global nuclear sector, released on 7 August, it provides a high case projection, which sees nuclear growing by 123% in 2050, and a low-case projection, which sees no growth at all.
World Nuclear News, a publication of the World Nuclear Association, unsurprisingly stresses the high case. It observes that, according to the IAEA report, “if nuclear power’s potential as a low-carbon energy source grows in recognition and advanced reactor designs further improve both safety and radioactive waste management, the use of nuclear power could grow significantly.”
“In its high case projection, global nuclear generating capacity increases from 392 GWe at the end of 2016 to 554 GWe by 2030, 717 GWe by 2040 and 874 GWe by 2050. Nuclear’s share of global electricity generation would increase from the current level of about 11% to 13.7% by 2050. This projection – which assumes that current rates of economic and electricity demand growth, particularly in Asia, will continue – reflects that 30-35 new reactors are expected to be grid connected annually starting around 2025. This rate of connections was last seen in 1984, when 33 new reactors were connected to the grid, the IAEA noted. However, it says 33 grid connections by 2025 would require immediate action today“.
In Europe, according to the IAEA high case projection, “capacity initially dips but recovers to reach 120 GWe by 2050.”
By contrast, the IAEA’s “low case projection assumes a continuation of current market, technology and resource trends with few changes to policies affecting nuclear power. It is designed to produce conservative but plausible” estimates. It does not assume that all national targets for nuclear power will be achieved.”
“Under this projection, nuclear capacity decreases from 392 GWe at the end of 2016 to 345 GWe by 2030, a further decrease to 332 GWe by 2040, before recovering to present levels by 2050. Nuclear’s share of global electricity generation declines from the current level of about 11% to 6% by 2050.”
“The IAEA noted that, although this projection appears to show no net growth in installed capacity through to 2050, it does not mean there is no new construction. In fact, even in the low case, some 320 GWe of new nuclear power capacity will be installed by 2050, making up for the loss caused by retiring reactors, albeit not necessarily in the same regions.”
In the low-case projection, significant decline is expected in North America and “in the region including northern, western and southern Europe”.
By the way, whereas the IAEA even in its high-case projection has nuclear power contributing 13.7% to global electricity demand by 2050, note that the World Nuclear Association has a target for nuclear energy to provide 25% of electricity in the world by that time. You can judge for yourself how realistic that is.
ENERGY WATCH #4 by Karel Beckman
Fact check: what is cheaper, coal or renewables?
August 21, 2017
I end this week’s edition of Energy Watch with an interesting “fact check” written by Ken Baldwin, Director of the Energy Change Institute at Australia National University, and reviewed by Dylan McConnell, a researcher at the Australian German Climate and Energy College at the University of Melbourne, and Tony Wood, Program Director Energy at the Grattan Institute in Australia.
The fact check, reported on The Conversation, looks at a statement by the (former) Australian Resources Minister Senator Matt Canavan, who said during a television appearance, in reply to a question from an audience member, that “I don’t accept that renewables are, at the moment, cheaper than coal”.
Baldwin writes that, strictly speaking, Canavan is right: “Based on the electricity generated now by old coal-fired power stations with sunk costs (meaning money that has already been spent and cannot be recovered), Canavan was right to say: ‘I don’t accept that renewables are, at the moment, cheaper than coal’.”
He notes that “in 2017, the marginal cost of generating power from an existing coal station is less than $40/MWh, while wind power is $60-70/MWh (explained below).”
But, Baldwin goes on to say, this applies to existing power capacity. It makes a big difference when you look at the new-build price: “Making the distinction between the cost of existing energy generation and the cost of new-build energy generation in this debate is very important. Comparing the two is like comparing apples and oranges. Current prices are based on existing installations, while new-build prices compare the costs of different technologies if their operating lives started today.”
New-build costs are highly relevant, notes Baldwin, because 9 of Australia’s 12 coal power stations are more than 30 years old and will have to be replaced sooner or later (or closed prematurely for climate policy reasons).
So how does this comparison turn out?
“To establish the current price of wind power, we can look at the announcement by Origin Energy in May 2017. The company agreed to buy all the power to be generated by the Stockyard Hill Wind Farm in Victoria between 2019 and 2030 for less than $60/MWh.”
“A similar price was struck in March 2016 when the Australian Capital Territory government conducted its second “wind auction”. The government uses wind auctions to buy contracts for future energy supplies. The lowest price in the 2016 auction yielded around $60/MWh in current prices. This figure is based on a flat rate of $77/MWh for 20 years and assumes around 3% inflation, which is the upper end of Australia’s inflation rate target of 2-3%.”
“Combining the total price range for that auction with this inflation range gives around $60-$70/MWh in current prices, with wind farms currently operating in that adjusted range.”
The cost of newly built coal power stations is more difficult to estimate, but, writes Baldwin, “we do have recent levelised price projections for the cheapest new-build fossil fuel energy, which is supercritical coal power. The projected price for new supercritical coal power comes in at around $75/MWh from the recent Finkel review of the National Electricity Market, based on data produced by Jacobs Consultancy. That is consistent with the price of $80/MWh from the 2016 report by the CO2 Cooperative Research Centre, and less than the $84-94/MWh from the 2012/3 Australian Energy Technology Assessment.”
“These projections for new supercritical coal power are higher than the recent prices for newly installed wind power (outlined earlier in the FactCheck) at around $60-70/MWh in current prices over the 20-year contract period (which is similar to a levelised cost).”
So, Baldwin concludes, “if we look at recent wind power prices and recent price projections for new supercritical coal power, it’s reasonable to say that – as things stand today – wind power would be the cheaper new-build source of electricity.”
The two reviewers essentially agree. So there you have it: according to these three researchers, new wind power is cheaper than new coal power. And that’s in Australia – which has plenty of domestically produced coal.