PARIS – Cambridge and North Dumfries Hydro, also known as Energy+, has purchased Brant County Power Inc. for $40.2 million.
County of Brant announced to the sale on Monday afternoon (May 12).
The county will receive $32.2 million after settlement of debt and other obligations, which it said represents a significant premium over Brant Power’s book value.
The county announced last August it was putting its utility up for sale to raise money for infrastructure and help keep property taxes under control.
Conditions of the sale protect Brant Power customers from hikes in hydro distribution rates for four years and guarantee the jobs of Brant Power employees.
Energy+ agreed to freeze current Brant Hydro distribution rates for four years. Afterward, Energy+ will apply to the Ontario Energy Board to harmonize the Brant Power rates with its own rates, which is expected to result in similar or lower rates for Brant customers than if Brant Power remained municipally owned.
About 30 per cent of a customer’s hydro bill covers distribution. The rest is the actual cost of the electricity, which is set by the Ontario Energy Board.
Energy+ also agreed to continue to employ all Brant Power employees and honor all existing conditions of employment following the transaction, and continue operations from Brant Power’s Paris operations center for at least five years.
County council will create an investment fund using the sale proceeds. Annual returns are expected to “significantly” exceed the annual dividend the county received from Brant Power. The investment proceeds will go to infrastructure projects and to maintain and improve country roads, bridges, parks, trails and other public assets.
Ontario Energy Board approval of the sale is expected to take four to five months.
During that time, the county will work with Energy+ and Brant Power representatives on a transition plan. Energy+ plans to form an advisory committee made up of representatives from the county and its own officials.
Day-ahead power markets are set to be linked from Portugal to Finland as the European Union seeks to integrate electricity markets by the end of this year across the 28-nation bloc.
Spain and Portugal are due to today join the existing 15-country market coupling project, linked through an interconnector between Spain and France. Network operators and energy exchanges have held a single auction at noon Paris time since Feb. 4 to determine next-day power prices in the northwest of Europe.
Linking markets is part of the EU’s third package of legislation intended to remove national barriers to power and gas trading and reduce energy costs. Market coupling aims to smooth price differences between nations through better control of cross-border flows. Before coupling, traders selling power into another country had to buy cable capacity in advance, and then make a separate trade on another exchange, exposing themselves to two sets of price risk.
“This is the first time a market coupling arrangement has been geographically expanded,” Andrew Claxton, director of business development at APX Group Holding BV, said by e-mail. “Previously this has involved implementing a whole new solution. This shows that we have a robust underlying solution that can be extended across Europe.”
Day-ahead power market coupling links Austria, Belgium, Denmark, Estonia, France, Finland, Germany, Latvia, Lithuania, Luxembourg, Norway, the Netherlands, Poland, Portugal, Spain, Sweden and the U.K. excluding Northern Ireland, according to N2EX, a U.K. exchange.
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“Although the interconnection level between the Iberian Peninsula and Central West Europe, through the Pyrenees, is very limited, the new mechanism ensures a proper use,” Rafael Gomez-Elvira Gonzalez, a Madrid-based spokesman for Iberian exchanges OMIE, said by e-mail. “Market coupling optimizes the use of existing cross-border capacities.”
Day-ahead markets in Romania will be linked to Slovakia, Hungary and the Czech Republic through the price coupling mechanism on Nov. 11, Czech power market operator OTE AS said April 9.
Plans to link Swiss day-ahead markets with European countries have stalled after the bloc halted talks on the Alpine nation joining its energy market. The EU suspended talks after Swiss voters on Feb. 9 approved immigrant quotas, a move contrary to market-opening pacts with the EU going back to 2002.
Europe’s plans to link intraday power markets ground to a halt after power exchanges failed to agree on who would develop a platform. The European Commission said on Feb. 6 that it would propose legally binding obligations to ensure the intraday platform is developed. Exchanges from APX Group Holding BV to Epex Spot SE said on Feb. 10 they had reached an agreement and are working on an EU-wide platform.
Yes: we’ll have to invest a lot but in the long term this could save the planet as well as huge sums of money, according to the IEA.
The IEA’s soberly named biennial report Energy Technology Perspectives 2014 casts a look at the energy sector over the next 40 years.
While these are the long term net gains, there are also some seriously costly investments needed to spur these changes.
The IEA estimates that an additional US$44 trillion of investment will be needed to meet 2050 carbon reduction targets.
This represents an increase of 22% from the figure the Agency gave two years ago ($36 trillion).
The investments would guarantee that the average temperature rise since the industrial revolution is limited to 2-degrees Celsius.
According to the Agency investments in renewables, nuclear power and carbon capture and storage would – in the long term – yield more than $115 trillion in fuel savings.
According to Maria van der Hoeven - executive director of the Paris-based IEA – coal use if still growing and outpacing that of renewable energies, while the intensity of electricity emissions has remained stable for the past two decades, though there has been some progress in certain areas.
The agency claims that tripling the use of renewable energy, nuclear power and carbon capture and storage by 2050 would be crucial to reaching the goal carbon reduction goal.
San Antonio had to claw its way into contention for Tesla Motors' planned “gigafactory,” a dream project that would put 6,500 people to work in a $5 billion plant that produces lithium-ion batteries.
By several accounts, local officials overcame the city's also-ran status in the early stages of Tesla's site selection. They finally coaxed the electric-car maker into taking a serious look at San Antonio for the project, which the Palo Alto, Calif.-based company announced in late February.
Now, San Antonio may be considered the strongest potential site in Texas.
That's because CPS Energy brings a lot to the table as a would-be partner for Tesla and because Mayor Julián Castro is reportedly working as many angles to win the project as he and his staff can think of.
As Tesla vets potential locations, CPS Energy is posting flirtatious Tweets on the virtues of electric vehicles. The city-owned utility is also using social media to play up its commitments to renewable energy — it's looking to make wind and solar power account for 20 percent of its electricity sources by 2020 — and demand response, which is when customers voluntarily reduce their use of electricity at times of peak demand.
Presumably, that's music to the ears of Elon Musk, the co-founder, CEO and chairman of Tesla. He's also co-founder of SolarCity, one of the largest providers of residential solar systems in the U.S., and Tesla's gigafactory would produce battery packs not just for Tesla vehicles but also “stationary storage applications” for homes and businesses. Solar panels on rooftops and battery systems to store the power they generate would come in handy for the demand response CPS Energy boasts about.
Texas — which is competing against Arizona, Nevada and New Mexico for the gigafactory — also has caught a couple of lucky breaks lately.
A big black mark against both Texas and Arizona is that they basically outlaw Tesla's distribution model — to sell cars directly to consumers, without going through franchised auto dealers.
True, Texas lawmakers are unlikely to break free of the hold dealers have on them (and their campaign accounts) anytime soon. But at least Arizona proved itself to be in the same position last week; a bill that would have allowed Tesla to sell straight to consumers — perhaps giving the state an edge — died in the legislature, according to news reports.
Also last week, the drive in New Mexico for a special legislative session to OK incentives for the gigafactory appears to have petered out, Albuquerque Business First reported Tuesday.
But as San Antonio officials have gotten their hopes up, questions about the viability of Musk's gigafactory have been relentless. An April 1 headline in the Wall Street Journal: “Does Tesla Really Need a $5 Billion Battery Factory?”
Some of the skepticism started with Panasonic, which currently supplies lithium-ion batteries to Tesla.
The maker of the luxury Model S sedan is willing to spend $2 billion on the facility, which would take up 10 million square feet and sit on as many as 1,000 acres. The company needs partners to cover the other $3 billion, and Musk suggested Panasonic might be one of them.
But Panasonic's president, Kazuhiro Tsuga, was noncommittal when he talked with reporters in Tokyo on March 26. As Bloomberg reported, he said: “Elon plans to produce more affordable models besides Model S, and I understand his thinking and would like to cooperate as much as we can. But the investment risk is definitely higher.”
Tesla has stayed mum on potential partners since then.
The big idea behind the gigafactory is that mass production, with raw materials such as lithium and cobalt coming in the front door and battery packs going out the back, will push down the cost of batteries by about 30 percent. Since batteries are the most expensive components of electric vehicles, the cost cuts would make Tesla cars less expensive.
A good thing, considering the Model S now starts at a little more than $70,000.
The company also has its mid-market Model E in the works — a car priced for the rest of us. It's expected to launch in 2017, the same year Tesla wants its gigafactory to start production.
Some of the questions coming at Tesla are whether it could actually slice 30 percent off of battery production costs, and how it would source the raw materials. But the most important question is whether enough drivers will embrace all-electric vehicles to keep the gigafactory humming.
As planned, the facility would produce enough batteries for 500,000 vehicles per year by 2020.
Selling that many Teslas would be a real feat.
The company began delivering the Model S is 2012 and had sold over 25,000 in North America and Europe by the end of 2013, according to a filing with the Securities and Exchange Commission. For a little perspective: Chevrolet sold 42,000 Silverado trucks in March.
Overseas sales will be critical to Tesla. The manufacturer will start selling Model S sedans in China this month, and in Japan, the United Kingdom and Australia later this year.
A local official I talked with recently, who's worked on the gigafactory bid, was hopeful but also wary, saying, “There are questions about how viable this project is.
“It depends on your view of the future. Will enough people give up their gas-powered cars?”
An employee holds a piece of coal in a storage yard at the Joban Joint Power Co. Nakoso coal-fired power station in Iwaki City, Fukushima Prefecture, Japan.
Prime Minister Shinzo Abe is pushing Japan’s coal industry to expand sales at home and abroad, undermining hopes among environmentalists that he’d use the Fukushima nuclear accident to switch the nation to renewables.
A new energy plan approved by Japan’s cabinet on April 11 designates coal an important long-term electricity source while falling short of setting specific targets for cleaner energy from wind, solar and geothermal. The policy also gives nuclear power the same prominence as coal in Japan’s energy strategy.
In many ways, utilities are already ahead of policy makers. With nuclear reactors idled for safety checks, Japan’s 10 power companies consumed 5.66 million metric tons of coal in January, a record for the month and 12 percent more than a year ago, according to industry figures.
“You cannot exclude coal when you think about the best energy mix for Japan to keep energy costs stable,” said Naoya Domoto, president of energy and plant operations at IHI Corp., a developer of a technology known as A-USC that burns coal to produce a higher temperature steam. “One way to do that is to use coal efficiently.”
Japan’s appetite for coal mirrors trends in Europe and the U.S., where the push for cheaper electricity is undermining rules limiting fossil fuel emissions and supporting cleaner energy. In the U.S., a frigid winter boosted natural gas prices, providing catalyst for utilities to extend the lives of dirtier coal plants. Germany, Spain and Britain are slashing subsidies for renewables to rein in the cost of electricity.
An employee walks in a coal storage yard at the Joban Joint Power Co. Nakoso coal-fired power station in Iwaki City, Fukushima Prefecture, Japan.
For renewable energy environmental groups, Japan’s policy is a mixed bag offers little in the way of policy direction. Instead, it backs the status quo, calling for reactors shut after the 2011 disaster to be restarted while offering no targets for the amount of power coming from wind and solar.
“What had been expected of the basic plan was to present a major policy to switch from nuclear power,” the Japan Renewable Energy Foundation said in a statement. “But the basic plan shows that the government has given up to fulfill that role. The plan does not promote a shift from old energy policies.”
WWF Japan urged the government to set a target to promote clean energy as soon as possible.
“The energy plan failed to present the spirit of innovation,” the conservation group said in a statement April 11. “Japan basically needs to recognize an increase in coal use is a serious issue for climate change. The country needs to push for reduction of carbon dioxide.”
The Joban Joint Power Co. Nakoso coal-fired power station stands illuminated at night in Iwaki City, Fukushima Prefecture, Japan.
In calling for technology to be used to soften coal’s environmental impact, the plan acknowledges that traditional fossil fuels pollute more and carry higher costs.
Before the accident, Japan got 62 percent of its electricity from fossil fuels, and nuclear made up about a third, according to government figures. Since then, utilities reverted to fossil fuels such as liquefied natural gas and coal to replace nuclear capacity taken offline. Those thermal power sources generated about 90 percent of Japan’s electricity in fiscal 2012, according to figures in the energy plan.
Buying more fossil fuels comes at a cost. The resource-poor nation has run 20 consecutive months of trade deficits and last year backtracked on promises to cut greenhouse gas emissions. That jarred United Nations talks involving 190 nations discussing ways to limit global warming.
“It’s crucial to have diverse energy sources for a country like Japan, which relies on imports for all energy,” said Akira Yasui, an official in charge of coal policy at the Ministry of the Economy, Trade and Industry. “Our basic stance is to use coal while caring for the environment as much as possible. Coal is economical and stable in supply.”
Abe’s government is supporting the development and export of advanced coal technology from Japan. According to a growth strategy released in June by the prime minister, the nation intends during the 2020s to commercialize A-USC technology. It’s also seeking to sell a equipment that combines fuel cells with a process called integrated gasification combined cycle to improve the efficiency of power generation.
“By applying Japan’s most advanced coal technology, the U.S., China and India can reduce a combined 1.5 billion tons of carbon dioxide emissions per year,” far above Japan’s total emissions, Toshimitsu Motegi, Japan’s trade minister, told parliament in February.
Japan’s interest in IGCC technology is on display at the Nakoso Power Station’s No. 10 coal power generator, about 60 kilometers (37 miles) south of the wrecked Fukushima nuclear plant. The unit, set up in 2007 to demonstrate the feasibility of the technology, can produce about a quarter of a typical nuclear reactor’s 1 gigawatt of electricity.
Had it not been for the Fukushima disaster three years ago, the generator would have been closed. Today, it’s up and working after repairs. The station, operated by a joint venture between Tokyo Electric Power (9501) Co. and Tohoku Electric Power (9506) Co., posted record output for the year ended March 31.
“This was a research generator,” Yoshitaka Ishibashi, associate director and executive general manager at the plant, said in an interview. “They’re usually dismantled once the study is over. But nuclear reactors were suspended, power supply was tight, and 250 megawatt is not a negligible capacity. So it was turned into a commercial one.”
Tokyo Electric, better known as Tepco, has other plans to use more coal for the stations that serve 29 million customers around the nation’s capital.
The utility plans to add two more IGCC generators at the Nakoso station and at its Hirono plant, also in Fukushima. A more traditional 600-megawatt coal-fired generator at the Hirono site began operating in December.
Power generation costs from IGCC can eventually be reduced to conventional coal power generation levels at 9.5 yen (9 cents) per kilowatt hour, though that may not happen for 10 years to 15 years, said Ishibashi at the Nakoso power station.
“The plan represents nothing but anachronism,” said Mie Asaoka, head of the Kiko Network, a Kyoto, Japan-based environmental organization.
This illustration shows a possible configuration of a floating offshore nuclear plant, based on design work by Jacopo Buongiorno and others at MIT's Department of Nuclear Science and Engineering. Like offshore oil drilling platforms, the structure would include living quarters and a helipad for transportation to the site. Illustration courtesy of Jake Jurewicz/MIT-NSE
New power plant design could provide enhanced safety, easier siting, and centralized construction.
When an earthquake and tsunami struck the Fukushima Daiichi nuclear plant complex in 2011, neither the quake nor the inundation caused the ensuing contamination. Rather, it was the aftereffects — specifically, the lack of cooling for the reactor cores, due to a shutdown of all power at the station — that caused most of the harm.
A new design for nuclear plants built on floating platforms, modeled after those used for offshore oil drilling, could help avoid such consequences in the future. Such floating plants would be designed to be automatically cooled by the surrounding seawater in a worst-case scenario, which would indefinitely prevent any melting of fuel rods, or escape of radioactive material.
Cutaway view of the proposed plant shows that the reactor vessel itself is located deep underwater, with its containment vessel surrounded by a compartment flooded with seawater, allowing for passive cooling even in the event of an accident. Illustration courtesy of Jake Jurewicz/MIT-NSE
The concept is being presented this week at the Small Modular Reactors Symposium, hosted by the American Society of Mechanical Engineers, by MIT professors Jacopo Buongiorno, Michael Golay, and Neil Todreas, along with others from MIT, the University of Wisconsin, and Chicago Bridge and Iron, a major nuclear plant and offshore platform construction company.
Such plants, Buongiorno explains, could be built in a shipyard, then towed to their destinations five to seven miles offshore, where they would be moored to the seafloor and connected to land by an underwater electric transmission line. The concept takes advantage of two mature technologies: light-water nuclear reactors and offshore oil and gas drilling platforms. Using established designs minimizes technological risks, says Buongiorno, an associate professor of nuclear science and engineering (NSE) at MIT.
Although the concept of a floating nuclear plant is not unique — Russia is in the process of building one now, on a barge moored at the shore — none have been located far enough offshore to be able to ride out a tsunami, Buongiorno says. For this new design, he says, “the biggest selling point is the enhanced safety.”
A floating platform several miles offshore, moored in about 100 meters of water, would be unaffected by the motions of a tsunami; earthquakes would have no direct effect at all. Meanwhile, the biggest issue that faces most nuclear plants under emergency conditions — overheating and potential meltdown, as happened at Fukushima, Chernobyl, and Three Mile Island — would be virtually impossible at sea, Buongiorno says: “It’s very close to the ocean, which is essentially an infinite heat sink, so it’s possible to do cooling passively, with no intervention. The reactor containment itself is essentially underwater.”
Buongiorno lists several other advantages. For one thing, it is increasingly difficult and expensive to find suitable sites for new nuclear plants: They usually need to be next to an ocean, lake, or river to provide cooling water, but shorefront properties are highly desirable. By contrast, sites offshore, but out of sight of land, could be located adjacent to the population centers they would serve. “The ocean is inexpensive real estate,” Buongiorno says.
In addition, at the end of a plant’s lifetime, “decommissioning” could be accomplished by simply towing it away to a central facility, as is done now for the Navy’s carrier and submarine reactors. That would rapidly restore the site to pristine conditions.
This design could also help to address practical construction issues that have tended to make new nuclear plants uneconomical: Shipyard construction allows for better standardization, and the all-steel design eliminates the use of concrete, which Buongiorno says is often responsible for construction delays and cost overruns.
There are no particular limits to the size of such plants, he says: They could be anywhere from small, 50-megawatt plants to 1,000-megawatt plants matching today’s largest facilities. “It’s a flexible concept,” Buongiorno says.
Most operations would be similar to those of onshore plants, and the plant would be designed to meet all regulatory security requirements for terrestrial plants. “Project work has confirmed the feasibility of achieving this goal, including satisfaction of the extra concern of protection against underwater attack,” says Todreas, the KEPCO Professor of Nuclear Science and Engineering and Mechanical Engineering.
Buongiorno sees a market for such plants in Asia, which has a combination of high tsunami risks and a rapidly growing need for new power sources. “It would make a lot of sense for Japan,” he says, as well as places such as Indonesia, Chile, and Africa.
This is a “very attractive and promising proposal,” says Toru Obara, a professor at the Research Laboratory for Nuclear Reactors at the Tokyo Institute of Technology who was not involved in this research. “I think this is technically very feasible. ... Of course, further study is needed to realize the concept, but the authors have the answers to each question and the answers are realistic.”
The paper was co-authored by NSE students Angelo Briccetti, Jake Jurewicz, and Vincent Kindfuller; Michael Corradini of the University of Wisconsin; and Daniel Fadel, Ganesh Srinivasan, Ryan Hannink, and Alan Crowle of Chicago Bridge and Iron, based in Canton, Mass.
Since the earthquake and subsequent tsunami that caused the catastrophic meltdown of the Fukushima Daiichi nuclear power plant in March 2011, Japan’s nuclear energy capacity has faced an uncertain future. The government has faced a significant cleaning up operation in the wake of the worst nuclear accident since Chernobyl. But their troubles do not stop there, as the costs of shutting down Japan’s 48 reactor plants for safety checks and inspections begin to mount up. Japan has been nuclear-free since September 2013.
The operators of these idled plants have been forced to spend approximately $87bn on burning fossil fuels to make up for the energy shortfall, driving costs higher. As a result, they have seen $60bn wiped from their combined stock values, and the nine publicly traded nuclear operators together lost an estimated sum in the region of $50billion in the two business years since Fukushima. The ramifications of these gargantuan losses have been keenly felt. Kyushu Electric Power Co has sought a $1bn bailout from the government, alongside Hokkaido Electric Power Co which is also seeking financial backing to get them out of their difficulties.
Nuclear power however remains unpopular with the general public after the disaster at the Fukushima plant, and the struggles of Tokyo Electric Power Co in trying to deal with it. 69% of respondents to a poll in the Tokyo Shimbun said they felt that nuclear power should be entirely phased out and an Asahi newspaper poll last month found that nearly 80 percent of those surveyed supported a gradual exit from atomic power.
Regardless of these concerns, the Japanese Cabinet approved an energy policy that reverses the previous government’s plans to gradually decommission the country’s 48 nuclear power plants, which are currently idling pending rigorous safety inspections.
The country is seeking to move away from over-reliance on nuclear power (before the Fukushima disaster, nuclear power accounted for nearly one third of Japan’s electricity) but is adamant that once reactors can be verified as being safe, they will be restarted. The new energy policy seeks to increase the amount of clean energy used by Japan ahead of old targets, but also names coal as being an important pillar of Japan’s energy strategy. That said, it was also stated that while coal is economical, with a steady and stable supply, the large amounts of greenhouse gases it emits are a concern. Thus there are also plans to push through technological developments that will be aimed at drastically reducing these emissions through efficiency gains.
But returning to the question of nuclear power once again, a Reuters analysis suggested that of the 48 currently idled reactors, 17 are unlikely to be restarted, and as many as 34 may have to be mothballed due to the high costs of necessary safety upgrades, seismic risks or general local opposition. Therefore, if these figures are to be believed, the major Japanese utility firms face major decommissioning costs if their plants do not pass the strict new safety standards when they are eventually inspected.
The new energy plan defines nuclear power as “an important base-load power source” but the overall role of nuclear power in the Japanese energy mix was not defined. There is a commitment to go beyond existing targets for renewable energy usage, but no concrete numbers were given. What is clear is that Prime Minister Shinzo Abe is enacting a policy that is likely to prove unpopular in order to secure the ailing atomic industry. But it may still be too late to save the ailing atomic industry in Japan, with Mycle Schneider, a Paris-based independent energy consultant saying: “I think it is unavoidable that the Japanese utilities will write off most of their nuclear 'assets' and move on.”
Japan faces major difficulties with regards to its energy requirements in the post-Fukushima landscape, with gargantuan costs faced by the major energy companies, as well as the burden placed on the government and other creditors as these companies desperately try to stay solvent. While the re-activation of several plants is likely to alleviate these problems somewhat, it is clear that many will never be turned on again. Japan needs to reduce its dependency on nuclear power, a move that is supported by the general public, but it also needs to ensure that it can guarantee a stable energy supply going forward, and attempt to mitigate the huge losses already caused by the “nuclear problem” so far. The latest energy policy seeks to strike a balance between these aims, but it remains to be seen whether they will be successful.