Electricity News in June 2017
Russia Develops Cyber Weapon That Can Disrupt Power Grids
CrashOverride malware is a Russian-linked ICS cyberweapon targeting power grids, SCADA systems, and utility networks; linked to Electrum/Sandworm, it threatens U.S. transmission and distribution with modular attacks and time-bomb payloads across critical infrastructure.
Key Points
A modular ICS malware linked to Russian actors that disrupts power grids via SCADA abuse and forced breaker outages.
✅ Targets breakers and substation devices to sustain outages
✅ Modular payloads adapt to ICS protocols and vendors
✅ Enables timed, multi-site attacks against transmission and distribution
Hackers allied with the Russian government have devised a cyberweapon that has the potential to be the most disruptive yet against electric systems that Americans depend on for daily life, according to U.S. researchers.
The malware, which researchers have dubbed CrashOverride, is known to have disrupted only one energy system — in Ukraine in December. In that incident, the hackers briefly shut down one-fifth of the electric power generated in Kiev.
But with modifications, it could be deployed against U.S. electric transmission and distribution systems to devastating effect, said Sergio Caltagirone, director of threat intelligence for Dragos, a cybersecurity firm that studied the malware and issued a recent report.
And Russian government hackers have shown their interest in targeting U.S. energy and other utility systems, with reports of suspected breaches at U.S. power plants in recent years, researchers said.
“It’s the culmination of over a decade of theory and attack scenarios,” Caltagirone warned. “It’s a game changer.”
The revelation comes as the U.S. government is investigating a wide-ranging, ambitious effort by the Russian government last year to disrupt the U.S. presidential election and influence its outcome, and has issued a condemnation of Russian power grid hacking as well. That campaign employed a variety of methods, including hacking hundreds of political and other organizations, and leveraging social media, U.S. officials said.
Dragos has named the group that created the new malware Electrum, and it has determined with high confidence that Electrum used the same computer systems as the hackers who attacked the Ukraine electric grid in 2015. That attack, which left 225,000 customers without power, was carried out by Russian government hackers, other U.S. researchers concluded. U.S. government officials have not officially attributed that attack to the Russian government, but some privately say they concur with the private-sector analysis.
“The same Russian group that targeted U.S. [industrial control] systems in 2014, including the Dragonfly campaign documented by Symantec, turned out the lights in Ukraine in 2015,” said John Hultquist, who analyzed both incidents while at iSight Partners, a cyber-intelligence firm now owned by FireEye, where he is director of intelligence analysis. Hultquist’s team had dubbed the group Sandworm.
“We believe that Sandworm is tied in some way to the Russian government — whether they’re contractors or actual government officials, we’re not sure,” he said. “We believe they are linked to the security services.”
Sandworm and Electrum may be the same group or two separate groups working within the same organization, but the forensic evidence shows they are related, said Robert M. Lee, chief executive of Dragos.
The Department of Homeland Security, which works with the owners of the nation’s critical infrastructure systems, did not respond to a request for comment Sunday.
Energy-sector experts said that the new malware is cause for concern, but that the industry is seeking to develop ways to disrupt attackers who breach their systems, including documented access to U.S. utility control rooms in prior incidents.
“U.S. utilities have been enhancing their cybersecurity, but attacker tools like this one pose a very real risk to reliable operation of power systems,” said Michael J. Assante, who worked at Idaho National Labs and is a former chief security officer of the North American Electric Reliability Corporation, where he oversaw the rollout of industry cybersecurity standards.
CrashOverride is only the second instance of malware specifically tailored to disrupt or destroy industrial control systems. Stuxnet, the worm created by the United States and Israel to disrupt Iran’s nuclear capability, was an advanced military-grade weapon designed to affect centrifuges that enrich uranium.
In 2015, the Russians used malware to gain access to the power supply network in western Ukraine, but it was hackers at the keyboards who remotely manipulated the control systems to cause the blackout — not the malware itself, Hultquist said.
With CrashOverride, “what is particularly alarming . . . is that it is all part of a larger framework,” said Dan Gunter, a senior threat hunter for Dragos.
The malware is like a Swiss Army knife, where you flip open the tool you need and where different tools can be added to achieve different effects, Gunter said.
Theoretically, the malware can be modified to attack different types of industrial control systems, such as water and gas. However, the adversary has not demonstrated that level of sophistication, Lee said.
Still, the attackers probably had experts and resources available not only to develop the framework but also to test it, Gunter said. “This speaks to a larger effort often associated with nation-state or highly funded team operations.”
One of the most insidious tools in CrashOverride manipulates the settings on electric power control systems. It scans for critical components that operate circuit breakers and opens the circuit breakers, which stops the flow of electricity. It continues to keep them open even if a grid operator tries to close them, creating a sustained power outage.
The malware also has a “wiper” component that erases the software on the computer system that controls the circuit breakers, forcing the grid operator to revert to manual operations, which means driving to the substation to restore power.
With this malware, the attacker can target multiple locations with a “time bomb” functionality and set the malware to trigger simultaneously, Lee said. That could create outages in different areas at the same time.
The outages would last a few hours and probably not more than a couple of days, Lee said. That is because the U.S. electric industry has trained its operators to handle disruptions caused by large storms, alongside a renewed focus on protecting the grid in response to recent alerts. “They’re used to having to restore power with manual operations,” he said.
So although the malware is “a significant leap forward in tradecraft, it’s also not a doomsday scenario,” he said.
The malware samples were first obtained by ESET, a Slovakian research firm, which shared some of them with Dragos. ESET has dubbed the malware Industroyer.
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Clean energy stored in electric vehicles to power buildings
Vehicle-to-Grid (V2G) enables bidirectional charging, letting EV batteries supply smart grid services to large buildings, support renewable energy integration, reduce battery degradation, and optimize demand response for efficient, resilient power management.
Key Points
Vehicle-to-Grid (V2G) is bidirectional EV charging that feeds the grid and buildings while protecting battery health.
✅ Uses idle EVs to power buildings and support renewables
✅ Smart algorithms minimize lithium-ion battery degradation
✅ Provides grid services, demand response, and peak shaving
Stored energy from electric vehicles (EVs) can be used to power large buildings -- creating new possibilities for the future of smart, renewable energy -- thanks to ground-breaking battery research from WMG at the University of Warwick.
Dr Kotub Uddin, with colleagues from WMG's Energy and Electrical Systems group and Jaguar Land Rover, has demonstrated that vehicle-to-grid (V2G) technology can be intelligently utilised to take enough energy from idle EV batteries to be pumped into the grid and power buildings -- without damaging the batteries.
This new research into the potentials of V2G shows that it could actually improve vehicle battery life by around ten percent over a year.
For two years, Dr Uddin's team analysed some of the world's most advanced lithium ion batteries used in commercially available EVs -- and created one of the most accurate battery degradation models existing in the public domain -- to predict battery capacity and power fade over time, under various ageing acceleration factors -- including temperature, state of charge, current and depth of discharge.
Using this validated degradation model, Dr Uddin developed a 'smart grid' algorithm, which supports grid coordination and intelligently calculates how much energy a vehicle requires to carry out daily journeys, and -- crucially -- how much energy can be taken from its battery without negatively affecting it, or even improving its longevity.
The researchers used their 'smart grid' algorithm to see if they could power WMG's International Digital Laboratory -- a large, busy building which contains a 100-seater auditorium, two electrical laboratories, teaching laboratories, meeting rooms, and houses approximately 360 staff -- with vehicle-to-building charging from EVs parked on the University of Warwick campus.
They worked out that the number of EVs parked on the campus (around 2.1% of cars, in line with the UK market share of EVs) could spare the energy to power this building, acting as capacity on wheels for electricity networks -- and that in doing so, capacity fade in participant EV batteries would be reduced by up to 9.1%, and power fade by up to 12.1% over a year.
It has previously been thought that extracting energy from EVs with V2G technology causes their lithium ion batteries to degrade more rapidly.
Dr Uddin's group (along with collaborators from Jaguar Land Rover) have proved, however, that battery degradation is more complex -- and this complexity, in operation, can be exploited to improve a battery's lifetime.
Given that battery degradation is dependent on calendar age, capacity throughput, temperature, state of charge, current and depth of discharge, V2G is an effective tool that can be used to optimise a battery's conditions such that degradation is minimised. Hence, taking excess energy from an idle EV to power the grid actually keeps the battery healthier for longer.
Dr Uddin commented on the research:
"These findings reinforce the attractiveness of vehicle-to-grid technologies to automotive Original Equipment Manufacturers: not only is vehicle-to-grid an effective solution for grid support -- and subsequently a tidy revenue stream -- but we have shown that there is a real possibility of extending the lifetime of traction batteries in tandem.
"The results are also appealing to policy makers interested in grid decarbonisation and addressing grid challenges from rising EVs across power systems."
The research, 'On the possibility of extending the lifetime of lithium-ion batteries through optimal V2G facilitated by an integrated vehicle and smart-grid system' is published in Energy.
It was funded by the Engineering and Physical Sciences Research Council and the WMG centre High Value Manufacturing Catapult, in partnership with Jaguar Land Rover.
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As Trump ditches Paris, California is one step closer to getting wind power from Wyoming
TransWest Express Power Line will deliver Wyoming wind energy to California via a 730-mile high-voltage corridor, integrating 3,000 MW from the Chokecherry and Sierra Madre project to strengthen the Western grid and decarbonization goals.
Key Points
A 730-mile line delivering up to 3,000 MW of Wyoming wind to Western states, improving clean energy reliability.
✅ 3,000 MW from Chokecherry and Sierra Madre turbines
✅ 730-mile route linking Wyoming to CA, AZ, NV markets
✅ Supports 60% by 2030, 100% by 2045 clean mandates
A conservative billionaire wants to build America's biggest wind farm in Wyoming and send the clean electricity to California.
Federal officials have approved another section of the 730-mile TransWest Express power line, in line with a renewable transmission rule aimed at speeding upgrades, which would carry energy from Philip Anschutz's Chokecherry and Sierra Madre wind farm to potential customers in California, Arizona and Nevada. The 1,000-turbine, 3,000-megawatt wind project, which has been in the works for a decade, would be built in south-central Wyoming, in one of the windiest spots in the continental U.S.
Supporters say the massive power project would help California meet its clean energy goals, in part because Wyoming winds tend to blow strong into the evening, as the sun sets over the Pacific and the Golden State's many solar farms go offline, though expanding battery storage is starting to fill that gap. Under California law, electric utilities are required to get 50% of their power from renewable sources by 2030. The state Senate passed a bill Wednesday that would raise the clean energy mandate to 60% by 2030 and 100% by 2045.
The Denver-based Anschutz Corporation hasn't inked any contracts to sell the electricity its Wyoming wind farm would generate. But company officials are confident demand will materialize by the time they're ready to build turbines. Construction of roads and other project infrastructure started last year and picked back up in April after a winter hiatus.
The developer has already spent $100 million developing the wind farm and power line, and expects to spend a combined $8 billion on the two projects.
Bill Miller oversees the development of the Anschutz Corporation's Chokecherry and Sierra Madre wind farm in Wyoming, which would send as much as 3,000 megawatts of wind power to California. (Photo: Jay Calderon/The Desert Sun)
After an extensive environmental review, the U.S. Forest Service issued a permit Wednesday for portions of the TransWest Express transmission line that would cross through 19 miles of the Uinta-Wasatch-Cache and Manti-La Sal national forests in Utah.
"It's another step forward in the process of making this line a reality, and being able to provide a path that allows California, Arizona and Nevada to access the high volumes of renewable energy supplies that are available in Wyoming," said Kara Choquette, a spokesperson for the Anschutz subsidiaries developing the power project.
Between the Forest Service approval and a Bureau of Land Management permit issued in December, the developer now has the go-ahead to build about two-thirds of the 730-mile route, Choquette said, progress that comes as the U.S. grid overhaul for renewables accelerates nationwide. Company officials are reaching out to the roughly 450 private landowners along the proposed route. They must also apply for a state permit in Wyoming, and 14 county-level permits in Wyoming, Colorado, Utah and Nevada.
But Anschutz's Chokecherry and Sierra Madre wind farm is a reminder that Trump can't stop the ongoing transition from coal to cleaner sources of energy, which is being driven largely by market forces. Solar, wind and natural gas, which burns more cleanly than coal, are now the cheapest sources of new electricity across much of the country, even as Texas grid constraints sometimes force High Plains turbines to shut down during oversupply. Utility industry executives are abandoning coal and embracing renewable energy. And the American solar industry employs more people than coal or natural gas.
States and local governments in California, New York and elsewhere have also forged ahead with policies to reduce climate emissions, including New York's largest offshore wind project recently approved. So have major companies like Apple, Facebook and Google, which have invested billions of dollars in renewable energy.
"The (Trump) administration is so out of step with reality right now. The trend is powerful, whether it's coming the cities or corporations, or from the coastal states," said Don Furman, a former utility executive who now advocates for greater sharing of renewable energy across state lines in the West.
Turbines at Duke Energy's Happy Jack wind farm near Cheyenne, Wyoming generate electricity on Dec. 6, 2016. (Photo: Jay Calderon/The Desert Sun)
Clean energy advocates say the 3,000-megawatt Wyoming wind farm is an especially powerful example of the economic case for renewable energy, because its proprietor is Anschutz, a longtime fossil fuel magnate and major donor to Republican politicians.
"I don't think Philip Anschutz would be putting his money here if he thought this was a bad business bet," Furman said.
The Forest Service also issued a permit Wednesday for the 416-mile Energy Gateway South power line, which would run through Wyoming, Colorado and Utah, traversing nine miles of the same national forests TransWest Express would cross. Gateway South is part of the 1,900-mile Energy Gateway transmission project being developed by Warren Buffett's PacifiCorp utility, which serves customers across six western states.
PacifiCorp officials say the $6 billion transmission project is needed to meet growing electricity demand. They've also pitched the power lines as another opportunity to transmit wind power from Wyoming to California and other coastal states. Critics, though, see Energy Gateway as costly and unnecessary — and they're worried Californians would end up paying the price through higher electricity rates.
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Coal comeback unlikely after Paris climate pact withdrawal, says utility CEO
US Shift From Coal to Renewables accelerates as natural gas, solar, and wind power gain market share, driven by the Paris climate agreement, clean energy mandates, smart grid upgrades, and energy efficiency.
Key Points
An industry trend where power producers replace coal with natural gas, solar, and wind to meet clean energy goals.
✅ Shareholders and customers demand cleaner power portfolios
✅ Natural gas, solar, and wind outcompete coal on cost and risk
✅ Smart grid and efficiency investments reduce emissions further
President Trump once again promised to revive the U.S. coal industry when he announced his intention to withdraw the U.S. from the Paris climate agreement.
But that reversal seems as unlikely as ever as electric power producers, the biggest consumers of coal in the U.S., continue to shift to natural gas and renewable energy sources like solar and wind power. In 2016, natural gas became the leading fuel for U.S. electricity generation for the first time, responsible for 33.8% of the output, compared with 30.4% for coal, according to the U.S. Energy Information Administration, even as coal-fired generation was projected to rise in 2021 in the short term.
Nick Akins, the CEO of American Electric Power, one of the largest utilities in the U.S., says the preference for gas, renewables and energy efficiency, will only grow in response to increasing demands from shareholders and customers for cleaner energy, regardless of changes in national energy policy.
With 5.4 million customers in 11 states, AEP plans to spend $1.5 billion on renewable energy from 2017 through 2019, and $13 billion on transmission and distribution improvements, including new “smart” technologies that will make the grid more resilient and efficient, AEP says.
We spoke with Akins on Thursday, just after Trump’s announcement. The transcript is edited for length and clarity.
What do you think of Trump’s decision to pull the U.S. from the climate agreement?
I don’t think it’s unexpected. He obviously made the point that he’s willing to renegotiate or have further dialogue about it. That’s a good sign. From our perspective, we’re going to continue along the path we’re already on toward a cleaner energy economy.
AEP and the U.S. electric power industry in general have been moving away from coal in favor of natural gas and renewable energy. Will this decision by the Trump administration have any impact on that trend?
If you look at our resource plans in all of the states we serve, they are focused on renewables, natural gas and transmission, as declining returns from coal generation pressure investment choices across the industry. And big-data analytics improves the efficiency of the grid, so energy efficiency is obviously a key component, as Americans use less electricity overall.
Our carbon dioxide emissions in 2016 were 44% below 2000 levels, and that progress will continue with the additions of more renewables, energy efficiency and natural gas.
So, you don’t see coal making a comeback at AEP or other utilities?
No, I don’t think so. … You wouldn’t make a decision (to build a coal power plant) at this point because it’s heavily capital-intensive, and involves a longer-term process and risk to build. And, of course, you can add renewables that are very efficient and natural gas that’s efficient and much less expensive and risky, in terms of construction and operation.
Do you plan to close any more coal-powered plants soon?
I suspect we’ll see some more retirements in the future, with coal and nuclear closures test just transition in many communities, and as we progress towards that cleaner energy economy, and consider the expectations of our customers and shareholders for us to mitigate risk, you’ll continue to see that happen.
But on the other hand, I want to make sure there’s an understanding that coal will remain a part of the portfolio, even though in rare cases new coal plants are still being built where options are limited, but it will be of a lesser degree because of these other resources that are available to us now that weren’t available to us just a few years ago.
Do you find yourself under more or less pressure from customers and shareholders to move to cleaner forms of energy?
I think there’s more pressure. Investors are looking for the sustainability of the company going forward and mitigation of risks … From a customer standpoint, we have some large customers interested in moving into our service territory who are looking for cleaner energy, and want to know if we’re focused on that. Some of them want to be supplied entirely by those clean sources. So, we’re clearly responding to our customers’ and our shareholders’ expectations.
What’s the solution for workers at coal mines and coal power plants who have lost their jobs?
Certainly, the skill sets of employees in mining and around machinery are transferable to other areas of manufacturing, like aerospace and defense. So, we’re really focusing on economic-development efforts in our service territories … particularly in the coal states … to bring coal miners back to work, not necessarily in coal mines but certainly (in manufacturing).
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Mississippi power plant costs cross $7.5B
Kemper County power plant costs and delays highlight lignite coal gasification, syngas production, carbon capture targets, and looming rate plans as Mississippi Power navigates Public Service Commission oversight and shareholder-ratepayer risk.
Key Points
Costs exceed $7.5B with repeated delays; rate impacts loom as syngas, lignite, and carbon capture systems mature.
✅ Estimate tops $7.5B; customers could fund about $4.3B
✅ Carbon capture target: 65% CO2 via syngas from lignite
✅ Rate plans pending before the Public Service Commission
A Mississippi utility on Monday delayed making proposals for how its customers should pay for an ever-more-expensive power plant, even as the estimated cost of the facility crossed $7.5 billion.
The Kemper County power plant will be tasked with mining lignite coal a few hundred yards away from the plant. That coal is moved through a process that will convert it to syngas. The syngas is then used to drive the energy output of the plant, and the resulting electricity is then moved into the grid, where transmission projects influence regional reliability and capacity.
Thomas Fanning, CEO of parent Southern Co., told shareholders in May that Mississippi Power would file rate plans for its Kemper County power plant this month. But still unable to operate the plant steadily enough to declare it finished, Mississippi Power punted, instead asking to hold rates level for 11 months to pay off costs that have already been approved by regulators.
Mississippi Power says it now hopes to reach commercial operation in June. The plant is more than three years behind schedule, with 10 delays announced in the past 18 months. It was originally supposed to cost $2.9 billion.
The company also said monday that it will have to replace troublesome parts of the facility much sooner than expected, including units that cool the synthetic gas produced from soft lignite coal by two gasifier units, plus ash handling systems in the gasifiers.
Kemper is designed to take synthetic gas, pipe it through a chemical plant to remove carbon dioxide and other chemicals, and then burn the gas in turbines to generate electricity. It’s designed to capture 65 percent of carbon dioxide from the coal, releasing only as much of the climate-warming gas as a typical natural gas plant. It’s a key effort nationally to maintain coal as a viable fuel source, even as coal unit retirements proceed in other states.
Mississippi Power raised its estimate of Kemper’s cost by $209.4 million, with shareholders absorbing $185.9 million, while ratepayers could be asked to pay $23.5 million. Overall, customers could be asked to pay $4.3 billion. Southern shareholders have agreed to absorb $3.1 billion, which has risen by $500 million since November.
The elected three-member Public Service Commission in 2015 allowed the company to raise rates on its 188,000 customers by $126 million a year. That paid for $840 million in Kemper work, which began generating electricity in 2014 using piped-in natural gas. Some items covered by that 15 percent rate increase will be paid off in coming months, but Mississippi Power now proposes to repay costs from regulatory proceedings earlier than originally projected.
In testimony filed with the Public Service Commission, Mississippi Power Chief Financial Officer Moses Fagin said that keeping rates level would reduce whiplash to customers when rates rise later to pay for Kemper, would pay off accumulated costs more quickly and would help the company wean itself off financial support from Southern Co. while maintaining credit ratings and positioning for a possible bond rating upgrade over time.
“Cash flow is important to the company in maintaining its current ratings and beginning to rebuild its credit strength on a more independent basis apart from the extraordinary parental support that has been required in recent years to maintain financial integrity,” Fagin testified.
Spokesman Jeff Shepard said Mississippi Power is still drawing up two rate plans — one requiring a sharp, immediate rate increase, and a “rate mitigation plan” that might cushion increases amid declining returns in coal markets. He said the company isn’t sure when it will file them. Fagin suggested the Public Service Commission set a new deadline of March 2, 2018.
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Seasonal power rates could cause consumer backlash
NB Power seasonal electricity rates face backlash amid smart grid delays, meter reading limits, and billing dispute risks, as consultants recommend AMI smart meters for accurate winter-summer pricing, time-of-use alignment, and consumer protection.
Key Points
NB Power seasonal electricity rates raise winter prices and lower summer prices to match costs, using accurate AMI metering.
✅ Requires midnight meter reads without AMI, increasing billing disputes.
✅ Shifts costs to electric-heat homes during high winter demand.
✅ Recommended to wait for smart grid AMI for time-of-use accuracy.
A consultant hired by NB Power is warning of significant consumer "backlash" if the utility is made to establish seasonal rates for electricity, as seen in B.C. and Quebec smart meter disputes among customers.
The consultant's report even suggests customers might have to read their own power meters at midnight twice a year — on April Fool's and Halloween — to make the system work.
"Virtually all bills will have errors ... billing disputes can be expected to increase, as seen in a $666 smart meter bill in N.S. that raised concerns, possibly dramatically, and there will be no means of resolving disputes in a satisfactory way," reads a report by Elenchus Research Associates that was commissioned by NB Power and filed with the Energy and Utilities Board on Thursday.
NB Power is in the middle of a year-long "rate design" review ordered by the EUB that is focused in part on whether the utility should charge lower prices for electricity in the summer and higher prices in the winter to better reflect the actual cost of serving customers.
New network of meters needed
Elenchus was asked to study how that might work but the company is arguing against any switch until NB Power upgrades its entire network of power meters, given old meters in N.B. have raised concerns.
Elenchus said seasonal rates require an accurate reading of every customer's power meter at midnight on March 31 and again on Oct. 31, the dates when power rates would switch between winter and summer prices.
A consultant's report says NB Power doesn't have the manpower to properly read meters if it brings in seasonal rates. (CBC)
But NB Power does not have the sophisticated infrastructure in place to read meters remotely, or the manpower to visit every customer location on the same day, so Elenchus said the utility would have to guesstimate bills or rely on the technical savvy and honesty of customers themselves.
"Customers could be asked to read their own meters late in the day on March 31 (and October 31)," suggested the report. "Aside from the obvious inconvenience and impracticality of that approach, NB Power would have no means of verifying the customers' meter reads."
Residential customers would see hike
Another looming controversy with seasonal rates is that it would raise costs for residential customers, especially to those who heat with electricity, a pressure seen with a 14% rate increase in Nova Scotia recently.
Elenchus estimated seasonal rates would add nearly $6 million to the cost of residential bills overall, with the largest increases flowing to those with baseboard heat.
Electric heat customers consume the majority of their power during the five months that would have the highest prices and Elenchus said that is another reason to wait for better power meters before proceeding.
NB Power has an ambitious plan to bring in a new meter system, and the consultant's report recommends waiting for that to happen before switching to seasonal rates. (Google Street View)
NB Power has an ambitious plan to upgrade meters and related infrastructure as part of its transformation to a "smart grid," but it is a multi-year plan.
Once in place the utility would be able to read meters remotely hour to hour, allowing power rates to be adjusted for times of the day and days of the week as well as seasonally.
Consumers will also have in-home pricing and consumption displays to help them manage their bills.
Elenchus said waiting for those meters will give electric heat customers a chance to avoid higher seasonal costs by letting them shift power consumption to lower-priced parts of the day.
"The introduction of seasonal rates would be more acceptable once AMI (advanced metering infrastructure) has been deployed," concludes the report.
A final hearing on NB Power's rate design, where seasonal rates and other changes will be considered, amid a power market overhaul debate in Alberta that industry is watching, is scheduled for next April.
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Unilorin develops device to check electricity theft
Ilorin Electricity Theft Device delivers remote monitoring and IoT-based detection for smart meters, identifying bypassed prepaid meters, triggering disconnects, and alerting the utility control room to curb distribution losses and energy theft.
Key Points
A prototype IoT system that detects electricity theft, enables remote disconnection, and alerts utility control rooms.
✅ Remote monitoring flags bypassed prepaid meters.
✅ Sends alerts to utility control room with customer details.
✅ Enables safe remote cut-off to reduce distribution losses.
The Department of Electrical and Electronics Engineering, University of Ilorin, has unveiled a prototype anti-theft device capable of remotely monitoring and detecting customers stealing electricity.
The Acting Head of the Department, Dr Mudathir Akorede told newsmen on Tuesday in Ilorin that the device could also cut off electricity supply to the premises of customers stealing electricity.
”This will simultaneously send a message to the utility control room, and in light of rising ransomware attacks targeting power systems, to alert the system operator with such customer’s details displayed on the control panel,” he said.
Akorede said that processes of filing application for patenting the invention, in line with emerging IoT security standards for the electricity sector, had commenced through the university’s Laboratory to Product Centre.
The don explained that the device was developed by himself and some students of the Department, reflecting how university teams contribute to innovations like generating electricity from falling snow in the field.
Akorede said, “I gave the project to my undergraduate students; they carried out the project to a level and I took it over and brought it to a level that was up to standard.”
The Don further said,”The invention is now up to the standard that it can be patented.
“I have brought this to the attention of the Ibadan Electricity Distribution Company, although not officially, but if adopted, and as utilities pursue digitizing the grid strategies, the device would enable distribution companies to cut their commercial losses substantially.”
He said that the idea followed the discovery that most people use electricity without paying for it.
”A lot of people that have been able to get the prepaid meter, even though they can afford to pay their bills, still want to bypass this thing to steal electricity and this is not helping the companies.
“It is not helping all of us as a whole. If the industry should collapse, with emerging cyber weapons that can disrupt power grids underscoring systemic risks, everybody would bear the brunt of that problem and that is why the consumers too have to share out of the problem
“But this is not to say that distribution companies also do not have their share of the blame by not wanting to take on responsibilities such as faulty transformers.”
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Australia electricity market: Plan to avoid threats to electricity supply
National Electricity Market review calls for clear coal-fired closure schedules to safeguard energy security, backing a technology-agnostic clean energy and low emissions target with tradeable certificates to stabilise prices and support a smoother transition.
Key Points
A review proposing orderly coal closures and a technology-agnostic clean energy target to protect grid reliability.
✅ Mandates advance notice of coal plant closure schedules
✅ Supports clean energy and low emissions target with certificates
✅ Aims to stabilise prices and ensure system security
THE Latrobe Valley’s coal-fired power stations could be forced to give details of planned closures well in advance to help governments avoid major threats to electricity supply, amid an AEMO warning on reduced reserves across the grid.
The much-anticipated review of the national electricity market, to be released on Friday, will outline the need for clear schedules for the closure of coal-fired power stations to avoid rushed decisions on energy security.
It is believed the Turnbull government, which has ruled out taxpayer-funded power plants in the current energy debate, will move toward either a clean-energy or a low-emissions target that aims to bolster power security while reducing household bills and emissions.
The system, believed to be also favoured by industry, would likely provide a more stable transition to clean energy by engaging with the just transition concept seen in other markets, because coal-fired power would not be driven out of the market as quickly.
Sources said that would lead to greater investment in the energy sector, a surplus of production and, as seen in Alberta's shift to gas and price cap debate driving market changes, a cut in prices.
It is likely most coal-fired power stations, such as Yallourn and Loy Yang in the Latrobe Valley, would see out their “natural lives” under the government’s favoured system, rather than be forced out of business by an EIS.
The new target would be separate from the Renewable Energy Target which have come under fire because of ad hoc federal and state targets.
The Herald Sun has been told the policy would provide tradeable clean-energy certificates for low-emissions generation, such as wind, solar and gas and coal which used carbon capture and storage technology.
Energy retailers and large industrial users would then be required to source a mandated amount of certified clean power.
Federal Energy Minister Josh Frydenberg has repeatedly said any solution must be “technology agnostic” including gas, renewable energy and coal, amid ongoing debates over whether to save or close nuclear plants such as the Three Mile Island debate in other markets.
Energy Networks Australia’s submission to the review, chaired by Chief Scientist Alan Finkel, acknowledged the challenges in identifying potential generation closures, particularly with uncertain and poorly integrated state and national carbon policy settings.
The group said given the likelihood of further closures of coal fired generation units a new mechanism was needed to better manage changes in the generation mix, well in advance of the closure of the plant.
It said the implications for system stability were “too significant” to rely on the past short-term closures, such as Hazelwood, particularly when the amount of power generated could drive energy security to “tipping point”.
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Premier warns NDP, Greens that delaying Site C dam could cost $600M
Site C Project Delay raises BC Hydro costs as Christy Clark warns $600 million impact; NDP and Greens seek BCUC review of the hydroelectric dam on the Peace River, challenging evictions and construction contracts.
Key Points
A potential slowdown of B.C.'s Site C dam, risking $600M overruns, evictions, and schedule delays pending a BCUC review.
✅ Clark warns $600M cost if river diversion slips a year
✅ NDP-Green seek BCUC review; request to pause contracts, evictions
✅ Peace River hydro dam; schedule critical to budget, ratepayers
Premier Christy Clark is warning the NDP and Greens that delaying work on the Site C project in northeast British Columbia could cost taxpayers $600 million.
NDP Leader John Horgan wrote to BC Hydro last week asking it to suspend the evictions of two homeowners and urging it not to sign any new contracts on the $8.6-billion hydroelectric dam until a new government has gained the confidence of the legislature.
But Clark says in letters sent to Horgan and Green Leader Andrew Weaver on Tuesday that the evictions are necessary as part of a road and bridge construction project that are needed to divert a river in September 2019.
Any delay could postpone the diversion by a year and cost taxpayers hundreds of millions of dollars, she says.
“With a project of this size and scale, keeping to a tight schedule is critical to delivering a completed project on time and on budget,” she says. “The requests contained in your letter are not without consequences to the construction schedule and ultimately have financial ramifications to ratepayers.”
The premier has asked Horgan and Weaver to reply by Saturday on whether they still want to put the evictions on hold.
She also asks whether they want the government to issue a “tools down” request to BC Hydro on other decisions that she says are essential to maintaining the budget and construction schedule.
An agreement between the NDP and Green party was signed last week that would allow the New Democrats to form a minority government, ousting Clark's Liberals.
The agreement includes a promise to refer the Site C project to the B.C. Utilities Commission to determine its economic viability.
Some analysts argue that better B.C.-Alberta power integration could improve climate outcomes and market flexibility.
But Clark says the project is likely to progress past the “point of no return” before a review can be completed.
Clark did not define what she meant by “point of no return,” nor did she explain how she reached the $600-million figure. Her press secretary Stephen Smart referred questions to BC Hydro, which did not immediately respond.
During prolonged drought conditions, BC Hydro has had to adapt power generation across the province, affecting planning assumptions.
In a written response to Clark, Weaver says before he can comment on her assertions he requires access to supporting evidence, including signed contracts, the project schedule and potential alternative project timelines.
“Please let me express my disappointment in how your government is choosing to proceed with this project,” he says.
“Your government is turning a significant capital project that potentially poses massive economic risks to British Columbians into a political debate rather than one informed by evidence and supported by independent analysis.”
The dam will be the third on the Peace River, flooding an 83-kilometre stretch of valley, and local First Nations, landowners and farmers have fiercely opposed the project.
Construction began two years ago.
A report written by University of British Columbia researchers in April argued it wasn't too late to press pause on the project and that the electricity produced by Site C won't be fully required for nearly a decade after it's complete.
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Wynne defends 25% hydro rate cut:
Ontario Hydro Rate Cuts address soaring electricity prices, lowering hydro bills via refinancing, FAO-reviewed costs, and long-term infrastructure investment, balancing ratepayer relief with a projected $21 billion net expense over 30 years.
Key Points
Ontario electricity bill relief spreading infrastructure and green energy costs over 30 years via refinancing.
✅ 25% average bill cut; $156 to $123 per month
✅ FAO projects $21B net cost over 30 years
✅ Costs shifted to long-term debt, infrastructure, green energy
Premier Kathleen Wynne is making no apologies for the Liberals’ 25 per cent hydro rate cuts, legislation to lower electricity rates that a legislative watchdog warns will cost at least $21 billion over three decades.
In the wake of Financial Accountability Officer Stephen LeClair’s report on the “Fair Hydro Plan,” Wynne emphasized that Ontario electricity consumers demanded and deserved relief.
“You all read the newspaper, you listen to the radio and you watch television — you know the problems that families are having around the province paying for their electricity costs,” the premier told reporters Thursday in Timmins.
That’s why the government moved forward with a rate cut, with recent Hydro One reconnections underscoring the stakes, that will see the average household’s monthly hydro bill drop from $156 to $123 once it fully takes effect next month.
In a 15-page report released Wednesday, the financial accountability officer estimated the initiative would cost the province $45 billion over the next 29 years amid a cabinet warning on prices that electricity costs could soar, while saving ratepayers $24 billion for a next expense of $21 billion.
Both the Progressive Conservatives and the New Democrats oppose the Liberal rate cut, arguing that a deal with Quebec would not lower hydro bills.
But Wynne said the government has in effect renegotiated a mortgage so it will bankroll hydro infrastructure improvements over a longer time period, though some have urged the next government to scrap the Fair Hydro Plan and review options, in order to give customers a break now.
“We’re talking about a 30-year window here. It took at least 30 years, probably 40 years, to let the electricity system degrade to the stage that it had in 2003,” she said, noting “we were having blackouts and brownouts around the province” before her party took office that year.
“There were thousands of kilometres of line that needed to be rebuilt . . . that work hadn’t been done over those generations, so electricity costs were low over that period of time but the work wasn’t being done.”
When her predecessor Dalton McGuinty came to power in 2003, Wynne said Queen’s Park began spending billions on infrastructure improvements, including expensive subsidies for green energy, such as wind turbines and solar panels.
“There’s a lot of work that has been done since then. Literally thousands of kilometres of line have been rebuilt. The coal-fired plants have been shut down. The air is cleaner. There’s less pollution in the air. The system is reliable and renewable,” she said.
“So there’s a cost associated with that and what was happening was that was work that had to be done — and all of those costs were on the shoulders of people today.”
Wynne noted “this electricity grid is an asset that is going to be used for generations to come.”
“My grandchildren are going to benefit from this asset, so I think it’s fair that we spread the cost of that over that 30-year period,” she said.
“That’s how we made this decision.”
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How Hedge Funds May Be Undermining the Electric Car Boom
Cobalt Supply Chain for EV Batteries faces shortages as lithium-ion demand surges; Tesla gigafactories, ethical sourcing, Idaho cobalt mining, and DRC risks intensify pricing, logistics, and procurement challenges for manufacturers and investors.
Key Points
A network supplying cobalt for lithium-ion cathodes, strained by EV demand, ethical sourcing pressures, and DRC risk.
✅ EV growth outpaces cobalt supply, widening deficits
✅ DRC reliance drives ESG scrutiny and sourcing shifts
✅ Idaho projects and stockpiling reshape U.S. supply
A perfect storm is brewing in the 21st Century battery market.
More specifically, it's about what goes into those batteries - and it's not just lithium.
The other element that makes up 35 percent of the lithium-ion batteries mass produced at Tesla's Nevada gigafactory and at a dozen of other behemoths slated to come on line, is cobalt. And it's already in dramatically short supply. A part of the answer to the cobalt deficit is 100 percent American, and this little-known miner is sitting on a prime Idaho cobalt project that is one of only two that looks likely to come online in the U.S. and it's right in Tesla's backyard.
High-Energy Batteries Need More Cobalt Than Lithium
If you've been focusing your investment on lithium supplies lately you've been missing the even bigger story. EV batteries need about 200 grams of refined cobalt per kilowatt of battery capacity. Power walls need more than twice that. Between March 2016 and April 2017, the cost of the cobalt in that mix nearly tripled. But it isn't just the price that's got manufacturers worried. It's the shortage of availability. Keeping gigafactories stocked with enough cobalt to run at capacity is the challenge of the decade.
Tesla, now with a $50-billion market cap, launched a $5-billion battery gigafactory in Nevada in January. By the end of 2017, it will have doubled the entire global battery production capacity. By next year, it will be producing more batteries than the rest of the world combined.
It is estimated that Tesla's gigafactory alone will need anywhere between 7,000 and 17,500 tonnes of refined cobalt every year.
Tesla used to buy its finished battery cells from Panasonic, which in turn got its processed cathode powders from a Japanese company, Sumitomo was processing its own cobalt in the Philippines. However, that facility is already running at capacity and couldn't even begin to handle Tesla's gigafactory demand. In other words, Tesla's supply chain is no longer secure. And that's just Tesla.
The EV market is fifteen times larger than it was five years ago. The market has experienced a comppound annual growth rate of over 72 percent from 2011-2016, with new sources like Alberta's lithium-laced oil fields drawing investment alongside cobalt. This year, analysts expect it to gain another 25-26 percent. Last year, global EV production grew 41 percent, and sales are up more than 60 per cent year to year.
In addition,the Iron Creek project isn't a new exploration property. It has already seen major historic exploratory work, including 30,000 feet of diamond drilling. Iron Creek has historic (non 43-101 compliant) indications of 1.3 million tons grading 0.59 percent of cobalt with encouraging indications of up to 10 million tons. The 'closeology' is also brilliant. It's right next to the only advanced cobalt project in the U.S., which has a resource of 3 million-plus tonnes of cobalt.
As the battery market hits fever pitch and the supply-chain bottlenecks become unbearable, homegrown exploration is the key-first-movers and first investors will be the biggest beneficiaries.
A Very Precarious Supply Chain
Supply is already in deficit, and we're also looking at an anticipated 500 percent increase in demand, making EV battery recycling an increasingly important complement to mining. Analysts at Macquarie Research project deficits of 885 tonnes of this resource next year, 3,205 in 2019 and 5,340 in 2020.
Not only is demand set to wildly outstrip supply very soon, but current supply (50 percent) comes primarily from the Democratic Republic of Congo (DRC). Buyers are coming under increasing pressure to look elsewhere for cobalt as the U.S. moves to work with allies to secure EV metals through diversified supply chains. The DRC has a horrendous record when it comes to labor practices and human rights.
Ask Apple Inc. The tech giant recently announced it would stop buying unethical DRC cobalt for its iPhones - and as such, it has been forced to look for new suppliers.
The perfect storm continues: Some 95 percent of the world's cobalt is produced as a byproduct of copper and nickel mining, where concerns about ethical sourcing have put a spotlight on Canada's role in sustainable nickel practices worldwide. This means that cobalt supply is dependent on copper and nickel mining, and if those commodities are uneconomic to mine, there are no cobalt by-product results.
Not only is US Cobalt one of the first movers on the All-American ethical cobalt scene, but it's also financed to advance its Idaho Cobalt Belt project, and hopes to prove up 10 million tonnes of cobalt resource.
The Dream Team Behind Pure American Cobalt
The CEO of US Cobalt, Wayne Tisdale, is a legend in spotting emerging trends with impeccable timing and has created billions in shareholder value. He's already done it with uranium, gold and oil and gas, and his most recent homerun was in lithium, with Pure Energy. When it launched in 2012, lithium was selling for about $5,000 per tonne. Within 18 months, it had increased 450 percent.
His next bet is on cobalt.
Tisdale and his team at Intrepid Financial have, in recent years, created $2.7 billion in value by building and financing 5 companies in completely different industries:
- Rainy River (gold) was worth $1.2 billion at its peak
- Xemplar (uranium) hit $1 billion at its peak
- Ryland Oil (oil and gas) sold for $114 million
- Webtech Wireless (tech) was worth $300 million at its peak
- Pure Energy (lithium) is worth $65 million (and counting)
The bottom line? There is no other commodity on the market right now that we need more.
Just watch what the hedge funds are doing with cobalt because it's unprecedented. The run on physical cobalt started in February in the least expected corner: Major hedge funds started buying up physical cobalt and hoarding it in order to gain exposure, resulting in a major supply shortage for the blue metal. Swiss-based Pala Investments and China's Shanghai Chaos have already hoarded 17 percent of last year's global production. At today's prices that's worth around $280 million. At tomorrow's prices, it will be worth a lot more.
When hedge funds start stockpiling physical cobalt, it sends its traditional buyers into a panic to secure new shipments. Since November, cobalt prices have rallied more than 100 percent, and this is only the beginning. As the cobalt supply problem grows, and EV giants and gigafactories continue to increase demand, a home-grown solution is at hand. As a first principle of investing, where there is a supply problem, there is a massive opportunity for early investors.
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Electric car market goes zero to 2 million in five years
Electric Vehicle Market Growth accelerated as EV adoption hit 2 million in 2016, per IEA, led by China, Tesla momentum, policy incentives, charging infrastructure buildout, and diesel decline under Paris Agreement goals.
Key Points
EV adoption rose to 2 million in 2016, driven by policy, China, and charging buildout, yet still only 0.2% of cars.
✅ 2M EVs on roads in 2016; 60% YoY growth
✅ China led with >40% of global EV sales
✅ Policies target 30% share by 2030 via EVI
The number of electric vehicles on the road rocketed to 2 million in 2016 as the age of electric cars accelerates after being virtually non-existent just five years ago, according to the International Energy Agency.
Registered plug-in and battery-powered vehicles on roads worldwide rose 60% from the year before, according to the Global EV Outlook 2017 report from the Paris-based IEA. Despite the rapid growth, electric vehicles still represent just 0.2% of total light-duty vehicles even as U.S. EV sales continue to soar into 2024, suggesting a turning point.
“China was by far the largest electric car market, accounting for more than 40% of the electric cars sold in the world and more than double the amount sold in the United States,” the IEA wrote in the report published Wednesday. “It is undeniable that the current electric car market uptake is largely influenced by the policy environment.”
A multi government program called the Electric Vehicle Initiative on Thursday will set a goal for 30% market share for battery power cars, buses, trucks and vans by 2030, aligning with projections that driving electric cars within a decade could become commonplace, according to IEA. The 10 governments in the initiative include China, France, Germany, the UK and US.
India, which isn’t part of the group, said last month that it plans to sell only electric cars by the end of the next decade. Countries and cities are looking to electric vehicles to help tackle their air pollution problems.
In order to limit global warming to below 2 degrees Celsius (3.6 degrees Fahrenheit), the target set by the landmark Paris Agreement on climate change, the world will need 600 million electric vehicles by 2040, according to the IEA.
After struggling for consumer acceptance, Tesla Inc. has made electric vehicles cool and trendy, and is pushing into the mass market as the United States approaches a tipping point for mass adoption with the new Model 3 sedan.
Consumer interest and charging infrastructure, as well as declining demand for diesel cars in the wake of Volkswagen’s emissions scandal, has spurred massive investments in plug-in cars, and across Europe the share of electric cars grew during virus lockdown months, reinforcing this momentum. An electrical vehicle “cool factor” could spur sales to 450 million by 2035, according to BP chief economist Spencer Dale.
Volkswagen, the world’s largest automaker, plans to roll out four affordable electric vehicles in the coming years as part of a goal to sell more than 2 million battery-powered vehicles a year by 2025. Mercedes-Benz accelerated the introduction of ten new electric vehicles by three years to 2022 to take on Tesla as the dominance of the combustion engine gradually fades.
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Zambian government says close to agreement with mines on electricity price rises
Zambia Mining Electricity Tariff Agreement signals a shift to a 9.33 cents/kWh flat rate for mining companies, as Zesco and the ERB steer power pricing talks, with backdating, copper output, and tariffs in focus.
Key Points
A policy to set a 9.33 cents/kWh flat rate for mines, with Zesco backdating terms still under negotiation.
✅ 9.33 cents/kWh flat tariff accepted by most mining houses
✅ Talks involve Zesco, ERB, First Quantum, Glencore, Vale, Vedanta
✅ Backdating to January remains under negotiation
Zambia is close to reaching an agreement with mining companies over its plans to increase electricity prices, in line with recent increases in Hong Kong seen elsewhere, Finance Minister Felix Mutati reports.
The government last month proposed introducing a flat tariff of 9.30 U.S. cents/kilowatt hour (kWh) backdated to January for mining companies, instead of individually negotiated rates that have averaged 6 U.S. cents/kWh, a structure echoing Manitoba's planned 2.5% yearly hikes over three years, but mining companies opposed the plan.
A team headed by the minister of energy was due to hold talks with mining companies this week, including First Quantum Minerals,.
"We have concluded with all the mining houses except for one. They have accepted our proposal to actually pay 9.33 cents/kwh," Mutati told Reuters in a move comparable to BC Hydro's 3.75% rate plan over two years.
However, an agreement has not yet been reached on backdating the higher tariffs to January as proposed by power firm Zesco Ltd, a point comparable to issues outlined in Nunavut's electricity price hike analysis, he said.
"It is part of the negotiations but ideally that is what the government is considering," Mutati said.
Other mining companies operating in Zambia, Africa's No. 2 copper producer, include Glencore of Switzerland, Brazil's Vale and London-listed Vedanta Resources .
Last week Zambia's Energy Regulation Board (ERB) approved a 75 percent increase in the price of electricity for retail customers, whereas utilities such as BC Hydro's $2 per month proposal in Canada have pursued more gradual adjustments. (Reporting by Chris Mfula; Editing by James Macharia and Susan Fenton)
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Three Mile Island nuclear plant will close in 2019, owner says
Three Mile Island closure highlights Exelon's nuclear plant losses as cheap natural gas, grid auctions, and renewable energy credits undercut profitability in Pennsylvania, prompting bailout debates over subsidies, reliability, carbon emissions, and local jobs.
Key Points
The Three Mile Island closure is Exelon's plan to shut the plant after gas losses, failed grid bids, and no state aid.
✅ Cheap natural gas undercuts nuclear profitability
✅ Plant missed capacity market awards in grid auctions
✅ Exelon seeks subsidies; Pennsylvania debates costs
Cheap natural gas could do what the worst commercial nuclear power accident in U.S. history could not: put Three Mile Island out of business.
Three Mile Island’s owner, Exelon Corp., announced Tuesday that the plant, now at the center of an energy debate over whether to let struggling nuclear plants close or save them, will close in 2019 unless the state of Pennsylvania comes to its financial rescue.
Nuclear power plants around the U.S. have been struggling in recent years, even as nuclear generation costs hit a ten-year low, to compete with generating stations that burn plentiful and inexpensive natural gas to produce electricity.
The Chicago-based energy company’s announcement came after what it called more than five years of losses at the single-reactor plant and Three Mile Island’s recent failure to be selected as a guaranteed supplier of power to the regional electric grid.
Exelon wants Pennsylvania to give nuclear power the kind of preferential treatment and premium payments that are extended to renewable forms of energy, such as wind and solar. It has not said how much it wants.
Pennsylvania Gov. Tom Wolf has made no commitment to a bailout. In a statement Tuesday, Wolf said he is concerned about layoffs at Three Mile Island and open to discussions about the future of nuclear power in the state. Exelon employs 675 people at the plant, whose license does not expire until 2034.
Nuclear bailouts have won approval in Illinois and New York, but the potential for higher utility bills in Pennsylvania is generating resistance from rival energy companies, manufacturers and consumer advocates.
The control room seen at the Three Mile Island nuclear power plant. The site has struggled to compete in an electricity market booming with inexpensive gas.
David Hughes, president of the Pittsburgh-based consumer group Citizen Power, said the notion that nuclear power is clean energy, as the industry argues, is laughable.
“It’s a myth, and they’re trying any way they can to get more money out of ratepayers,” he said.
In addition to contending that nuclear power can help fight climate change and enable net-zero emissions better than gas or coal, Exelon and other energy companies have argued that their plants are big employers and sources of tax revenue.
“Like New York and Illinois before it, the commonwealth has an opportunity to take a leadership role by implementing a policy solution to preserve its nuclear energy facilities and the clean, reliable energy and good-paying jobs they provide,” Chris Crane, Exelon president and CEO, said in a statement.
Around the U.S., nuclear plants have been hammered by the natural gas boom.
In December, Illinois approved $235 million a year for Exelon to prop up nuclear plants in the Quad Cities and Clinton, six months after the company threatened to shut them down.
FirstEnergy Corp. has said it could decide next year to sell or close its three nuclear plants — Davis-Besse and Perry in Ohio and Beaver Valley in Pennsylvania. PSEG of New Jersey, which owns all or parts of four nuclear plants, has said it won’t operate ones that are long-term money losers.
In this undated file photo, a Pennsylvania state police officer and plant security guards stand outside the closed front gate at Three Mile Island after the plant was shut down following a partial meltdown on March 28, 1979. (PAUL VATHIS/AP)
Built during a golden age for nuclear power, Three Mile Island’s Unit 1 went online in 1974 and Unit 2 in 1978, coughing steam into the air above its sliver of land in the Susquehanna River, about 10 miles from Harrisburg.
In March 1979, equipment failure and operator errors led to a partial core meltdown of Unit 2, leading to several days of fear and prompting 144,000 people to flee their homes amid conflicting or ill-informed information from utility and government officials.
Scientists worried at one point that a hydrogen bubble forming inside the reactor would explode with catastrophic consequences.
Experts have come to no firm conclusion about the health effects or the amount of radiation released, though government scientists have said the maximum individual dosage was not enough to cause health problems.
Regardless, the accident badly undermined support for nuclear power. No nuclear plant that was proposed after the accident has been successfully completed and put into operation in the U.S.
The damaged reactor has been mothballed, but the other reactor is still in use. Exelon says the operating costs for just the one unit are high, further straining Three Mile Island’s financial health.
Pennsylvania is the nation’s No. 2 nuclear power state, after Illinois.
Closing Three Mile Island would have little or no effect on electricity bills, analysts say. But the power may be replaced by electricity generated by carbon-emitting fuels such as coal or gas.
Because of the flood of natural gas on the market, a lot of it from the Northeast’s Marcellus Shale formation, dozens of new gas-fired plants are coming online or planned. At the same times, states are putting more emphasis on renewable energy and efficiency.
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California regulators weigh whether the state needs more power plants
California Natural Gas Plant Rethink signals a shift toward clean energy, renewables, distributed solar, battery storage, and grid modernization as LADWP and regulators pause repowering plans amid an electricity oversupply and rising ratepayer costs.
Key Points
California pauses new gas plants to assess renewables, storage, and grid solutions for reliability.
✅ LADWP delays $2.2B gas repowers to study clean alternatives
✅ CEC weighs halting Oxnard plant amid grid oversupply
✅ Distributed solar, batteries, demand response boost reliability
California energy officials are, for the first time, rethinking plans to build expensive natural gas power plants in the face of an electricity glut and growing use of cleaner and cheaper energy alternatives.
The Los Angeles Department of Water and Power announced Tuesday that it has put a hold on a $2.2-billion plan to rebuild several old natural gas power plants while it studies clean energy alternatives to meet electricity demands. And the California Energy Commission may decide as early as Thursday to halt a natural gas project in Ventura County.
The scrutiny comes after an investigation found that the state is operating with an oversupply of electricity, driven largely by the construction of gas-fueled generating plants, leading to higher rates as regulators consider a rate overhaul to clean the grid. The state’s power plants are on track to be able to produce at least 21% more electricity than needed by 2020, according to the Times report.
Californians are footing a $40-billion annual bill while using less electricity, paying $6.8 billion more than they did in 2008 when power use in the state was at its all-time high. Electricity consumption has since fallen and remained largely flat.
Utilities in California have been on a years-long building binge, adding new natural gas plants even as the nation’s electricity system has undergone significant change, including consumer choice reforms that are reshaping the market.
Where utilities once delivered all electrical services from huge power plants along miles of transmission lines, the industry now must consider power delivered to the electric grid not only from its own sources, but also from solar systems and batteries at homes and businesses.
At the same time, utilities have been aggressively upgrading or rebuilding their aging natural gas plants — a move critics have said is unnecessary because consumers are using less power and clean energy technology is making those plants obsolete.
The DWP and energy commission moves involve as many as seven natural gas plant projects proposed for Southern California, despite warnings about a looming shortage if capacity is retired too fast, from Oxnard to Carlsbad, at a cost of more than $6 billion.
Reiko Kerr, the DWP’s senior assistant general manager of power systems, said given the changes in the energy world, the assessment is necessary to protect ratepayer dollars and the environment.
“The whole utility paradigm has shifted,” Kerr said in an interview. “We really are doing our ratepayers a disservice by not considering all viable options.
“We’re just looking at everything,” she said. “What can help us solve this reliability, renewable and greenhouse gas challenge that we all have?”
State and local governments have felt a heightened sense of urgency to deal with climate change after President Trump decided last week to withdraw the United States from the Paris climate accord.
California already has mandated that at least 50% of the state’s electricity come from clean energy sources by 2030. Senate leader Kevin de León (D-Los Angeles) wants to increase that to 100% by 2045.
Building or overhauling natural gas plants throughout Southern California, environmentalists argue, isn’t helping achieve those goals, even as some contend the state can't keep the lights on without gas during the transition.
The DWP’s move to delay plans for the fossil fuel plants, which seemed all but set to be built, came as a surprise to clean-energy advocates, who hailed the decision.
“This is a great first step toward smart energy investments that save customers money, ensure the lights stay on and protect our health and environment,” Graciela Geyer of the Sierra Club said.
The environmental group said that if the utility had moved ahead with the $2.2-billion investment in repowering natural gas plants, it “would have blown an irreparable hole in the city and the state’s hopes to achieve 100% generation” from clean energy sources.
Angela Johnson Meszaros, attorney at EarthJustice, said in a statement: "As our city struggles with the worst smog we’ve seen in years, we appreciate that LADWP is taking some much-needed time to reassess its plans to build fossil fuel power plants. We look forward to the day that LADWP announces that we are going to power our city with 100% clean energy.”
The gas-fired generating units slated for demolition and rebuilding are at the Scattergood, Haynes and Harbor electricity plants, which range from 34 to 67 years old.
As a group, the three plants have generated less than 20% of their combined capacity since 2001. The Harbor facility has operated on the low end at just 7%, while Haynes ran on the high end at 22%.
“The old model, the old legacy clunkers, won’t get us into the future we want,” DWP’s Kerr said.
DWP staff members told the utility’s’ commissioners Tuesday that their analysis of possible alternatives would be completed no later than early 2018.
Separately, the California Energy Commission this week is evaluating whether to halt a natural gas project in Ventura County after the state’s electric grid operator offered to conduct a study of clean energy alternatives to the roughly $250-million project on Mandalay Bay in Oxnard.
An energy commission committee has been deliberating since a hearing Monday during which Southern California Edison and the project’s developer, NRG Energy, argued that a study is simply a delay tactic that probably would kill a project needed to ensure reliable electric service and to avoid blackouts during peak demand.
The California Independent System Operator, which runs the state’s electric grid, told the energy commission that it would take three to four weeks to conduct its study on alternatives to the Oxnard natural gas project.
“Here we have an actual offer by the ISO to do such an analysis,” Ellison Folk, a lawyer representing the city of Oxnard, told the energy commission as she pushed for the study. “Its view that this is an analysis worth doing is something worth taking seriously.”
Energy commission members reviewing the study proposal are scheduled to meet again Thursday to consider the offer.
The board of governors for the California Independent System Operator made the unusual offer at its May 1 meeting to conduct a eleventh-hour study of clean-energy alternatives to building a new natural gas plant.
“If we’re going to be moving forward with a gas plant at this time, in this juncture, in the context of everything that’s going on, not evaluating other alternatives that are viable, noncombustion alternatives, is a missed opportunity,” Angelina Galetiva. a commission board member, said during the May 1 meeting.
