The U.S. Department of Energy has awarded nearly $67 million for a test project to store more than 2 million tons of carbon dioxide underground in western Wyoming.
The Big Sky Regional Carbon Sequestration Partnership hopes to start work within a year to develop the project, which will study the injection of carbon dioxide underground on a commercial scale.
The Energy Department, which is funding seven such large-scale projects around the country, says successful carbon sequestration would help the United States use its fossil fuel resources without releasing pollutants thought to contribute to climate change.
"Along with our regional partners, we will be able to move carbon sequestration technology from the laboratory to large-scale field demonstrations and ultimately to the marketplace," said Jeffrey Kupfer, deputy secretary of energy. "By doing so, we will help our nation meet growing energy demand and reduce greenhouse gas emissions."
The Big Sky partnership, which is led by Montana State University, is one of seven regional partnerships made up of federal agencies, universities, national laboratories and industry interests.
The remainder of the project's $130 million cost will be covered by private partners and other matching sources, said Lee Spangler, director of the Big Sky partnership. The main private partners are Houston-based Schlumberger and Denver-based Cimarex Energy Co., Spangler said.
The eight-year project involves drilling a CO2 injection well into the Nugget Sandstone formation, about 11,000 feet underground. Similar sandstone formations are found throughout the region and potentially could store more than 100 years of CO2 emissions, according to the Energy Department.
Cimarex will provide liquefied CO2 for the project from its Riley Ridge plant, a proposed gas- and helium-processing facility slated to be built at the base of the Wyoming Range, near Big Piney in Sublette County. Big Sky's injection well is proposed for the same area.
Scott Stinson, Cimarex's Riley Ridge project manager, said that while the Big Sky project is dependent on the Riley Ridge plant to provide CO2, the two projects are subject to separate environmental studies and permitting by regulators.
The Cimarex development also includes carbon sequestration, but the two projects are different. Cimarex plans to sequester the gas back into the zone where it came from, while the Big Sky project would inject CO2 into an area containing saline water that doesn't currently have CO2, Stinson said.
"Our project is moving forward because most of our environmental issues have already all been addressed," Stinson said. "We'll let the DOE address the new environmental issues that are specific to their project."
Spangler said the Nugget Sandstone is appropriate for the test project because it's comparable to other regional formations, has a large storage capacity and is sealed by five layers of caprock. The water inside the formation has salt levels that make it unusable for drinking water, he said.
"It's definitely not a drinking water source and therefore (the project) has no drinking water impact," he said.
Rob Hurless, energy adviser to Wyoming Gov. Dave Freudenthal, said the University of Wyoming participated in earlier stages of the Big Sky partnership's development of the sequestration project. More recently, the university turned its focus to a separate congressionally funded project involving a different private company, Hurless said.
Wyoming, the nation's largest producer of coal, has actively promoted carbon sequestration as a means of sustaining markets for its coal. The Wyoming Legislature this year passed two laws establishing underground storage rights and a framework for state regulation of carbon storage.
"At the end of the day, our interest is understanding and creating the environment so we can get C02 in the ground," Hurless said. "Anything that does that, where we can learn from it, we're very interested in."
California Electricity Reliability covers grid resilience amid heat waves, rolling blackouts, renewable energy integration, resource adequacy, battery storage, natural gas peakers, ISO oversight, and peak demand management to keep homes, businesses, and industry powered.
Key Points
Dependable California power delivery despite heat waves, peak demand, and challenges integrating renewables into grid.
✅ Rolling blackouts revealed gaps in resource adequacy.
✅ Early evening solar drop requires fast ramping and storage.
✅ Agencies pledge planning reforms and flexible backup supply.
One hallmark of an advanced society is a reliable supply of electrical energy for residential, commercial and industrial consumers. Uncertainty that California electricity will be there when we need it it undermines social cohesion and economic progress, as demonstrated by the travails of poor nations with erratic energy supplies.
California got a small dose of that syndrome in mid-August when a record heat wave struck the state and utilities were ordered to impose rolling blackouts to protect the grid from melting down under heavy air conditioning demands.
Gov. Gavin Newsom quickly demanded that the three overseers of electrical service to most of the state - the Public Utilities Commission, the Energy Commission and the California Independent Service Operator – explain what went wrong.
"These blackouts, which occurred without prior warning or enough time for preparation, are unacceptable and unbefitting of the nation's largest and most innovative state," Newsom wrote. "This cannot stand. California residents and businesses deserve better from their government."
Initially, there was some fingerpointing among the three entities. The blackouts had been ordered by the California Independent System Operator, which manages the grid and its president, Steve Berberich, said he had warned the Public Utilities Commission about the potential supply shortfall facing the state.
"We have indicated in filing after filing after filing that the resource adequacy program was broken and needed to be fixed," he said. "The situation we are in could have been avoided."
However, as political heat increased, the three agencies hung together and produced a joint report that admitted to lapses of supply planning and grid management and promised steps to avoid a repeat next summer.
"The existing resource planning processes are not designed to fully address an extreme heat storm like the one experienced in mid August," their report said. "In transitioning to a reliable, clean and affordable resource mix, resource planning targets have not kept pace to lead to sufficient resources that can be relied upon to meet demand in the early evening hours. This makes balancing demand and supply more challenging."
Although California's grid had experienced greater heat-related demands in previous years, most notably 2006, managers then could draw standby power from natural gas-fired plants and import juice from other Western states when necessary.
Since then, the state has shut down a number of gas-fired plants and become more reliant on renewable but less reliable sources such as windmills and solar panels.
August's air conditioning demand peaked just as output from solar panels was declining with the setting of the sun and grid managers couldn't tap enough electrons from other sources to close the gap.
While the shift to renewables didn't, unto itself, cause the blackouts, they proved the need for a bigger cushion of backup generation or power storage in batteries or some other technology. The Public Utilities Commission, as Beberich suggested, has been somewhat lax in ordering development of backup supply.
In the aftermath of the blackouts, the state Water Resources Control Board, no doubt with direction from Newsom's office, postponed planned shutdowns of more coastal plants, which would have reduced supply flexibility even more.
Shifting to 100% renewable electricity, the state's eventual goal, while maintaining reliability will not get any easier. The state's last nuclear plant, Diablo Canyon, is ticketed for closure and demand will increase as California eliminates gasoline- and diesel-powered vehicles in favor of "zero emission vehicles" as part of its climate policies push and phases out natural gas in homes and businesses.
Politicians such as Newsom and legislators in last week's blackout hearing may endorse a carbon-free future in theory, but they know that they'll pay the price as electricity prices climb if nothing happens when Californians flip the switch.
Maple Ridge Lithium-Ion Battery Plant will be a $1B E-One Moli clean-tech facility in Canada, manufacturing high-performance cells for tools and devices, with federal and provincial funding, creating 450 jobs and boosting battery supply chains.
Key Points
A $1B E-One Moli facility in B.C. producing lithium-ion cells, backed by federal and provincial funding.
✅ $204.5M federal and up to $80M B.C. support committed
✅ E-One Moli to create 450 skilled jobs in Maple Ridge
✅ High-performance cells for tools, medical devices, and equipment
A lithium-ion battery cell production plant costing more than $1 billion will be built in Maple Ridge, B.C., Prime Minister Justin Trudeau and Premier David Eby jointly announced on Tuesday.
Trudeau and Eby say the new E-One Moli facility will bolster Canada's role as a global leader in clean technology, as recent investments in Quebec's EV battery assembly illustrate today.
It will be the largest factory in Canada to manufacture such high-performance batteries, Trudeau said during the announcement, amid other developments such as a new plant in the Niagara Region supporting EV growth.
The B.C. government will contribute up to $80 million, while the federal government plans to contribute up to $204.5 million to the project. E-One Moli and private sources will supply the rest of the funding.
Trudeau said B.C. has long been known for its innovation in the clean-technology sector, and securing the clean battery manufacturing project, alongside Northvolt's project near Montreal, will build on that expertise.
"The world is looking to Canada. When we support projects like E-One Moli's new facility in Maple Ridge, we bolster Canada's role as a global clean-tech leader, create good jobs and help keep our air clean," he said.
"This is the future we are building together, every single day. Climate policy is economic policy."
Nelson Chang, chairman of E-One Moli Energy, said the company has always been committed to innovation and creativity as creator of the world's first commercialized lithium-metal battery.
E-One Moli has been operating a plant in Maple Ridge since 1990. Its parent company, Taiwan Cement Corp., is based in Taiwan.
"We believe that human freedom is a chance for us to do good for others and appreciate life's fleeing nature, to leave a positive impact on the world," Chang said.
"We believe that [carbon dioxide] reduction is absolutely the key to success for all future businesses," he said.
The new plant will produce high-performance lithium-cell batteries found in numerous products, including vacuums, medical devices, and power and gardening tools, aligning with B.C.'s grid development and job plans already underway, and is expected to create 450 jobs, making E-One Moli the largest private-sector employer in Maple Ridge.
Eby said every industry needs to find ways to reduce their carbon footprint to ensure they have a prosperous future and every province should do the same, with resource plays like Alberta's lithium supporting the EV supply chain today.
It's the responsible thing to do given the record wildfires, extreme heat, and atmospheric rivers that caused catastrophic flooding in B.C., he said, with large-scale battery storage in southwestern Ontario helping grid reliability.
"We know that this is what we have to do. The people who suggest that we have to accept that as the future and stop taking action are simply wrong."
Trudeau, Eby and Chang toured the existing plant in Maple Ridge, east of Vancouver, before making the announcement.
The prime minister wove his way around several machines and apologized to technicians about the commotion his visit was creating.
The Canadian Taxpayers Federation criticized the federal and B.C. governments for the announcement, saying in a statement the multimillion-dollar handout to the battery firm will cost taxpayers hundreds of thousands of dollars for each job.
Federation director Franco Terrazzano said the Trudeau government has recently given "buckets of cash" to corporations such as Volkswagen, Stellantis, the Ford Motor Company and Northvolt.
"Instead of raising taxes on ordinary Canadians and handing out corporate welfare, governments should be cutting red tape and taxes to grow the economy," said Terrazzano.
Construction is expected to start next June, as EV assembly deals put Canada in the race, and the company plans for the facility to be fully operational in 2028.
Boeing 787 More-Electric Architecture replaces pneumatics with bleedless pressurization, VFSG starter-generators, electric brakes, and heated wing anti-ice, leveraging APU, RAT, batteries, and airport ground power for efficient, redundant electrical power distribution.
Key Points
An integrated, bleedless electrical system powering start, pressurization, brakes, and anti-ice via VFSGs, APU and RAT.
✅ VFSGs start engines, then generate 235Vac variable-frequency power
✅ Bleedless pressurization, electric anti-ice improve fuel efficiency
✅ Electric brakes cut hydraulic weight and simplify maintenance
The 787 Dreamliner is different to most commercial aircraft flying the skies today. On the surface it may seem pretty similar to the likes of the 777 and A350, but get under the skin and it’s a whole different aircraft.
When Boeing designed the 787, in order to make it as fuel efficient as possible, it had to completely shake up the way some of the normal aircraft systems operated. Traditionally, systems such as the pressurization, engine start and wing anti-ice were powered by pneumatics. The wheel brakes were powered by the hydraulics. These essential systems required a lot of physical architecture and with that comes weight and maintenance. This got engineers thinking.
What if the brakes didn’t need the hydraulics? What if the engines could be started without the pneumatic system? What if the pressurisation system didn’t need bleed air from the engines? Imagine if all these systems could be powered electrically… so that’s what they did.
Power sources
The 787 uses a lot of electricity. Therefore, to keep up with the demand, it has a number of sources of power, much as grid operators track supply on the GB energy dashboard to balance loads. Depending on whether the aircraft is on the ground with its engines off or in the air with both engines running, different combinations of the power sources are used.
Engine starter/generators
The main source of power comes from four 235Vac variable frequency engine starter/generators (VFSGs). There are two of these in each engine. These function as electrically powered starter motors for the engine start, and once the engine is running, then act as engine driven generators.
The generators in the left engine are designated as L1 and L2, the two in the right engine are R1 and R2. They are connected to their respective engine gearbox to generate electrical power directly proportional to the engine speed. With the engines running, the generators provide electrical power to all the aircraft systems.
APU starter/generators
In the tail of most commercial aircraft sits a small engine, the Auxiliary Power Unit (APU). While this does not provide any power for aircraft propulsion, it does provide electrics for when the engines are not running.
The APU of the 787 has the same generators as each of the engines — two 235Vac VFSGs, designated L and R. They act as starter motors to get the APU going and once running, then act as generators. The power generated is once again directly proportional to the APU speed.
The APU not only provides power to the aircraft on the ground when the engines are switched off, but it can also provide power in flight should there be a problem with one of the engine generators.
Battery power
The aircraft has one main battery and one APU battery. The latter is quite basic, providing power to start the APU and for some of the external aircraft lighting.
The main battery is there to power the aircraft up when everything has been switched off and also in cases of extreme electrical failure in flight, and in the grid context, alternatives such as gravity power storage are being explored for long-duration resilience. It provides power to start the APU, acts as a back-up for the brakes and also feeds the captain’s flight instruments until the Ram Air Turbine deploys.
Ram air turbine (RAT) generator
When you need this, you’re really not having a great day. The RAT is a small propeller which automatically drops out of the underside of the aircraft in the event of a double engine failure (or when all three hydraulics system pressures are low). It can also be deployed manually by pressing a switch in the flight deck.
Once deployed into the airflow, the RAT spins up and turns the RAT generator. This provides enough electrical power to operate the captain’s flight instruments and other essentials items for communication, navigation and flight controls.
External power
Using the APU on the ground for electrics is fine, but they do tend to be quite noisy. Not great for airports wishing to keep their noise footprint down. To enable aircraft to be powered without the APU, most big airports will have a ground power system drawing from national grids, including output from facilities such as Barakah Unit 1 as part of the mix. Large cables from the airport power supply connect 115Vac to the aircraft and allow pilots to shut down the APU. This not only keeps the noise down but also saves on the fuel which the APU would use.
The 787 has three external power inputs — two at the front and one at the rear. The forward system is used to power systems required for ground operations such as lighting, cargo door operation and some cabin systems. If only one forward power source is connected, only very limited functions will be available.
The aft external power is only used when the ground power is required for engine start.
Circuit breakers
Most flight decks you visit will have the back wall covered in circuit breakers — CBs. If there is a problem with a system, the circuit breaker may “pop” to preserve the aircraft electrical system. If a particular system is not working, part of the engineers procedure may require them to pull and “collar” a CB — placing a small ring around the CB to stop it from being pushed back in. However, on the 787 there are no physical circuit breakers. You’ve guessed it, they’re electric.
Within the Multi Function Display screen is the Circuit Breaker Indication and Control (CBIC). From here, engineers and pilots are able to access all the “CBs” which would normally be on the back wall of the flight deck. If an operational procedure requires it, engineers are able to electrically pull and collar a CB giving the same result as a conventional CB.
Not only does this mean that the there are no physical CBs which may need replacing, it also creates space behind the flight deck which can be utilised for the galley area and cabin.
A normal flight
While it’s useful to have all these systems, they are never all used at the same time, and, as the power sector’s COVID-19 mitigation strategies showed, resilience planning matters across operations. Depending on the stage of the flight, different power sources will be used, sometimes in conjunction with others, to supply the required power.
On the ground
When we arrive at the aircraft, more often than not the aircraft is plugged into the external power with the APU off. Electricity is the blood of the 787 and it doesn’t like to be without a good supply constantly pumping through its system, and, as seen in NYC electric rhythms during COVID-19, demand patterns can shift quickly. Ground staff will connect two forward external power sources, as this enables us to operate the maximum number of systems as we prepare the aircraft for departure.
Whilst connected to the external source, there is not enough power to run the air conditioning system. As a result, whilst the APU is off, air conditioning is provided by Preconditioned Air (PCA) units on the ground. These connect to the aircraft by a pipe and pump cool air into the cabin to keep the temperature at a comfortable level.
APU start
As we near departure time, we need to start making some changes to the configuration of the electrical system. Before we can push back , the external power needs to be disconnected — the airports don’t take too kindly to us taking their cables with us — and since that supply ultimately comes from the grid, projects like the Bruce Power upgrade increase available capacity during peaks, but we need to generate our own power before we start the engines so to do this, we use the APU.
The APU, like any engine, takes a little time to start up, around 90 seconds or so. If you remember from before, the external power only supplies 115Vac whereas the two VFSGs in the APU each provide 235Vac. As a result, as soon as the APU is running, it automatically takes over the running of the electrical systems. The ground staff are then clear to disconnect the ground power.
If you read my article on how the 787 is pressurised, you’ll know that it’s powered by the electrical system. As soon as the APU is supplying the electricity, there is enough power to run the aircraft air conditioning. The PCA can then be removed.
Engine start
Once all doors and hatches are closed, external cables and pipes have been removed and the APU is running, we’re ready to push back from the gate and start our engines. Both engines are normally started at the same time, unless the outside air temperature is below 5°C.
On other aircraft types, the engines require high pressure air from the APU to turn the starter in the engine. This requires a lot of power from the APU and is also quite noisy. On the 787, the engine start is entirely electrical.
Power is drawn from the APU and feeds the VFSGs in the engines. If you remember from earlier, these fist act as starter motors. The starter motor starts the turn the turbines in the middle of the engine. These in turn start to turn the forward stages of the engine. Once there is enough airflow through the engine, and the fuel is igniting, there is enough energy to continue running itself.
After start
Once the engine is running, the VFSGs stop acting as starter motors and revert to acting as generators. As these generators are the preferred power source, they automatically take over the running of the electrical systems from the APU, which can then be switched off. The aircraft is now in the desired configuration for flight, with the 4 VFSGs in both engines providing all the power the aircraft needs.
As the aircraft moves away towards the runway, another electrically powered system is used — the brakes. On other aircraft types, the brakes are powered by the hydraulics system. This requires extra pipe work and the associated weight that goes with that. Hydraulically powered brake units can also be time consuming to replace.
By having electric brakes, the 787 is able to reduce the weight of the hydraulics system and it also makes it easier to change brake units. “Plug in and play” brakes are far quicker to change, keeping maintenance costs down and reducing flight delays.
In-flight
Another system which is powered electrically on the 787 is the anti-ice system. As aircraft fly though clouds in cold temperatures, ice can build up along the leading edge of the wing. As this reduces the efficiency of the the wing, we need to get rid of this.
Other aircraft types use hot air from the engines to melt it. On the 787, we have electrically powered pads along the leading edge which heat up to melt the ice.
Not only does this keep more power in the engines, but it also reduces the drag created as the hot air leaves the structure of the wing. A double win for fuel savings.
Once on the ground at the destination, it’s time to start thinking about the electrical configuration again. As we make our way to the gate, we start the APU in preparation for the engine shut down. However, because the engine generators have a high priority than the APU generators, the APU does not automatically take over. Instead, an indication on the EICAS shows APU RUNNING, to inform us that the APU is ready to take the electrical load.
Shutdown
With the park brake set, it’s time to shut the engines down. A final check that the APU is indeed running is made before moving the engine control switches to shut off. Plunging the cabin into darkness isn’t a smooth move. As the engines are shut down, the APU automatically takes over the power supply for the aircraft. Once the ground staff have connected the external power, we then have the option to also shut down the APU.
However, before doing this, we consider the cabin environment. If there is no PCA available and it’s hot outside, without the APU the cabin temperature will rise pretty quickly. In situations like this we’ll wait until all the passengers are off the aircraft until we shut down the APU.
Once on external power, the full flight cycle is complete. The aircraft can now be cleaned and catered, ready for the next crew to take over.
Bottom line
Electricity is a fundamental part of operating the 787. Even when there are no passengers on board, some power is required to keep the systems running, ready for the arrival of the next crew. As we prepare the aircraft for departure and start the engines, various methods of powering the aircraft are used.
The aircraft has six electrical generators, of which only four are used in normal flights. Should one fail, there are back-ups available. Should these back-ups fail, there are back-ups for the back-ups in the form of the battery. Should this back-up fail, there is yet another layer of contingency in the form of the RAT. A highly unlikely event.
The 787 was built around improving efficiency and lowering carbon emissions whilst ensuring unrivalled levels safety, and, in the wider energy landscape, perspectives like nuclear beyond electricity highlight complementary paths to decarbonization — a mission it’s able to achieve on hundreds of flights every single day.
Alberta Capacity Market Overhaul faces scrutiny over electricity costs, reliability targets, investor certainty, and AESO design, as UCP reviews NDP reforms, renewables integration, and deregulated energy-only alternatives impacting generators, ratepayers, and future power price volatility.
Key Points
A shift paying generators for capacity and energy to improve reliability; critics warn of higher electricity costs.
✅ UCP reviewing NDP plan and subsidies amid market uncertainty
✅ AESO cites reliability needs as coal retires, renewables grow
✅ Critics predict overprocurement and premature launch cost spikes
Jason Kenney's government is facing renewed pressure to cancel a massive overhaul of Alberta's power market that one player says will needlessly spike costs by hundreds of millions of dollars, amid an electricity sector in profound change today.
Nick Clark, who owns the Calgary-based electricity retailer Spot Power, has sent the Alberta government an open letter urging it to walk away from the electricity market changes proposed by the former NDP government.
"How can you encourage new industry to open up when one of their raw material costs will increase so dramatically?" Clark said. "The capacity market will add more costs to the consumer and it will be a spiral downwards."
But NDP Leader Rachel Notley, whose government ushered in the changes, said fears over dramatic cost increases are unfounded.
"There are some players within the current electricity regime who have a vested interest in maintaining the current situation," Notley said
Kenney's UCP vowed during the recent election to review the current and proposed electricity market options, as the electricity market heads for a reshuffle, with plans to report on its findings within 90 days.
The party also promised to scrap subsidies for renewable power, while ensuring "a market-based electricity system" that emphasizes competition in Alberta's electricity market for consumers.
The New Democrats had opted to scrap the current deregulated power market — in place since the Klein era — after phasing out coal-fired generation and ushering in new renewable power as part of changes in how Alberta produces and pays for electricity under their climate change strategy.
The Alberta Electric System Operator, which oversees the grid, says the province will need new sources of electricity to replace shuttered coal plants and backstop wind and solar generators, while meeting new consumer demand.
After consulting with power companies and investors, the AESO concluded in late 2016 the electricity market couldn't attract enough investment to build the needed power generation under the current model.
The AESO said at the time investors were concerned their revenues would be uncertain once new plants are running. It recommended what's known as a capacity market, which compensates power generators for having the ability to produce electricity, even when they're not producing it.
In other words, producers would collect revenue for selling electricity into the grid and, separately, for having the capacity to produce power as a backstop, ensuring the lights stay on. Power generators would use this second source of income to help cover plant construction costs.
Clark said the complex system introduces unnecessary costs, which he believes would hurt consumers in the end. He said what's preventing investment in the power market is uncertainty over how the market will be structured in the future.
"What investors need to see in this market is price certainty, regulatory ease, and where the money they're putting into the marketplace is not at risk," he said.
"They can risk their own money, but if in fact the government comes in and changes the policy as it was doing, then money stayed away from the province."
Notley said a capacity market would not increase power bills but would avoid big price swings, with protections like a consumer price cap on power bills also debated, while bringing greener sources of energy into Alberta's grid.
"Moving back to the [deregulated] energy-only market would make a lot of money for a few people, and put consumers, both industrial and residential, at great risk."
Clark disagrees, citing Enmax's recent submissions to the Alberta Utilities Commission, in which the utility argues the proposed design of the capacity market is flawed.
In its submissions to the commission, which is considering the future of Alberta's power market, Enmax says the proposed system would overestimate the amount of generation capacity the province will need in the future. It says the calculation could result in Alberta procuring too much capacity.
The City of Calgary-owned utility says this could drive up costs by anywhere from $147 million to $849 million a year. It says a more conservative calculation of future electricity demand could avoid the extra expense.
An analysis by a Calgary energy consulting firm suggests a different feature of the proposed power market overhaul could also lead to a massive spike in costs.
EDC Associates, hired by the Consumers' Coalition of Alberta, argues the proposal to launch the new system in November 2021 may be premature, because it could bring in additional supplies of electricity before they're needed.
The consultant's report, also filed with the Alberta Utilities Commission, estimates the early launch date could require customers to pay 40 per cent more for electricity amid rising electricity prices in the province — potentially an extra $1.4 billion — in 2021/22.
"The target implementation date is politically driven by the previous government," said Duane Reid-Carlson, president of EDC Associates.
Reid-Carlson recommends delaying the launch date by several years and making another tweak: reducing the proposed target for system reliability, which would scale back the amount of power generation needed to backstop renewable sources.
"You could get a result in the capacity market that would give a similar cost to consumers that the [deregulated] energy-only market design would have done otherwise," he said.
"You could have a better risk profile associated with the capacity market that would serve consumers better through lower cost, lower price volatility, and it would serve generators better by giving them better access to capital at lower costs."
The UCP government did not respond to a request for comment.
Toronto Hydro Storm Outages continue after strong winds and heavy rain, with crews restoring power, clearing debris and downed lines. Safety alerts and real-time updates guide affected neighborhoods via website and social media.
Key Points
Toronto Hydro Storm Outages are weather-related power cuts; crews restore service safely and share public updates.
✅ Crews prioritize areas with severe damage and limited access
✅ Report downed power lines; keep a safe distance
✅ Check website and social media for restoration updates
In the aftermath of a powerful spring storm that swept through Toronto on Tuesday, approximately 400 customers remain without power as of Sunday. The storm, which brought strong winds and heavy rain that caused severe flooding in some areas, led to significant damage across the city, including downed trees and power lines. Toronto Hydro crews have been working tirelessly to restore service, similar to efforts by Sudbury Hydro crews in Northern Ontario, focusing on areas with the most severe damage. While many customers have had their power restored, the remaining outages are concentrated in neighborhoods where access is challenging due to debris and fallen infrastructure.
Toronto Hydro has assured residents that restoration efforts are ongoing and that they are prioritizing safety and efficiency, in step with recovery from damaging storms in Ontario across the province. The utility company has urged residents to report any downed power lines and to avoid approaching them, as they may still be live and dangerous, and notes that utilities sometimes rely on mutual aid deployments to speed restoration in large-scale events. Additionally, Toronto Hydro has been providing updates through their website and social media channels, keeping the public informed about the status of power restoration in affected areas.
The storm's impact has also led to disruptions in other services, and power outages in London disrupted morning routines for thousands earlier in the week. Some public transportation routes experienced delays due to debris on tracks, and several schools in the affected areas were temporarily closed. City officials are coordinating with various agencies to address these issues and ensure that services return to normal as quickly as possible, even as Quebec contends with widespread power outages after severe windstorms.
Residents are advised to stay updated on the situation through official channels and to exercise caution when traveling in storm-affected areas. Toronto Hydro continues to work diligently to restore power to all customers and appreciates the public's patience during this challenging time, a challenge echoed when Texas utilities struggled to restore power during Hurricane Harvey.
Shell's Industrial Electricity Supply Strategy targets UK and US industrial customers, leveraging gas-to-power, renewables, long-term PPAs, and energy transition momentum to disrupt utilities, cut costs, and secure demand in the evolving electricity market.
Key Points
Shell will sell power directly to industrial clients, leveraging gas, renewables, and PPAs to secure demand and pricing.
✅ Direct power sales to industrials in UK and US
✅ Leverages gas-to-power, renewables, and flexible sourcing
✅ Targets long-term PPAs, price stability, and demand security
Royal Dutch Shell’s decision to sell electricity direct to industrial customers is an intelligent and creative one. The shift is strategic and demonstrates that oil and gas majors are capable of adapting to a new world as the transition to a lower carbon economy develops. For those already in the business of providing electricity it represents a dangerous competitive threat. For the other oil majors it poses a direct challenge on whether they are really thinking about the future sufficiently strategically.
The move starts small with a business in the UK that will start trading early next year, in a market where the UK’s second-largest electricity operator has recently emerged, signaling intensifying competition. Shell will supply the business operations as a first step and it will then expand. But Britain is not the limit — Shell recently announced its intention of making similar sales in the US. Historically, oil and gas companies have considered a move into electricity as a step too far, with the sector seen as oversupplied and highly politicised because of sensitivity to consumer price rises. I went through three reviews during my time in the industry, each of which concluded that the electricity business was best left to someone else. What has changed? I think there are three strands of logic behind the strategy.
First, the state of the energy market. The price of gas in particular has fallen across the world over the last three years to the point where the International Energy Agency describes the current situation as a “glut”. Meanwhile, Shell has been developing an extensive range of gas assets, with more to come. In what has become a buyer’s market it is logical to get closer to the customer — establishing long-term deals that can soak up the supply, while options such as storing electricity in natural gas pipes gain attention in Europe. Given its reach, Shell could sign contracts to supply all the power needed by the UK’s National Health Service or with the public sector as a whole as well as big industrial users. It could agree long-term contracts with big businesses across the US.
To the buyers, Shell offers a high level of security from multiple sources with prices presumably set at a discount to the market. The mutual advantage is strong. Second, there is the transition to a lower carbon world. No one knows how fast this will move, but one thing is certain: electricity will be at the heart of the shift with power demand increasing in transportation, industry and the services sector as oil and coal are displaced. Shell, with its wide portfolio, can match inputs to the circumstances and policies of each location. It can match its global supplies of gas to growing Asian markets, including China’s 2060 electricity share projections, while developing a renewables-based electricity supply chain in Europe. The new company can buy supplies from other parts of the group or from outside. It has already agreed to buy all the power produced from the first Dutch offshore wind farm at Egmond aan Zee.
The move gives Shell the opportunity to enter the supply chain at any point — it does not have to own power stations any more than it now owns drilling rigs or helicopters. The third key factor is that the electricity market is not homogenous. The business of supplying power can be segmented. The retail market — supplying millions of households — may be under constant scrutiny, as efforts to fix the UK’s electricity grid keep infrastructure in the headlines, with suppliers vilified by the press and governments forced to threaten price caps but supplying power to industrial users is more stable and predictable, and done largely out of the public eye. The main industrial and commercial users are major companies well able to negotiate long-term deals.
Given its scale and reputation, Shell is likely to be a supplier of choice for industrial and commercial consumers and potentially capable of shaping prices. This is where the prospect of a powerful new competitor becomes another threat to utilities and retailers whose business models are already under pressure. In the European market in particular, electricity pricing mechanisms are evolving and public policies that give preference to renewables have undermined other sources of supply — especially those produced from gas. Once-powerful companies such as RWE and EON have lost much of their value as a result. In the UK, France and elsewhere, public and political hostility to price increases have made retail supply a risky and low-margin business at best. If the industrial market for electricity is now eaten away, the future for the existing utilities is desperate.
Shell’s move should raise a flag of concern for investors in the other oil and gas majors. The company is positioning itself for change. It is sending signals that it is now viable even if oil and gas prices do not increase and that it is not resisting the energy transition. Chief executive Ben van Beurden said last week that he was looking forward to his next car being electric. This ease with the future is rather rare. Shareholders should be asking the other players in the old oil and gas sector to spell out their strategies for the transition.
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