GE has signed contracts totaling US$300 million to supply six gas turbines and associated services to the Egyptian Electricity Holding Company for two new combined-cycle power plants near Cairo that will support Egypt's rapidly growing energy needs.
GE and its consortium partner, SEPCO III, have been selected for the expansions of Giza North and Banha power plants. The projects will add 2,250 megawatts of capacity to the country's power grid, or 10 percent of capacity to the country's grid, supporting residents and businesses in Cairo. These $300 million contracts constitute the largest power generation order between GE and Egypt.
According to Egypt's Ministry of Electricity and Energy, the country experienced 13 percent growth in electricity demand from 2009 to 2010, and the growth is expected to continue at a rate of approximately 11 percent over the next five years. The Giza North and Banha plants are scheduled to enter service by the middle of 2013 in time to help the country meet its peak power demands during the summer.
GE will supply four Frame 9FA Gas Turbines for Giza North and two 9FA Gas Turbines for Banha, along with installation and technical services. The 9FA Gas Turbines are equipped with GE's advanced dry low NOx DLN combustion technology to support lower emissions at Giza North and Banha power plants. GE's advanced DLN combustion technology is designed to help gas turbine operators meet lower emissions requirements without the injection of diluents. More than 700 GE DLN combustors have compiled more than 23 million hours of operation on almost 800 units worldwide.
Dr. Hassan Younis, Egypt's Minister for Electricity and Energy, said: "Egypt is heralding a new era in its growth story, with a focus on the all-round development of all economic sectors. Driving this is the power industry, which is being upgraded and strengthened to meet the needs of the people and boost business efficiencies. The partnership with the major industrial energy companies will accelerate the development of the country's power sector and, in turn, the overall economy."
"GE's advanced technology produces power with high efficiency and promotes energy sustainability in Egypt," said Mahmoud Balbaa, chairman, Egyptian Electricity Holding Company. "We are pleased to be working with an industry leader such as GE to support us in meeting the growing power demands in Cairo and the country."
"Strong economic growth in Egypt continues to drive the need to increase the country's supply of reliable electricity," said Joseph Anis, GE Energy's president and CEO for the Middle East. "With the Giza North and Banha projects, we continue our commitment to supply the technology and services that will help our customers throughout the region meet their long-term power generation and delivery objectives."
The engineering, procurement and construction EPC company for the Giza North and Banha power plants is China-based SEPCO III. GE and SEPCO III have successfully collaborated on several other projects around the world and in the Middle East region. This is the first time that both companies have joined in a consortium partnership structure for a power project in Egypt.
GE's F technology, proven in more than 36 million hours of operation worldwide, offers high efficiency and low emissions in combined-cycle operation. The two new plants plan to operate at 56 percent combined-cycle efficiency while meeting emissions standards of 25 ppm NOx. Natural gas will be the primary fuel for both plants.
The four 9FA Gas Turbines at Giza North, located 30 kilometers northwest of Cairo, will have a total capacity of 1,000 megawatts, while the plant will generate 1,500 megawatts in combined-cycle operation. The two 9FA Gas Turbines at Banha, which is 40 kilometers northwest of Cairo, have a total capacity of 500 megawatts and the plant's combined-cycle output will be 750 megawatts. The gas turbines are scheduled for shipment to the project sites in the second quarter of 2012.
The Giza North and Banha projects build on GE's strong technology presence in Egypt. Since 1974, nearly 70 GE gas turbines have been installed in Egypt, and they are generating more than seven gigawatts, a quarter of the country's installed capacity.
California Rooftop Solar Rate Reforms propose shifting net metering to fixed access fees, peak-demand charges, and time-of-use pricing, aligning grid costs, distributed generation incentives, and retail rates for efficient, least-cost electricity and fair cost recovery.
Key Points
Policies replacing net metering with fixed fees, demand charges, and time-of-use rates to align costs and incentives.
✅ Large fixed access charge funds grid infrastructure
✅ Peak-demand pricing reflects capacity costs at system peak
✅ Time-varying rates align marginal costs and emissions
The California Public Service Commission has proposed revamping electricity rates for residential customers who produce electricity through their rooftop solar panels. In a recent New York Times op‐ed, former Governor Arnold Schwarzenegger argued the changes pose an existential threat to residential rooftop solar. Interest groups favoring rooftop solar portray the current pricing system, often called net metering, in populist terms: “Net metering is the one opportunity for the little guy to get relief, and they want to put the kibosh on it.” And conventional news coverage suggests that because rooftop solar is an obvious good development and nefarious interests, incumbent utilities and their unionized employees, support the reform, well‐meaning people should oppose it. A more thoughtful analysis would inquire about the characteristics and prices of a system that supplies electricity at least cost.
Currently, under net metering customers are billed for their net electricity use plus a minimum fixed charge each month. When their consumption exceeds their home production, they are billed for their net use from the electricity distribution system (the grid) at retail rates. When their production exceeds their consumption and the excess is supplied to the grid, residential consumers also are reimbursed at retail rates. During a billing period, if a consumer’s production equaled their consumption their electric bill would only be the monthly fixed charge.
Net metering would be fine if all the fixed costs of the electric distribution and transmission systems were included in the fixed monthly charge, but they are not. Between 66 and 77 percent of the expenses of California private utilities do not change when a customer increases or decreases consumption, but those expenses are recovered largely through charges per kWh of use rather than a large monthly fixed charge. Said differently, for every kWh that a PG&E solar household exported into the grid in 2019, it saved more than 26 cents, on average, while the utility’s costs only declined by about 8 cents or less including an estimate of the pollution costs of the system’s fossil fuel generators. The 18‐cent difference pays for costs that don’t change with variation in a household’s consumptions, like much of the transmission and distribution system, energy efficiency programs, subsidies for low‐income customers, and other fixed costs. Rooftop solar is so popular in California because its installation under a net metering system avoids the 18 cents, creating a solar cost shift onto non-solar customers. Rooftop solar is not the answer to all our environmental needs. It is simply a form of arbitrage around paying for the grid’s fixed costs.
What should electricity tariffs look like? This article in Regulation argues that efficient charges for electricity would consist of three components: a large fixed charge for the distribution and transmission lines, meter reading, vegetation trimming, etc.; a peak‐demand charge related to your demand when the system’s peak demand occurs to pay for fixed capacity costs associated with peak use; and a charge for electricity use that reflects the time‐ and location‐varying cost of additional electricity supply.
Actual utility tariffs do not reflect this ideal because of political concerns about the effects of large fixed monthly charges on low‐income customers and the optics of explaining to customers that they must pay 50 or 60 dollars a month for access even if their use is zero. Instead, the current pricing system “taxes” electricity use to pay for fixed costs. And solar net metering is simply a way to avoid the tax. The proposed California rate reforms would explicitly impose a fixed monthly charge on rooftop solar systems that are also connected to the grid, a change that could bring major changes to your electric bill statewide, and would thus end the fixed‐cost avoidance. Any distributional concerns that arise because of the effect of much larger fixed charges on lower‐income customers could be managed through explicit tax deductions that are proportional to income.
The current rooftop solar subsidies in California also should end because they have perverse incentive effects on fossil fuel generators, even as the state exports its energy policies to neighbors. Solar output has increased so much in California that when it ends with every sunset, natural gas generated electricity has to increase very rapidly. But the natural gas generators whose output can be increased rapidly have more pollution and higher marginal costs than those natural gas plants (so called combined cycle plants) whose output is steadier. The rapid increase in California solar capacity has had the perverse effect of changing the composition of natural gas generators toward more costly and polluting units.
The reforms would not end the role of solar power. They would just shift production from high‐cost rooftop to lower‐cost centralized solar production, a transition cited in analyses of why electricity prices are soaring in California, whose average costs are comparable with electricity production in natural gas generators. And they would end the excessive subsidies to solar that have negatively altered the composition of natural gas generators.
Getting prices right does not generate citizen interest as much as the misguided notion that rooftop solar will save the world, and recent efforts to overturn income-based utility charges show how politicized the debate remains. But getting prices right would allow the decentralized choices of consumers and investors to achieve their goals at least cost.
Vehicle-to-Grid Revenue helps EV owners earn income via V2G, demand response, and ancillary services by exporting stored energy, supporting grid balancing, smart charging, and renewable integration with two-way charging infrastructure.
Key Points
Income EV owners earn by selling battery power to the grid for balancing, response, and flexibility services.
✅ Earn up to about $1,530 annually in Denmark trials
✅ Requires V2G-compatible EVs and two-way smart chargers
✅ Provides ancillary services and supports renewable integration
Electric car owners are earning as much as $1,530 a year just by parking their vehicle and feeding excess power back into the grid, effectively selling electricity back to the grid under V2G schemes.
Trials in Denmark carried out by Nissan and Italy’s biggest utility Enel Spa showed how batteries inside electric cars could, using vehicle-to-grid technology, help balance supply and demand at times and provide a new revenue stream for those who own the vehicles.
Technology linking vehicles to the grid marks another challenge for utilities already struggling to integrate wind and solar power into their distribution system. As the use of plug-in cars spreads, grid managers will have to pay closer attention and, with proper management, to when motorists draw from the system and when they can smooth variable flows.
“If you blindingly deploy in the market a massive number of electric cars without any visibility or control over the way they impact the electricity grid, you might create new problems,” said Francisco Carranza, director of energy services at Nissan Europe in an interview with Bloomberg New Energy Finance.
While the Tokyo-based automaker has trials with more than 100 cars across Europe, only those in Denmark are able to earn money by feeding power back into the grid. There, fleet operators collected about 1,300 euros ($1,530) a year using the two-way charge points, said Carranza.
Restrictions on accessing the market in the U.K. means the company needs to reach about 150 cars before they can get paid for power sent back to the grid. That could be achieved by the end of this year, he said.
“It’s feasible,” he said. “It’s just a matter of finding the appropriate business model to deploy the business wide-scale.’’
Electric car demand globally is expected to soar, challenging state power grids and putting further pressure on grid operators to find new ways of balancing demand. Power consumption from vehicles will grow to 1,800 terawatt-hours in 2040 from just 6 terawatt-hours now, according to Bloomberg New Energy Finance.
ITER Nuclear Fusion advances tokamak magnetic confinement, heating deuterium-tritium plasma with superconducting magnets, targeting net energy gain, tritium breeding, and steam-turbine power, while complementing laser inertial confinement milestones for grid-scale electricity and 2025 startup goals.
Key Points
ITER Nuclear Fusion is a tokamak project confining D-T plasma with magnets to achieve net energy gain and clean power.
✅ Tokamak magnetic confinement with high-temp superconducting coils
✅ Deuterium-tritium fuel cycle with on-site tritium breeding
✅ Targets net energy gain and grid-scale, low-carbon electricity
It sounds like the stuff of dreams: a virtually limitless source of energy that doesn’t produce greenhouse gases or radioactive waste. That’s the promise of nuclear fusion, often described as the holy grail of clean energy by proponents, which for decades has been nothing more than a fantasy due to insurmountable technical challenges. But things are heating up in what has turned into a race to create what amounts to an artificial sun here on Earth, one that can provide power for our kettles, cars and light bulbs.
Today’s nuclear power plants create electricity through nuclear fission, in which atoms are split, with next-gen nuclear power exploring smaller, cheaper, safer designs that remain distinct from fusion. Nuclear fusion however, involves combining atomic nuclei to release energy. It’s the same reaction that’s taking place at the Sun’s core. But overcoming the natural repulsion between atomic nuclei and maintaining the right conditions for fusion to occur isn’t straightforward. And doing so in a way that produces more energy than the reaction consumes has been beyond the grasp of the finest minds in physics for decades.
But perhaps not for much longer. Some major technical challenges have been overcome in the past few years and governments around the world have been pouring money into fusion power research as part of a broader green industrial revolution under way in several regions. There are also over 20 private ventures in the UK, US, Europe, China and Australia vying to be the first to make fusion energy production a reality.
“People are saying, ‘If it really is the ultimate solution, let’s find out whether it works or not,’” says Dr Tim Luce, head of science and operation at the International Thermonuclear Experimental Reactor (ITER), being built in southeast France. ITER is the biggest throw of the fusion dice yet.
Its $22bn (£15.9bn) build cost is being met by the governments of two-thirds of the world’s population, including the EU, the US, China and Russia, at a time when Europe is losing nuclear power and needs energy, and when it’s fired up in 2025 it’ll be the world’s largest fusion reactor. If it works, ITER will transform fusion power from being the stuff of dreams into a viable energy source.
Constructing a nuclear fusion reactor ITER will be a tokamak reactor – thought to be the best hope for fusion power. Inside a tokamak, a gas, often a hydrogen isotope called deuterium, is subjected to intense heat and pressure, forcing electrons out of the atoms. This creates a plasma – a superheated, ionised gas – that has to be contained by intense magnetic fields.
The containment is vital, as no material on Earth could withstand the intense heat (100,000,000°C and above) that the plasma has to reach so that fusion can begin. It’s close to 10 times the heat at the Sun’s core, and temperatures like that are needed in a tokamak because the gravitational pressure within the Sun can’t be recreated.
When atomic nuclei do start to fuse, vast amounts of energy are released. While the experimental reactors currently in operation release that energy as heat, in a fusion reactor power plant, the heat would be used to produce steam that would drive turbines to generate electricity, even as some envision nuclear beyond electricity for industrial heat and fuels.
Tokamaks aren’t the only fusion reactors being tried. Another type of reactor uses lasers to heat and compress a hydrogen fuel to initiate fusion. In August 2021, one such device at the National Ignition Facility, at the Lawrence Livermore National Laboratory in California, generated 1.35 megajoules of energy. This record-breaking figure brings fusion power a step closer to net energy gain, but most hopes are still pinned on tokamak reactors rather than lasers.
In June 2021, China’s Experimental Advanced Superconducting Tokamak (EAST) reactor maintained a plasma for 101 seconds at 120,000,000°C. Before that, the record was 20 seconds. Ultimately, a fusion reactor would need to sustain the plasma indefinitely – or at least for eight-hour ‘pulses’ during periods of peak electricity demand.
A real game-changer for tokamaks has been the magnets used to produce the magnetic field. “We know how to make magnets that generate a very high magnetic field from copper or other kinds of metal, but you would pay a fortune for the electricity. It wouldn’t be a net energy gain from the plant,” says Luce.
One route for nuclear fusion is to use atoms of deuterium and tritium, both isotopes of hydrogen. They fuse under incredible heat and pressure, and the resulting products release energy as heat
The solution is to use high-temperature, superconducting magnets made from superconducting wire, or ‘tape’, that has no electrical resistance. These magnets can create intense magnetic fields and don’t lose energy as heat.
“High temperature superconductivity has been known about for 35 years. But the manufacturing capability to make tape in the lengths that would be required to make a reasonable fusion coil has just recently been developed,” says Luce. One of ITER’s magnets, the central solenoid, will produce a field of 13 tesla – 280,000 times Earth’s magnetic field.
The inner walls of ITER’s vacuum vessel, where the fusion will occur, will be lined with beryllium, a metal that won’t contaminate the plasma much if they touch. At the bottom is the divertor that will keep the temperature inside the reactor under control.
“The heat load on the divertor can be as large as in a rocket nozzle,” says Luce. “Rocket nozzles work because you can get into orbit within minutes and in space it’s really cold.” In a fusion reactor, a divertor would need to withstand this heat indefinitely and at ITER they’ll be testing one made out of tungsten.
Meanwhile, in the US, the National Spherical Torus Experiment – Upgrade (NSTX-U) fusion reactor will be fired up in the autumn of 2022, while efforts in advanced fission such as a mini-reactor design are also progressing. One of its priorities will be to see whether lining the reactor with lithium helps to keep the plasma stable.
Choosing a fuel Instead of just using deuterium as the fusion fuel, ITER will use deuterium mixed with tritium, another hydrogen isotope. The deuterium-tritium blend offers the best chance of getting significantly more power out than is put in. Proponents of fusion power say one reason the technology is safe is that the fuel needs to be constantly fed into the reactor to keep fusion happening, making a runaway reaction impossible.
Deuterium can be extracted from seawater, so there’s a virtually limitless supply of it. But only 20kg of tritium are thought to exist worldwide, so fusion power plants will have to produce it (ITER will develop technology to ‘breed’ tritium). While some radioactive waste will be produced in a fusion plant, it’ll have a lifetime of around 100 years, rather than the thousands of years from fission.
At the time of writing in September, researchers at the Joint European Torus (JET) fusion reactor in Oxfordshire were due to start their deuterium-tritium fusion reactions. “JET will help ITER prepare a choice of machine parameters to optimise the fusion power,” says Dr Joelle Mailloux, one of the scientific programme leaders at JET. These parameters will include finding the best combination of deuterium and tritium, and establishing how the current is increased in the magnets before fusion starts.
The groundwork laid down at JET should accelerate ITER’s efforts to accomplish net energy gain. ITER will produce ‘first plasma’ in December 2025 and be cranked up to full power over the following decade. Its plasma temperature will reach 150,000,000°C and its target is to produce 500 megawatts of fusion power for every 50 megawatts of input heating power.
“If ITER is successful, it’ll eliminate most, if not all, doubts about the science and liberate money for technology development,” says Luce. That technology development will be demonstration fusion power plants that actually produce electricity, where advanced reactors can build on decades of expertise. “ITER is opening the door and saying, yeah, this works – the science is there.”
PG&E Public Safety Power Shutoff reduces wildfire risk during extreme winds, triggering de-energization across the North Bay and Sierra Foothills under red flag warnings, with safety inspections and staged restoration to improve grid resilience.
Key Points
A utility protocol to de-energize lines during extreme fire weather, reducing ignition risks and improving grid safety.
✅ Triggered by red flag warnings, humidity, wind, terrain
✅ Temporary de-energization of transmission and distribution lines
✅ Inspections precede phased restoration to minimize wildfire risk
PG&E purposefully shut off electricity to nearly 60,000 Northern California customers Sunday night, aiming to mitigate wildfire risks from power lines during extreme winds.
Pacific Gas and Electric planned to restore power to 70 percent of affected customers in the North Bay and Sierra Foothills late Monday night. As crews inspect lines for safety by helicopter, vehicles and on foot, the remainder will have power sometime Tuesday.
While it was the first time the company shut off power for public safety, PG&E announced its criteria and procedures for such an event in June, said spokesperson Paul Doherty. After wildfires devastated Northern California's wine country last October, he added, PG&E developed its community wildfire safety program division to make power grids and communities more resilient, and prepares for winter storm season through enhanced local response.
Two sagging PG&E power lines caused one of those wildfires during heavy winds, killing four people and injuring a firefighter, the California Department of Forestry and Fire Protection determined earlier this month. Trees or tree branches hitting PG&E power lines started another four wildfires in October 2017. Altogether, the power company has been blamed for igniting 13 wildfires last year.
"We're adapting our electric system our operating practices to improve safety and reliability," Doherty said of the safety program. "That's really the bottom line for us."
Turning off power to so many customers was a "last resort given the extreme fire danger conditions these communities are experiencing," Pat Hogan, senior vice president of electric operations, said in a statement. Conditions that led the company to shut off power included the National Weather Service's red flag fire warnings, humidity levels, sustained winds, temperature, dry fuel and local terrain, Doherty said, amid possible rolling blackouts during grid strain.
The company de-energized more than 78 miles of transmission lines and more than 2,150 miles of distribution power lines Sunday night. Many schools in the area were closed Monday because of the planned power outage, highlighting unequal access to electricity across communities.
Late Saturday and early Sunday, PG&E warned 97,000 customers in 12 counties that the shut off might go into effect. Through automated calls, texts and emails, the company encouraged customers to have drinking water, canned food, flashlights, prescriptions and baby supplies on hand.
Power was also turned off in Southern California on Monday.
San Diego Gas & Electric turned off service to about 360 customers near Cleveland National Forest, where multiple fires have scorched large swaths of land in recent years.
SDG&E has pre-emptively shut off power to customers in the past, most recently in December when 14,000 customers went without power.
Southern California Edison, the primary electric provider across Southern California — including Los Angeles — has a similar power shutoff program. As of Monday night, SCE had yet to turn off power in any of its service areas, a spokesperson told USA TODAY.
Gaza Power Plant Shutdown underscores the Gaza Strip's fuel ban, Israeli blockade, and electricity crisis, cutting megawatts, disrupting hospitals and quarantine centers, and exposing fragile energy supply, GEDCO warnings, and public health risks.
Key Points
An abrupt halt of Gaza's sole power plant due to a fuel ban, deepening the electricity crisis and straining hospitals.
✅ Israeli fuel ban halts Gaza's only power plant
✅ Available supply drops far below 500 MW demand
✅ Hospitals and COVID-19 quarantine centers at risk
The only electricity plant in the Gaza Strip shut down yesterday after running out of fuel banned from entering the besieged enclave by the Israeli occupation, Gaza Electricity Distribution Company announced.
“The power plant has shut down completely,” the company said in a brief statement, as disruptions like China power cuts reveal broader grid vulnerabilities.
Israel banned fuel imports into Gaza as part of punitive measures over the launching incendiary balloons from the Strip.
On Sunday, GEDCO warned that the industrial fuel for the electricity plant would run out, mirroring Lebanon's fuel shortage challenges, on Tuesday morning.
Since 2007, the Gaza Strip suffered under a crippling Israeli blockade that has deprived its roughly two million inhabitants of many vital commodities, including food, fuel and medicine, and regional strains such as Iraq's summer electricity needs highlight broader power insecurity.
The Gaza Strip needs some 500 megawatts of electricity – of which only 180 megawatts are currently available – to meet the needs of its population, while Iran supplies about 40% of Iraq's electricity in the region.
Spokesman of the Ministry of Health in Gaza, Ashraf Al Qidra, said the lack of electricity undermines offering health services across Gaza’s hospitals.
He also warned that the lack of electricity would affect the quarantine centres used for coronavirus patients, reinforcing the need to keep electricity options open during the pandemic.
Gaza currently has three sources of electricity: Israel, which provides 120 megawatts and is advancing coal use reduction measures; Egypt, which supplies 32 megawatts; and the Strip’s sole power plant, which generates between 40 and 60 megawatts.
Canada Clean Electricity Standard targets a net-zero grid by 2035, using carbon pricing, CO2 caps, and carbon capture while expanding renewables and interprovincial trade to decarbonize power in Alberta, Saskatchewan, and Ontario.
Key Points
A federal plan to reach a net-zero grid by 2035 using CO2 caps, carbon pricing, carbon capture, renewables, and trade.
✅ CO2 caps and rising carbon prices through 2050
✅ Carbon capture required on gas plants in high-emitting provinces
✅ Renewables build-out and interprovincial trade to balance supply
A new tool has been proposed in the federal election campaign as a way of eradicating the carbon emissions from Canada’s patchwork electricity system.
As the country’s need for power grows through the decarbonization of transportation, industry and space heating, the Liberal Party climate plan is proposing a clean energy standard to help Canada achieve a 100% net-zero-electricity system by 2035, aligning with Canada’s net-zero by 2050 target overall.
The proposal echoes a report released August 19 by the David Suzuki Foundation and a group of environmental NGOs that also calls for a clean electricity standard, capping power-sector emissions, and tighter carbon-pricing regulations. The report, written by Simon Fraser University climate economist Mark Jaccard and data analyst Brad Griffin, asserts that these policies would effectively decarbonize Canada’s electricity system by 2035.
“Fuel switching from dirty fossil fuels to clean electricity is an essential part of any serious pathway to transition to a net-zero energy system by 2050,” writes Tom Green, climate policy advisor to the Suzuki Foundation, in a foreword to the report. The pathway to a net-zero grid is even more important as Canada switches from fossil fuels to electric vehicles, space heating and industrial processes, even as the Canadian Gas Association warns of high transition costs.
Under Jaccard and Griffin’s proposal, a clean electricity standard would be established to regulate CO2 emissions specifically from power plants across Canada. In addition, the plan includes an increase in the carbon price imposed on electricity system releases, combined with tighter regulation to ensure that 100% of the carbon price set by the federal government is charged to electricity producers. The authors propose that the current scheduled carbon price of $170 per tonne of CO2 in 2030 should rise to at least $300 per tonne by 2050.
In Alberta, Saskatchewan, Ontario, New Brunswick and Nova Scotia, the 2030 standard would mean that all fossil-fuel-powered electricity plants would require carbon capture in order to comply with the standard. The provinces would be given until 2035 to drop to zero grams CO2 per kilowatt hour, matching the 2030 standard for low-carbon provinces (Quebec, British Columbia, Manitoba, Newfoundland and Labrador and Prince Edward Island).
Alberta and Saskatchewan targeted Canada has a relatively clean electricity system, as shown by nationwide progress in electricity, with about 80% of the country’s power generated from low- or zero-emission sources. So the biggest impacts of the proposal will be felt in the higher-carbon provinces of Alberta and Saskatchewan. Alberta has a plan to switch from coal-based electric power to natural gas generation by 2023. But Saskatchewan is still working on its plan. Under the Jaccard-Griffin proposal, these provinces would need to install carbon capture on their gas-fired plants by 2030 and carbon-negative technology (biomass with carbon capture, for instance) by 2035. Saskatchewan has been operating carbon capture and storage technology at its Boundary Dam power station since 2014, but large-scale rollout at power plants has not yet been achieved in Canada.
With its heavy reliance on nuclear and hydro generation, Ontario’s electricity supply is already low carbon. Natural gas now accounts for about 7% of the province’s grid, but the clean electricity standard could pose a big challenge for the province as it ramps up natural-gas-generated power to replace electricity from its aging Pickering station, scheduled to go out of service in 2025, even as a fully renewable grid by 2030 remains a debated goal. Pickering currently supplies about 14% of Ontario’s power.
Ontario doesn’t have large geological basins for underground CO2 storage, as Alberta and Saskatchewan do, so the report says Ontario will have to build up its solar and wind generation significantly as part of Canada’s renewable energy race, or find a solution to capture CO2 from its gas plants. The Ontario Clean Air Alliance has kicked off a campaign to encourage the Ontario government to phase out gas-fired generation by purchasing power from Quebec or installing new solar or wind power.
As the report points out, the federal government has Supreme Court–sanctioned authority to impose carbon regulations, such as a clean electricity standard, and carbon pricing on the provinces, with significant policy implications for electricity grids nationwide.
The federal government can also mandate a national approach to CO2 reduction regardless of fuel source, encouraging higher-carbon provinces to work with their lower-carbon neighbours. The Atlantic provinces would be encouraged to buy power from hydro-heavy Newfoundland, for example, while Ontario would be encouraged to buy power from Quebec, Saskatchewan from Manitoba, and Alberta from British Columbia.
The Canadian Electricity Association, the umbrella organization for Canada’s power sector, did not respond to a request for comment on the Jaccard-Griffin report or the Liberal net-zero grid proposal.
Just how much more clean power will Canada need? The proposal has also kicked off a debate, and an IEA report underscores rising demand, about exactly how much additional electricity Canada will need in coming decades.
In his 2015 report, Pathways to Deep Decarbonization in Canada, energy and climate analyst Chris Bataille estimated that to achieve Canada’s climate net-zero target by 2050 the country will need to double its electricity use by that year.
Jaccard and Griffin agree with this estimate, saying that Canada will need more than 1,200 terawatt hours of electricity per year in 2050, up from about 640 terawatt hours currently.
But energy and climate consultant Ralph Torrie (also director of research at Corporate Knights) disputes this analysis.
He says large-scale programs to make the economy more energy efficient could substantially reduce electricity demand. A major program to install heat pumps and replace inefficient electric heating in homes and businesses could save 50 terawatt hours of consumption on its own, according to a recent report from Torrie and colleague Brendan Haley.
Put in context, 50 terawatt hours would require generation from 7,500 large wind turbines. Applied to electric vehicle charging, 50 terawatt hours could power 10 million electric vehicles.
While Torrie doesn’t dispute the need to bring the power system to net-zero, he also doesn’t believe the “arm-waving argument that the demand for electricity is necessarily going to double because of the electrification associated with decarbonization.”
