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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.” 

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Power-to-gas converts surplus renewable electricity into green hydrogen or synthetic methane via electrolysis and methanation, enabling seasonal energy storage, grid balancing, hydrogen injection into gas pipelines, and decarbonization of heat, transport, and industry.

Key Points

Power-to-gas turns excess renewable power into hydrogen or methane for storage, grid support, and clean fuel.

✅ Enables hydrogen injection into existing natural gas networks

✅ Balances grids and provides seasonal energy storage capacity

✅ Supplies low-carbon fuels for industry, heat, and heavy transport

Last month Denmark’s biggest energy firm, Ørsted, said wind farms it is proposing for the North Sea will convert some of their excess power into gas. Electricity flowing in from offshore will feed on-shore electrolysis plants that split water to produce clean-burning hydrogen, with oxygen as a by-product. That would supply a new set of customers who need energy, but not as electricity. And it would take some strain off of Europe’s power grid as it grapples with an ever-increasing share of hard-to-handle EU wind and solar output on the grid.

Turning clean electricity into energetic gases such as hydrogen or methane is an old idea that is making a comeback as renewable power generation surges and crowds out gas in Europe. That is because gases can be stockpiled within the natural gas distribution system to cover times of weak winds and sunlight. They can also provide concentrated energy to replace fossil fuels for vehicles and industries. Although many U.S. energy experts argue that this “power-to-gas” vision may be prohibitively expensive, some of Europe’s biggest industrial firms are buying in to the idea.

European power equipment manufacturers, anticipating a wave of renewable hydrogen projects such as Ørsted’s, vowed in January that, as countries push for hydrogen-ready power plants across Europe, all of their gas-fired turbines will be certified by next year to run on up to 20 percent hydrogen, which burns faster than methane-rich natural gas. The natural gas distributors, meanwhile, have said they will use hydrogen to help them fully de-carbonize Europe’s gas supplies by 2050.

Converting power to gas is picking up steam in Europe because the region has more consistent and aggressive climate policies and evolving electricity pricing frameworks that support integration. Most U.S. states have goals to clean up some fraction of their electricity supply; coal- and gas-fired plants contribute a little more than a quarter of U.S. greenhouse gas emissions. In contrast, European countries are counting on carbon reductions of 80 percent or more by midcentury—reductions that will require an economywide switch to low-carbon energy.

Cleaning up energy by stripping the carbon out of fossil fuels is costly. So is building massive new grid infrastructure, including transmission lines and huge batteries, amid persistent grid expansion woes in parts of Europe. Power-to-gas may be the cheapest way forward, complementing Germany’s net-zero roadmap to cut electricity costs by a third. “In order to reach the targets for climate protection, we need even more renewable energy. Green hydrogen is perceived as one of the most promising ways to make the energy transition happen,” says Armin Schnettler, head of energy and electronics research at Munich-based electric equipment giant Siemens.

Europe already has more than 45 demonstration projects to improve power-to-gas technologies and their integration with power grids and gas networks. The principal focus has been to make the electrolyzers that convert electricity to hydrogen more efficient, longer-lasting and cheaper to produce.

The projects are also scaling up the various technologies. Early installations converted a few hundred kilowatts of electricity, but manufacturers such as Siemens are now building equipment that can convert 10 megawatts, which would yield enough hydrogen each year to heat around 3,000 homes or fuel 100 buses, according to financial consultancy Ernst & Young.

The improvements have been most dramatic for proton-exchange membrane electrolyzers, which are akin to the fuel cells used in hydrogen vehicles (but optimized to produce hydrogen rather than consume it). The price of proton-exchange electrolyzers has dropped by roughly 40 percent during the past decade, according to a study published in February in Nature Energy. They are also five times more compact than older alkaline electrolysis plants, enabling onsite hydrogen production near gas consumers, and they can vary their power consumption within seconds to operate on fluctuating wind and solar generation.

Many European pilot projects are demonstrating “methanation” equipment that converts hydrogen to methane, too, which can be used as a drop-in replacement for natural gas. Europe’s electrolyzer plants, however, are showing that methanation is not as critical to the power-to-gas vision as advocates long believed. Many electrolyzers are injecting their hydrogen directly into natural gas pipelines—something that U.S. gas firms forbid—and they are doing so without impacting either the gas infrastructure or natural gas consumers.

Europe’s first large-scale hydrogen injection began in eastern Germany in 2013 at a two-megawatt electrolyzer installed by Essen-based power firm E.ON. Germany has since ratcheted up the amount of hydrogen it allows in natural gas lines from an initial 2 percent by volume to 10 percent, in a market where renewables now outpace coal and nuclear in Germany, and other European states have followed suit with their own hydrogen allowances. Christopher Hebling, head of hydrogen technologies at the Freiburg-based Fraunhofer Institute for Solar Energy Systems, predicts that such limits will rise to the 20-percent level anticipated by Europe’s turbine manufacturers.

Moving renewable hydrogen and methane via natural gas pipelines promises to cut the cost of switching to renewable energy. For example, gas networks have storage caverns whose reserves could be tapped to run gas-fired electric generation power plants during periods of low wind and solar output. Hebling notes that Germany’s gas network can store 240 terawatt-hours of energy—roughly 25 times more energy than global power grids can presently store by pumping water uphill to refill hydropower reservoirs. Repurposing gas infrastructure to help the power system could save European consumers 138 billion euros ($156 billion) by 2050, according to Dutch energy consultancy Navigant (formerly Ecofys).

For all the pilot plants and promise, renewable hydrogen presently supplies a tiny fraction of Europe’s gas. And, globally, around 4 percent of hydrogen is supplied via electrolysis, with the bulk refined from fossil fuels, according to the International Renewable Energy Agency.

Power-to-gas is catching up, however. According to the February Nature Energy study, renewable hydrogen already pays for itself in some niche applications, and further electrolyzer improvements will progressively extend its market. “If costs continue to decline as they have done in recent years, power-to-gas will become competitive at large scale within the next decade,” says study co-author Gunther Glenk, an economist at the Technical University of Munich.

Glenk says power-to-gas could scale up faster if governments guaranteed premium prices for renewable hydrogen and methane, as they did to mainstream solar and wind power.

Tim Calver, an energy storage researcher turned consultant and Ernst & Young’s executive director in London, agrees that European governments need to step up their support for power-to-gas projects and markets. Calver calls the scale of funding to date, “not proportionate to the challenge that we face on long-term decarbonization and the potential role of hydrogen.”

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Maritime Link HVDC Transmission connects Newfoundland and Nova Scotia to the North American grid, enabling renewable energy imports, subsea cable interconnection, Muskrat Falls hydro power delivery, and lower carbon emissions across Atlantic Canada.

Key Points

A 500 MW HVDC intertie linking Newfoundland and Nova Scotia to deliver Muskrat Falls hydro power.

✅ 500 MW capacity using twin 170 km subsea HVDC cables

✅ Interconnects Newfoundland and Nova Scotia to the North American grid

✅ Enables Muskrat Falls hydro imports, cutting CO2 and costs

For the first time, electricity has been sent between Newfoundland and Nova Scotia through the new Maritime Link.

The 500-megawatt transmission line — which connects Newfoundland to the North American energy grid for the first time and echoes projects like the New England Clean Power Link underway — was tested Friday.

"This changes not only the energy options for Newfoundland and Labrador but also for Nova Scotia and Atlantic Canada," said Rick Janega, the CEO of Emera Newfoundland and Labrador, which owns the link.

"It's an historic event in our eyes, one that transforms the electricity system in our region forever."

'On time and on budget'

It will eventually carry power from the Muskrat Falls hydro project in Labrador, where construction is running two years behind schedule and $4 billion over budget, a context in which the Manitoba Hydro line to Minnesota has also faced delay, to Nova Scotia consumers. It was supposed to start producing power later this year, but the new deadline is 2020 at the earliest.

The project includes two 170-kilometre subsea cables across the Cabot Strait between Cape Ray in southwestern Newfoundland and Point Aconi in Cape Breton.

The two cables, each the width of a two-litre pop bottle, can carry 250 megawatts of high voltage direct current, and rest on the ocean floor at depths up to 470 metres.

This reel of cable arrived in St. John's back in April aboard the Norwegian vessel Nexans Skagerrak, after the first power cable reached Nova Scotia earlier in the project. (Submitted by Emera NL)

The Maritime Link also includes almost 50 kilometres of overland transmission in Nova Scotia and more than 300 kilometres of overland transmission in Newfoundland, paralleling milestones on Site C transmission work in British Columbia.

The link won't go into commercial operation until January 1.

Janega said the $1.6-billion project is on time and on budget.

"We're very pleased to be in a position to be able to say that after seven years of working on this. It's quite an accomplishment," he said.

This Norwegian vessel was used to transport the 5,500 tonne subsea cable. (Submitted by Emera NL)

Once in service, the link will improve electrical interconnections between the Atlantic provinces, aligning with climate adaptation guidance for Canadian utilities.

"For Nova Scotia it will allow it to achieve its 40 per cent renewable energy target in 2020. For Newfoundland it will allow them to shut off the Holyrood generating station, in fact using the Maritime Link in advance of the balance of the project coming into service," Janega said.

Karen Hutt, president and CEO of Nova Scotia Power, which is owned by Emera Inc., calls it a great day for Nova Scotia.

"When it goes into operation in January, the Maritime Link will benefit Nova Scotia Power customers by creating a more stable and secure system, helping reduce carbon emissions, and enabling NSP to purchase power from new sources," Hutt said in a statement.

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Zaporizhzhia Nuclear Plant Restart signals new high-voltage transmission lines to Mariupol, Rosatom grid integration, and IAEA-monitored safety amid occupied territory risks, cooling system shortfalls after the Kakhovka dam collapse, and disputed international law.

Key Points

A Russian plan to reconnect and possibly restart ZNPP via power lines, despite IAEA safety, cooling, and legal risks.

✅ 80 km high-voltage link toward Mariupol confirmed by imagery

✅ IAEA warns of safety risks and militarization at the site

✅ Cooling capacity limited after Kakhovka dam destruction

Russia is actively constructing new power lines to facilitate the restart of the Zaporizhzhia Nuclear Power Plant (ZNPP), Europe's largest nuclear facility, which it seized from Ukraine in 2022. Satellite imagery analyzed by Greenpeace indicates the construction of approximately 80 kilometers (50 miles) of high-voltage transmission lines and pylons connecting the plant to the Russian-controlled port city of Mariupol. This development marks the first tangible evidence of Russia's plan to reintegrate the plant into its energy infrastructure.

Strategic Importance of Zaporizhzhia Nuclear Power Plant

The ZNPP, located on the eastern bank of the Dnipro River in Enerhodar, was a significant asset in Ukraine's energy sector before its occupation. Prior to the war, the plant was connected to Ukraine's national grid, which later saw resumed electricity exports, via four 750-kilovolt lines, two of which passed through Ukrainian-controlled territory and two through areas under Russian control. The ongoing conflict has damaged these lines, complicating efforts to restore the plant's operations.

In March 2022, Russian forces captured the plant, and by 2023, all six of its reactors had been shut down. Despite this, Russian authorities have expressed intentions to restart the facility. Rosatom, Russia's state nuclear corporation, has identified replacing the power grid as one of the critical steps necessary for resuming operations, even as Ukraine pursues more resilient wind power to bolster its energy mix.

Environmental and Safety Concerns

The construction of new power lines and the potential restart of the ZNPP have raised significant environmental and safety concerns, as the IAEA has warned of nuclear risks from grid attacks in recent assessments. Greenpeace has reported that the plant's cooling system has been compromised due to the destruction of the Kakhovka Reservoir dam in 2023, which previously supplied cooling water to the plant. Currently, the plant relies on wells for cooling, which are insufficient for full-scale operations.

Additionally, the International Atomic Energy Agency (IAEA) has expressed concerns about the militarization of the plant. Reports indicate that Russian forces have established defensive positions and trenches around the facility, with mines found at ZNPP by UN inspectors, raising the risk of accidents and complicating efforts to ensure the plant's safety.

International Reactions and Legal Implications

Ukraine and the international community have condemned Russia's actions as violations of international law and Ukrainian sovereignty. Ukrainian officials have argued that the construction of power lines and the potential restart of the ZNPP constitute illegal activities in occupied territory. The IAEA has called for a ceasefire to allow for necessary safety improvements and to facilitate inspections of the plant, as a possible agreement on power plant attacks could underpin de-escalation efforts.

The United States has also expressed concerns, with President Donald Trump reportedly proposing the inclusion of the ZNPP in peace negotiations, which sparked controversy among Ukrainian and international observers, even suggesting the possibility of transferring control to American companies. However, Russia has rejected such proposals, reaffirming its intention to maintain control over the facility.

The construction of new power lines to the Zaporizhzhia Nuclear Power Plant signifies Russia's commitment to reintegrating the facility into its energy infrastructure. However, this move raises significant environmental, safety, and legal concerns, and a proposal to control Ukraine's nuclear plants remains controversial among stakeholders. The international community continues to monitor the situation closely, urging for adherence to international laws and standards to prevent potential nuclear risks.

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Alaska Coal-Fired CHP Plant opens near Usibelli mine, supplying electricity and district heat to UAF; remote location without gas pipelines, low wind and solar potential, and high heating demand shaped fuel choice.

Key Points

A 17 MW coal CHP at UAF producing power and campus heat, chosen for remoteness and lack of gas pipelines.

✅ 17 MW generator supplying electricity and district heat

✅ Near Usibelli mine; limited pipeline access shapes fuel

✅ Alternative options like LNG, wind, solar not cost-effective

One way to boost coal in the US: Find a spot near a mine with no access to oil or natural gas pipelines, where it’s not particularly windy and it’s dark much of the year.

That’s how the first coal-fired plant to open in the U.S. since 2015 bucked the trend in an industry that’s seen scores of facilities close in recent years. A 17-megawatt generator, built for $245 million, is set to open in April at the University of Alaska Fairbanks, just 100 miles from the state’s only coal mine.

“Geography really drove what options are available to us,” said Kari Burrell, the university’s vice chancellor for administrative services, in an interview. “We are not saying this is ideal by any means.”

The new plant is arriving as coal fuels about 25 percent of electrical generation in the U.S., down from 45 percent a decade earlier, even as some forecasts point to a near-term increase in coal-fired generation in 2021. A near-record 18 coal plants closed in 2018, and 14 more are expected to follow this year, according to BloombergNEF.

The biggest bright spot for U.S. coal miners recently has been exports to overseas power plants. At home, one of the few growth areas has been in pizza ovens.

There are a handful of other U.S. coal power projects that have been proposed, including plans to build an 850 megawatt facility in Georgia and an 895 megawatt plant in Kansas, even as a Minnesota utility reports declining coal returns across parts of its portfolio. But Ashley Burke, a spokeswoman for the National Mining Association, said she’s unaware of any U.S. plants actively under development besides the one in Alaska.

Future of power

“The future of power in the U.S. does not include coal,” Tessie Petion, an analyst for HSBC Holdings Plc, said in a research note, a view echoed by regions such as Alberta retiring coal power early in their transition.

Fairbanks sits on the banks of the Chena River, amid the vast subarctic forests in the heart of Alaska. The oil and gas fields of the state’s North slope are 500 miles north. The nearest major port is in Anchorage, 350 miles south.

The university’s new plant is a combined heat and power generator, which will create steam both to generate electricity and heat campus buildings. Before opting for coal, the school looked into using liquid natural gas, wind and solar, bio-mass and a host of other options, as new projects in Southeast Alaska seek lower electricity costs across the region. None of them penciled out, said Mike Ruckhaus, a senior project manager at the university.

The project, financed with university and state-municipal bonds, replaces a coal plant that went into service in 1964. University spokeswoman Marmian Grimes said it’s worth noting that the new plant will emit fewer emissions.

The coal will come from Usibelli Coal Mine Inc., a family-owned business that produces between 1.2 and 2 million tons per year from a mine along the Alaska railroad, according to the company’s website.

While any new plant is good news for coal miners, Clarksons Platou Securities Inc. analyst Jeremy Sussman said this one is "an isolated situation."

“We think the best producers can hope for domestically is a slow down in plant closures,” he said, even as jurisdictions like Alberta close their last coal plant entirely.

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CPUC Decision on San Diego Community Power directs SDG&E to use updated forecasts, stabilizing electricity rates for CCA customers and supporting clean energy in San Diego with accurate rate forecasting and reduced volatility.

Key Points

A CPUC ruling directing SDG&E to use updated forecasts to ensure accurate, stable CCA rates and limit volatility.

✅ Uses 2021 sales forecasts for rate setting

✅ Aims to prevent undercollection and bill spikes

✅ Levels changes across customer classes

The California Public Utilities Commission on Thursday sided with the soon-to-launch San Diego community energy program in a dispute it had with San Diego Gas & Electric.

San Diego Community Power — which will begin to purchase power for customers in San Diego, Chula Vista, La Mesa, Encinitas and Imperial Beach later this year — had complained to the commission that data SDG&E intended to use to calculate rates, including community choice exit fees that could make the new energy program less attractive to prospective customers.

SDG&E argued it was using numbers it was authorized to employ as part of a general rate case amid a potential rate structure revamp that is still being considered by the commission.

But in a 4-0 vote, the commission, or CPUC, sided with San Diego Community Power and directed SDG&E to use an updated forecast for energy sales.

"This was not an easy decision," said CPUC president Marybel Batjer at the meeting, held remotely due to COVID-19 restrictions. "In my mind, this outcome best accounts for the shifting realities ... in the San Diego area while minimizing the impact on ratepayers during these difficult financial times."

In filings to the commission, SDG&E predicted a rate decrease of 12.35 percent in the coming year. While that appears to be good news for customers, Californians still face soaring electricity prices statewide, Commissioner Martha Guzman Aceves said the data set SDG&E wanted to use would lead to an undercollection of $150 million to $260 million.

That would result in rates that would be "artificially low," Guzman Aceves said, and rates "would inevitably go up quite a bit after the undercollection was addressed."

San Diego Community Power, or SDCP, said the temporary reduction would make its rates less attractive than SDG&E's, especially amid SDG&E's minimum charge proposal affecting low-usage customers, just as it is about to begin serving customers. SDCP's board members wrote an open letter last month to the commission, accusing the utility of "willful manipulation of data."

Working with an administrative law judge at the CPUC, Guzman Aceves authored a proposal requiring SDG&E to use numbers based on 2021 forecasts, as regulators simultaneously weigh whether the state needs more power plants to ensure reliability. The utility argued that could result in an increase of "roughly 40 percent" for medium and large commercial and industrial customers this year.

To help reduce potential volatility, Guzman Aceves, SDCP and other community energy supporters called for using a formula that would average out changes in rates across customer classes amid debates over income-based utility charges statewide. That's what the commissioners OK'd Thursday.

"It is essential that customer commodity rates be as accurate as we can possibly get them to avoid undercollections," said Commissioner Genevieve Shiroma.

San Diego Community Power is one of 23 community choice aggregation, or CCA, energy programs that have launched in California in the past decade.

CCAs compete with traditional power companies amid California's evolving power competition landscape, in one important role — purchasing power for a given community. They were created to boost the use of cleaner energy sources, such as wind and solar, at rates equal to or lower than investor-owned utilities.

However, CCAs do not replace utilities because the incumbent power companies still perform all of the tasks outside of power purchasing, such as transmission and distribution of energy and customer billing.

When a CCA is formed, California rules stipulate the utility customers in that area are automatically enrolled in the CCA. If customers prefer to stay with their previous power company, they can opt out of joining the CCA.

The shift of customers from SDG&E to San Diego Community Power is expected to be large. The total number of accounts for SDCP is expected to be 770,000, which would make it the second-largest CCA in the state. That's why SDCP considered Thursday's CPUC decision to be so important.

"At a time when customers are choosing between sticking with San Diego Gas & Electric and migrating to a CCA, we want them to have accurate bill information," said Commissioner Clifford Rechtschaffen.

"SDCP is very happy with today's CPUC decision, and that the commissioners shared our goal of limiting rate volatility for businesses and families in the region," said SDCP interim CEO Bill Carnahan. "This is definitely a win for accurate rate forecasting, and our mutual customers, and we look forward to working with SDG&E on next steps."

In an email, SDG&E spokeswoman Helen Gao said, "We are committed to continuing to work collaboratively with local Community Choice Aggregation programs to support their successful launch in 2021 and ensure that our mutual customers receive excellent customer service."

San Diego Community Power's case before the CPUC was joined by the California Community Choice Association, a trade group advocating for CCAs, and the Clean Energy Alliance — the North County-based CCA representing Del Mar, Solana Beach and Carlsbad that is scheduled to launch this summer.

SDCP will begin its rollout this year, folding in about 71,000 municipal, commercial and industrial accounts. The bulk of its roughly 700,000 residential accounts is expected to come in January 2022.

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