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Alberta Energy Price Spike signals rising electricity and natural gas costs; lock in fixed rates as storage is low, demand surged in heat waves, and exports rose after Hurricane Ida, driving volatility and higher futures.

Key Points

An anticipated surge in Alberta electricity and natural gas prices, urging consumers to lock fixed rates to reduce risk.

✅ Fixed-rate gas near $3.79/GJ vs futures approaching $6/GJ

✅ Low storage after heat waves and U.S. export demand

✅ Switch providers or plans; UCA comparison tool helps

Energy economists are warning Albertans to review their gas and electricity bills and lock in a fixed rate if they haven't already done so because prices are expected to spike in the coming months.

"I have been urging anyone who will listen that every single Albertan should be on a fixed rate for this winter," University of Calgary energy economist Blake Shaffer said Monday. "And I say that for both natural gas and power."

Shaffer said people will rightly point out energy costs make up only roughly a third of their monthly bill. The rest of the costs for such things as delivery fees can't be avoided. 

But, he said, "there is an energy component and it is meaningful in terms of savings." 

For example, Shaffer said, when he checked last week, a consumer could sign a fixed rate gas contract for $3.79 a gigajoule and the current future price for gas is nearly $6 a gigajoule.

A typical household would use about 15 gigajoules a month, he said, so a consumer could save $30 to $45 a month for five months. For people on lower or fixed incomes, "that is a pretty significant saving."

Comparable savings can also be achieved with electricity, he said.

Shaffer said research has shown households that are least able to afford sharp increases in gas and electrical bills are less likely to pick up the phone and call their energy provider and either negotiate a lower fixed rate contract or jump to a new provider. 

But, he said, it is definitely worth the time and effort, particularly as Calgary electricity bills are rising across the city. Alberta's Utilities Consumer Advocate has a handy cost comparison tool on its website that allows consumers to conduct regional price comparisons that will assist in making an informed decision.

"Folks should know that for most providers you can change back to a floating rate any time you want," Shaffer said.

Summer heat wave affected natural gas supply
Why are energy prices set to spike in Alberta, which is a major producer of natural gas?

Sophie Simmonds, managing director of the brokerage firm Anova Energy, said Alberta is now generating the majority of its power using natural gas. 

The heat wave in June and July created record electrical demand. Normally, natural gas is stored in the summer for use in the winter. But this year, there was much greater gas consumption in the summer and so less was stored. 

Alberta also set a new electricity usage record during a recent deep freeze, underscoring system stress.

On top of that, Alberta has been exporting much more natural gas to the United States since August and September because Hurricane Ida knocked out natural gas assets in the Gulf of Mexico.

"So what this means is we are actually going into winter with very, very low storage numbers," Simmonds said.

Why natural gas prices have surged to some of their highest levels in years
Canadians to remain among world's top energy users even as government strives for net zero
Consultant Matt Ayres said he believes rising electricity prices also are being affected by Alberta's transition from carbon-intensive fuel sources to less carbon-intensive fuel sources.

"That transition is not always smooth," said Ayres, who is also an adjunct assistant professor at the University of Calgary's School of Public Policy. 

"It is my view that at least some of the price increases we are seeing on electricity comes down to difficulties imposed by that transition and also by a reduction in competition amongst generators, as well as power market overhaul debates shaping policy." 

In 2019, under the leadership of Premier Jason Kenney the UCP government removed the former NDP government's rate cap on electricity at the time.

The NDP has called for the government to reinstate the cap but the UCP government has dismissed that as unsustainable and unrealistic.

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Alberta Electricity Market faces energy-only vs capacity debate as transmission, distribution, and administration fees surge; rural rates rise amid a regulated duopoly of investor-owned utilities, prompting calls for competition, innovation, and lower bills.

Key Points

Alberta's electricity market is an energy-only system with rising delivery charges and limited rural competition.

✅ Energy-only design; capacity market scrapped

✅ Delivery charges outpace energy on monthly bills

✅ Rural duopoly limits competition and raises rates

Last week, Alberta’s new Energy Minister Sonya Savage announced the government, through its new electricity rules, would be scrapping plans to shift Alberta’s electricity to a capacity market and would instead be “restoring certainty in the electricity system.”

The proposed transition from energy only to a capacity market is a contentious subject as a market reshuffle unfolds across the province that many Albertans probably don’t know much about. Our electricity market is not a particularly glamorous subject. It’s complicated and confusing and what matters most to ordinary Albertans is how it affects their monthly bills.

What they may not realize is that the cost of their actual electricity used is often just a small fraction of their bill amid rising electricity prices across the province. The majority on an average electricity bill is actually the cost of delivering that electricity from the generator to your house. Charges for transmission, distribution and franchise and administration fees are quickly pushing many Alberta households to the limit with soaring bills.

According to data from Alberta’s Utilities Consumer Advocate (UCA), and alongside policy changes, in 2004 the average monthly transmission costs for residential regulated-rate customers was below $2. In 2018 that cost was averaging nearly $27 a month. The increase is equally dramatic in distribution rates which have more than doubled across the province and range wildly, averaging from as low as $10 a month in 2004 to over $80 a month for some residential regulated-rate customers in 2018.

Where you live determines who delivers your electricity. In Alberta’s biggest cities and a handful of others the distribution systems are municipally owned and operated. Outside those select municipalities most of Alberta’s electricity is delivered by two private companies which operate as a regulated duopoly. In fact, two investor-owned utilities deliver power to over 95 per cent of rural Alberta and they continue to increase their share by purchasing the few rural electricity co-ops that remained their only competition in the market. The cost of buying out their competition is then passed on to the customers, driving rates even higher.

As the CEO of Alberta’s largest remaining electricity co-op, I know very well that as the price of materials, equipment and skilled labour increase, the cost of operating follows. If it costs more to build and maintain an electricity distribution system there will inevitably be a cost increase passed on to the consumer. The question Albertans should be asking is how much is too much and where is all that money going with these private- investor-owned utilities, as the sector faces profound change under provincial leadership?

The reforms to Alberta’s electricity system brought in by Premier Klein in the late 1900s and early 2000s contributed to a surge in investment in the sector and led to an explosion of competition in both electricity generation and retail. 

More players entered the field which put downward pressure on electricity rates, encouraged innovation and gave consumers a competitive choice, even as a Calgary electricity retailer urged the government to scrap the overhaul. But the legislation and regulations that govern rural electricity distribution in Alberta continue to facilitate and even encourage the concentration of ownership among two players which is certainly not in the interests of rural Albertans.

It is also not in the spirit of the United Conservative Party platform commitment to a “market-based” system. A market-based system suggests more competition. Instead, what we have is something approaching a monopoly for many Albertans. The UCP promised a review of the transition to a capacity market that would determine which market would be best for Alberta, and through proposed electricity market changes has decided that we will remain an energy-only market.
Consumers in rural Alberta need electricity to produce the goods that power our biggest industries. Instead of regulating and approving continued rate increases from private multinational corporations, we need to drive competition and innovation that can push rates down and encourage growth and investment in rural-based industries and communities.

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CCUS in the U.S. Power Sector drives investments as DOE grants, 45Q tax credits, and EPA carbon rules spur carbon capture, geologic storage, and utilization, while debates persist over costs, transparency, reliability, and emissions safeguards.

Key Points

CCUS captures CO2 from power plants for storage or use, backed by 45Q tax credits, DOE funding, and EPA carbon rules.

✅ DOE grants and 45Q credits aim to de-risk project economics.

✅ EPA rules may require capture rates to meet emissions limits.

✅ Transparency and MRV guard against tax credit abuse.

New public and private funding, including DOE $110M for CCUS announced recently, and expected strong federal power plant emissions reduction standards have accelerated electricity sector investments in carbon capture, utilization and storage,’ or CCUS, projects but some worry it is good money thrown after bad.

CCUS separates carbon from a fossil fuel-burning power plant’s exhaust through carbon capture methods for geologic storage or use in industrial and other applications, according to the Department of Energy. Fossil fuel industry giants like Calpine and Chevron are looking to take advantage of new federal tax credits and grant funding for CCUS to manage potentially high costs in meeting power plant performance requirements, amid growing investor pressure for climate reporting, including new rules, expected from EPA soon, on reducing greenhouse gas emissions from existing power plants.

Power companies have “ambitious plans” to add CCUS to power plants, estimated to cause 25% of U.S. CO2 emissions. As a result, the power sector “needs CCUS in its toolkit,” said DOE Office of Fossil Energy and Carbon Management Assistant Secretary Brad Crabtree. Successful pilots and demonstrations “will add to investor confidence and lead to more deployment” to provide dispatchable clean energy, including emerging CO2-to-electricity approaches for power system reliability after 2030,| he added.

But environmentalists and others insist potentially cost-prohibitive CCUS infrastructure, including CO2 storage hub initiatives, must still prove itself effective under rigorous and transparent federal oversight.

“The vast majority of long-term U.S. power sector needs can be met without fossil generation, and better options are being deployed and in development,” Sierra Club Senior Advisor, Strategic Research and Development, Jeremy Fisher, said, pointing to carbon-free electricity investments gaining momentum in the market. CCUS “may be needed, but without better guardrails, power sector abuses of federal funding could lead to increased emissions and stranded fossil assets,” he added.

New DOE CCUS project grants, an increased $85 per metric ton, or tonne, federal 45Q tax credit, and the forthcoming EPA power plant carbon rules and the federal coal plan will do for CCUS what similar policies did for renewables, advocates and opponents agreed. But controversial past CCUS performance and tax credit abuses must be avoided with transparent reporting requirements for CO2 capture, opponents added.

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Hydro One-Avista Merger outlines a utility acquisition shaped by Washington regulators, Colstrip coal plant depreciation, and plans for renewables, clean energy, and emissions cuts, while Montana reviews implications for jobs, ratepayers, and a 2027 closure.

Key Points

A utility deal setting Colstrip depreciation and renewables, without committing to an early coal plant closure.

✅ Washington sets 2027 depreciation for Colstrip units

✅ Montana reviews jobs, ratepayer impacts, community fund

✅ Avista seeks renewables; no binding shutdown commitment

The Washington power company Hydro One is buying will be ready to close its huge coal-fired generating station ahead of schedule, thanks to conditions put on the corporate merger by state regulators there.

Not that we actually plan to do that, the company is telling other regulators in Montana, where coal unit retirements are under debate, the huge coal-fired generating station in question employs hundreds of people. We’ll be in the coal business for a good long time yet.

Hydro One, in which the Ontario government now owns a big minority stake, is still working on its purchase of Avista, a private power utility based in Spokane. The $6.7-billion deal, which Hydro One announced in July, includes a 15 per cent share in two of the four generating units in a coal plant in Colstrip, Montana, one of the biggest in the western United States. Avista gets most of its electricity from hydro dams and gas but uses the Colstrip plant when demand for power is high and water levels at its dams are low.

#google#

Colstrip’s a town of fewer than 2,500 people whose industries are the power plant and the open-pit mines that feed it about 10 million tonnes of coal a year. Two of Colstrip’s generators, older ones Avista doesn’t have any stake in, are closing in 2022. The other two will be all that keep the town in business.

In Washington, they don’t like the coal plant and its pollution. In Montana, the future of Colstrip is a much bigger concern. The companies have to satisfy regulators in both places that letting Hydro One buy Avista is in the public interest.

Ontario proudly closed the last of our coal plants in 2014 and outlawed new ones as environmental menaces, and Alberta's coal phase-out is now slated to finish by 2023. When Hydro One said it was buying Avista, which makes about $100 million in profit a year, Premier Kathleen Wynne said she hoped Ontario’s “value system” would spread to Avista’s operations.

The settlement is “an important step towards bringing together two historic companies,” Hydro One’s chief executive Mayo Schmidt said in announcing it.

The deal has approval from the Washington Utilities and Transportation Commission staff but is subject to a vote by the group’s three commissioners. It doesn’t commit Avista to closing anything at Colstrip or selling its share. But Avista and Hydro One will budget as if the Colstrip coal burners will close in 2027, instead of running into the 2040s as their owners had once planned, a timeline that echoes debates over the San Juan Generating Station in New Mexico.

In accounting terms, they’ll depreciate the value of their share of the plant to zero over the next nine years, reflecting what they say is the end of the plant’s “useful life.” Another of Colstrip’s owners, Puget Sound Energy, has previously agreed with Washington regulators that it’ll budget for a Colstrip closure in 2027 as well.

Avista and Hydro One will look for sources of 50 megawatts of renewable electricity, including independent power projects where feasible, in the next four years and another 90 megawatts to supplement Avista’s supply once the Colstrip plant eventually closes, they promise in Washington. They’ll put $3 million into a “community transition fund” for Colstrip.

The money will come from the companies’ profits and cash, the agreement says. “Hydro One will not seek cost recovery for such funds from ratepayers in Ontario,” it says specifically.

“Ontario has always been a global leader in the transition away from dirty coal power and towards clean energy,” said Doug Howell, an anti-coal campaigner with the Sierra Club, which is a party to the agreement. “This settlement continues that tradition, paving the way for the closure of the largest single source of climate pollution in the American West by 2027, if not earlier.”

Montanans aren’t as thrilled. That state has its own public services commission, doing its own examination of the corporate merger, which has asked Hydro One and Avista to explain in detail why they want to write off the value of the Colstrip burners early. The City of Colstrip has filed a petition saying it wants in on Montana hearings because “the potential closure of (Avista’s units) would be devastating to our community.”

Don’t get too worked up, an Avista vice-president urged the Montana commission just before Easter.

“Just because an asset is depreciated does not mean that one would otherwise remove that asset from service if the asset is still performing as intended,” Jason Thackston testified in a session that dealt only with what the deal with Washington state would mean to Colstrip. We’re talking strictly about an accounting manoeuvre, not an operational commitment.

Six joint owners will have to agree to close the Colstrip generators and there’s “no other tacit understanding or unstated agreement” to do that, he said.

Besides Washington and Montana, state regulators in Idaho, including those overseeing the Idaho Power settlement process, Alaska and Oregon and multiple federal authorities have to sign off on the deal before it can happen. Hydro One hopes it’ll be done in the second half of this year.

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DOE CCUS Funding advances carbon capture, utilization, and storage with FEED studies, regional deployment, and CarbonSAFE site characterization, leveraging 45Q tax credits to scale commercial CO2 reduction across fossil energy sectors.

Key Points

DOE CCUS Funding are federal FOAs for commercial carbon capture, storage, and utilization via FEED and CarbonSAFE.

✅ $110M across FEED, Regional, and CarbonSAFE FOAs

✅ Supports Class VI permits, NEPA, and site characterization

✅ Enables 45Q credits and enhanced oil recovery utilization

The U.S. Department of Energy’s (DOE’s) Office of Fossil Energy (FE) has announced approximately $110 million in federal funding for cost-shared research and development (R&D) projects under three funding opportunity announcements (FOAs), alongside broader carbon-free electricity investments across the power sector.

Approximately $75M is for awards selected under two FOAs announced earlier this fiscal year; $35M is for a new FOA.

These FOAs further the Administration’s commitment to strengthening coal while protecting the environment. Carbon capture, utilization, and storage (CCUS) is increasingly becoming widely accepted as a viable option for fossil-based energy sources—such as coal- or gas-fired power plants under new EPA power plant rules and other industrial sources—to lower their carbon dioxide (CO2) emissions.

DOE’s program has successfully deployed various large-scale CCUS pilot and demonstration projects, and it is imperative to build upon these learnings to test, mature, and prove CCUS technologies at the commercial scale. A recent study by Science of the Total Environment found that DOE is the most productive organization in the world in the carbon capture and storage field.

“This Administration is committed to providing cost-effective technologies to advance CCUS around the world,” said Secretary Perry. “CCUS technologies are vital to ensuring the United States can continue to safely use our vast fossil energy resources, and we are proud to be a global leader in this field.”

“CCUS technologies have transformative potential,” said Assistant Secretary for Fossil Energy Steven Winberg. “Not only will these technologies allow us to utilize our fossil fuel resources in an environmentally friendly manner, but the captured CO2 can also be utilized in enhanced oil recovery and emerging CO2-to-electricity concepts, which would help us maximize our energy production.”

Under the first FOA award, Front-End Engineering Design (FEED) Studies for Carbon Capture Systems on Coal and Natural Gas Power Plants, DOE has selected nine projects to receive $55.4 million in federal funding for cost-shared R&D. The selected projects will support FEED studies for commercial-scale carbon capture systems. Find project descriptions HERE. 

Under the second FOA award, Regional Initiative to Accelerate CCUS Deployment, DOE selected four projects to receive up to $20 million in federal funding for cost-shared R&D. The projects also advance existing research and development by addressing key technical challenges; facilitating data collection, sharing, and analysis; evaluating regional infrastructure, including CO2 storage hubs and pipelines; and promoting regional technology transfer. Additionally, this new regional initiative includes newly proposed regions or advanced efforts undertaken by the previous Regional Carbon Sequestration Partnerships (RCSP) Initiative. Find project descriptions HERE. 

Elsewhere in North America, provincial efforts such as Quebec's and industry partners like Cascades are investing in energy efficiency projects to complement emissions-reduction goals.

Under the new FOA, Carbon Storage Assurance Facility Enterprise (CarbonSAFE): Site Characterization and CO2 Capture Assessment, DOE is announcing up to $35 million in federal funding for cost-shared R&D projects that will accelerate wide-scale deployment of CCUS through assessing and verifying safe and cost-effective anthropogenic CO2 commercial-scale storage sites, and carbon capture and/or purification technologies. These types of projects have the potential to take advantage of the 45Q tax credit, bolstered by historic U.S. climate legislation, which provides a tax credit for each ton of CO2 sequestered or utilized. The credit was recently increased to $35/metric ton for enhanced oil recovery and $50/metric ton for geologic storage.

Projects selected under this new FOA shall perform the following key activities: complete a detailed site characterization of a commercial-scale CO2 storage site (50 million metric tons of captured CO2 within a 30 year period); apply and obtain an underground injection control class VI permit to construct an injection well; complete a CO2capture assessment; and perform all work required to obtain a National Environmental Policy Act determination for the site.

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Ontario Pickering Nuclear Closure will shift supply to natural gas, raising emissions as the electricity grid manages nuclear refurbishment, IESO planning, clean power imports, and new wind, solar, and storage to support electrification.

Key Points

Ontario will close Pickering and rely on natural gas, increasing emissions while other nuclear units are refurbished.

✅ 14% of Ontario electricity supplied by Pickering now

✅ Natural gas use rises; grid emissions projected up 375%

✅ IESO warns gas phaseout by 2030 risks blackouts, costs

The Ontario government will not reconsider plans to close the Pickering nuclear station and instead stop-gap the consequent electricity shortfall with natural gas-generated power in a move that will, as an analysis of Ontario's grid shows, hike the province’s greenhouse gas emissions substantially in the coming years.

In a report released this week, a nuclear advocacy group urged Ontario to refurbish the aging facility east of Toronto, which is set to be shuttered in phases in 2024 and 2025, prompting debate over a clean energy plan after Pickering as the closure nears. The closure of Pickering, which provides 14 per cent of the province’s annual electricity supply, comes at the same time as Ontario’s other two nuclear stations are undergoing refurbishment and operating at reduced capacity.

Canadians for Nuclear Energy, which is largely funded by power workers' unions, argued closing the 50-year-old facility will result in job losses, emissions increases, heightened reliance on imported natural gas and an electricity supply gap across Ontario.

But Palmer Lockridge, spokesperson for the provincial energy minister, said further extending Pickering’s lifespan isn’t on the table.

“As previously announced in 2020, our government is supporting Ontario Power Generation’s plan to safely extend the life of the Pickering Nuclear Generating Station through the end of 2025,” said Lockridge in an emailed response to questions.

“Going forward, we are ensuring a reliable, affordable and clean electricity system for decades to come. That’s why we put a plan in place that ensures we are prepared for the emerging energy needs following the closure of Pickering, and as a result of our government’s success in growing and electrifying the province’s economy.”

The Progressive Conservative government under Premier Doug Ford has invested heavily in electrification, sinking billions into electric vehicle and battery manufacturing and industries like steel-making to retool plants to run on electricity rather than coal, and exploring new large-scale nuclear plants to bolster baseload supply.

Natural gas now provides about seven per cent of the province’s energy, a piece of the pie that will rise significantly as nuclear energy dwindles. Emissions from Ontario’s electricity grid, which is currently one of the world’s cleanest with 94 per cent zero-emission power generation, are projected to rise a whopping 375 per cent as the province turns increasingly to natural gas generation. Those increases will effectively undo a third of the hard-won emissions reductions the province achieved by phasing out coal-fired power generation.

The Independent Electricity System Operator (IESO), which manages Ontario’s grid, studied whether the province could phase out natural gas generation by 2030 and concluded that “would result in blackouts and hinder electrification” and increase average residential electricity costs by $100 per month.

The Ontario Clean Air Alliance, however, obtained draft documents from the electricity operator that showed it had studied, but not released publicly, other scenarios that involved phasing out natural gas without energy shortfalls, price hikes or increases in emissions.

The Ontario government will not reconsider plans to close the Pickering nuclear station and instead stop-gap the consequent electricity shortfall facing Ontario with natural gas-generated power in a move that will hike the province’s greenhouse gas emissions.

One model suggested increasing carbon taxes and imports of clean energy from other provinces could keep blackouts, costs and emissions at bay, while another involved increasing energy efficiency, wind generation and storage.

“By banning gas-fired electricity exports to the U.S., importing all the Quebec water power we can with the existing transmission lines and investing in energy efficiency and wind and solar and storage — do all those things and you can phase out gas-fired power and lower our bills,” said Jack Gibbons, chair of the Ontario Clean Air Alliance.

The IESO has argued in response that the study of those scenarios was not complete and did not include many of the challenges associated with phasing out natural gas plants.

Ontario Energy Minister Todd Smith asked the IESO to develop “an achievable pathway to zero-emissions in the electricity sector and evaluate a moratorium on new-build natural gas generation stations,” said his spokesperson. That report, an early look at halting gas power, is expected in November.

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