Arnold defends California's greenhouse-gas rules

Ontario Nuclear Power Costs highlight LCOE, capex, refurbishment outlays, and waste management, compared with renewables, grid reliability, and emissions targets, informing Australia and Peter Dutton on feasibility, timelines, and electricity prices.

Key Points

They include high capex and LCOE from refurbishments and waste, offset by reliable, low-emission baseload.

✅ Refurbishment and maintenance drive lifecycle and LCOE variability.

✅ High capex and long timelines affect consumer electricity prices.

✅ Low emissions, but waste and safety compliance add costs.

Australian opposition leader Peter Dutton recently lauded Canada’s use of nuclear power as a model for Australia’s energy future. His praise comes as part of a broader push to incorporate nuclear energy into Australia’s energy strategy, which he argues could help address the country's energy needs and climate goals. However, the question arises: Is Ontario’s experience with nuclear power as cost-effective as Dutton suggests?

Dutton’s endorsement of Canada’s nuclear power strategy highlights a belief that nuclear energy could provide a stable, low-emission alternative to fossil fuels. He has pointed to Ontario’s substantial reliance on nuclear power, and the province’s exploration of new large-scale nuclear projects, as an example of how such an energy mix might benefit Australia. The province’s energy grid, which integrates a significant amount of nuclear power, is often cited as evidence that nuclear energy can be a viable component of a diversified energy portfolio.

The appeal of nuclear power lies in its ability to generate large amounts of electricity with minimal greenhouse gas emissions. This characteristic aligns with Australia’s climate goals, which emphasize reducing carbon emissions to combat climate change. Dutton’s advocacy for nuclear energy is based on the premise that it can offer a reliable and low-emission option compared to the fluctuating availability of renewable sources like wind and solar.

However, while Dutton’s enthusiasm for the Canadian model reflects its perceived successes, including recent concerns about Ontario’s grid getting dirtier amid supply changes, a closer look at Ontario’s nuclear energy costs raises questions about the financial feasibility of adopting a similar strategy in Australia. Despite the benefits of low emissions, the economic aspects of nuclear power remain complex and multifaceted.

In Ontario, the cost of nuclear power has been a topic of considerable debate. While the province benefits from a stable supply of electricity due to its nuclear plants, studies warn of a growing electricity supply gap in coming years. Ontario’s experience reveals that nuclear power involves significant capital expenditures, including the costs of building reactors, maintaining infrastructure, and ensuring safety standards. These expenses can be substantial and often translate into higher electricity prices for consumers.

The cost of maintaining existing nuclear reactors in Ontario has been a particular concern. Many of these reactors are aging and require costly upgrades and maintenance to continue operating safely and efficiently. These expenses can add to the overall cost of nuclear power, impacting the affordability of electricity for consumers.

Moreover, the development of new nuclear projects, as seen with Bruce C project exploration in Ontario, involves lengthy and expensive construction processes. Building new reactors can take over a decade and requires significant investment. The high initial costs associated with these projects can be a barrier to their economic viability, especially when compared to the rapidly decreasing costs of renewable energy technologies.

In contrast, the cost of renewable energy has been falling steadily, even as debates over nuclear power’s trajectory in Europe continue, making it a more attractive option for many jurisdictions. Solar and wind power, while variable and dependent on weather conditions, have seen dramatic reductions in installation and operational costs. These lower costs can make renewables more competitive compared to nuclear energy, particularly when considering the long-term financial implications.

Dutton’s praise for Ontario’s nuclear power model also overlooks some of the environmental and logistical challenges associated with nuclear energy. While nuclear power generates low emissions during operation, it produces radioactive waste that requires long-term storage solutions. The management of nuclear waste poses significant environmental and safety concerns, as well as additional costs for safe storage and disposal.

Additionally, the potential risks associated with nuclear power, including the possibility of accidents, contribute to the complexity of its adoption. The safety and environmental regulations surrounding nuclear energy are stringent and require continuous oversight, adding to the overall cost of maintaining nuclear facilities.

As Australia contemplates integrating nuclear power into its energy mix, it is crucial to weigh these financial and environmental considerations. While the Canadian model provides valuable insights, the unique context of Australia’s energy landscape, including its existing infrastructure, energy needs, and the costs of scrapping coal-fired electricity in comparable jurisdictions, must be taken into account.

In summary, while Peter Dutton’s endorsement of Canada’s nuclear power model reflects a belief in its potential benefits for Australia’s energy strategy, the cost-effectiveness of Ontario’s nuclear power experience is more nuanced than it may appear. The high capital and maintenance costs associated with nuclear energy, combined with the challenges of managing radioactive waste and ensuring safety, present significant considerations. As Australia evaluates its energy future, a comprehensive analysis of both the benefits and drawbacks of nuclear power will be essential to making informed decisions about its role in the country’s energy strategy.

Related News

• Electricity Forum News

• Power Generation News

SDG&E Minimum Bill Proposal would impose a $38.40 fixed charge, discouraging rooftop solar, burdening low income households, and shifting grid costs during peak demand, as the CPUC weighs consumer impacts and affordability.

Key Points

Sets a $38.40 monthly minimum bill that raises low usage costs, deters rooftop solar, and burdens low income households.

✅ $38.40 fixed charge regardless of usage

✅ Disincentivizes rooftop solar investments

✅ Disproportionate impact on low income customers

The utility San Diego Gas & Energy has an aggressive proposal pending before the California Public Utilities Commission, amid recent commission changes in San Diego that highlight how regulatory decisions affect local customers: It wants to charge most residential customers a minimum bill of $38.40 each month, regardless of how much energy they use. The costs of this policy would hit low-income customers and those who generate their own energy with rooftop solar. We’re urging the Commission to oppose this flawed plan—and we need your help.

SDG&E’s proposal is bad news for sustainable energy. About half of the customers whose bills would go up under this proposal have rooftop solar. The policy would deter other customers from investing in rooftop solar by making these investments less economical. Ultimately, lost opportunities for solar would mean burning more gas in polluting power plants. 

The proposal is also bad news for people who already have to scrimp on energy costs. Most customers with big homes and billowing air conditioners won't notice if this policy goes into effect, because they use at least $38 worth of electricity a month anyway. But for households that don’t buy much electricity from the company, including those in small apartments without air conditioning, this proposal would raise the bills. Even for customers on special low-income rates, amid electric bill changes statewide, SDG&E wants a minimum bill of $19.20.

Penalizing customers who don’t use much electricity would disproportionately hurt lower-income customers, raising energy equity concerns across the region, who tend to use less energy than their wealthier neighbors. In the region SDG&E serves, the average family in an apartment uses half as much electricity as a single-family residence. Statewide, low-income households are more than four times as likely to be low-usage electricity customers than high-income households. When it gets hot, residential electricity patterns are often driven by air conditioning. The vast majority of SDG&E's customers live in the coastal climate zone, where access to air conditioning is strongly linked to income: Households with incomes over $150,000 are more than twice as likely to have air conditioning than families making less than $35,000, with significant racial disparities in who has AC.

In its attempt to rationalize its request, SDG&E argues that it should charge everyone for infrastructure costs that do not depend on how much energy they use. But the cost of the grid is driven by how much energy SDG&E delivers on hot summer afternoons, when some customers blast their AC and demand for electricity peaks. If more customers relied on their own solar power or conserved energy, the utility would spend less on its grid and help rein in soaring electricity prices over time.

In the long term, reducing incentives to go solar and conserve energy will strain the grid and drive up costs for everyone, especially as lawmakers may overturn income-based charges and reshape rate design. SDG&E's arguments are part of a standard utility playbook for trying to hike income-based fixed charges, and consumer advocates have repeatedly shut them down.  As far as we know, no regulators in the country have allowed a utility to charge customers over $38 for the “privilege” of accessing electric service. 

Related News

• Electricity Forum News

• Energy Policy News

Renewable Energy Cost Trends highlight IRENA data showing solar and wind undercut coal, as utility-scale projects drive lower levelized electricity costs worldwide, with the Middle East and UAE advancing mega solar parks.

Key Points

They track how solar and wind undercut new fossil fuels as utility-scale costs drop and investment accelerates.

✅ IRENA reports renewables cheapest for new installations

✅ Solar and wind LCOE fell sharply since 2010

✅ Middle East and UAE scale mega utility projects

Renewable energy is now the cheapest option for new electricity installation in most of the world, a report from the International Renewable Energy Agency (IRENA) on Tuesday said.

Renewable power projects have undercut traditional coal fuel plants, with solar and wind power costs in particular falling as record-breaking growth continues worldwide.

“Installing new renewables increasingly costs less than the cheapest fossil fuels. With or without the health and economic crisis, dirty coal plants were overdue to be consigned to the past, said Francesco La Camera, director-general of IRENA said in the report.

In 2019, renewables accounted for around 72 percent of all new capacity added worldwide, IRENA said, following a 2016 record year that highlighted the momentum, with lowering costs and technological improvements in solar and wind power helping this dynamic. For solar energy, IRENA notes that the cost for electricity from utility-scale plants fell by 82 percent in the decade between 2010 and 2019, as China's solar PV growth underscored in 2016.

“More than half of the renewable capacity added in 2019 achieved lower electricity costs than new coal, while new solar and wind projects are also undercutting the cheapest and least sustainable of existing coal-fired plants,” Camera added.

Costs for solar and wind power also fell year-on-year by 13 and 9 percent, respectively, with offshore wind costs showing steep declines as well. In 2019, more than half of all newly commissioned utility-scale renewable power plants provided electricity cheaper than the lowest cost of a new fossil fuel plant.

The Middle East

In mid-May, a report by UK-based law firm Ashurst suggested the Middle East is the second most popular region for renewable energy investment after North America, at a time when clean energy investment is outpacing fossil fuels.

The region is home to some of the largest renewable energy bets in the world, with Saudi wind expansion gathering pace. The UAE, for instance, is currently developing the Mohammed Bin Rashid Solar Park, the world’s largest concentrated solar power project in the world.

Around 26 percent of Middle East respondents in Ashurst’s survey said that they were presently investing in energy transition, marking the region as the most popular for current investment in renewables, while 11 percent added that they were considering investing.

In North America, the most popular region, 28 percent said that they were currently investing, with 11 percent stating they are considering investing.

Related News

• Electricity Forum News

• Renewable Energy News

Alberta Solar Power is accelerating as renewable energy investment, PPAs, and utility-scale projects expand the grid, with independent power producers and foreign capital outperforming AESO forecasts in oil-and-gas-rich markets across Alberta and Calgary.

Key Points

Alberta Solar Power is a fast-growing provincial market, driven by PPAs and private investment, outpacing AESO forecasts.

✅ Utility-scale projects and PPAs expand capacity beyond AESO outlooks

✅ Private and foreign capital drive independent power producers

✅ Costs near $70/MWh challenge >$100/MWh assumptions

Solar power is beating expectations in oil and gas rich Alberta, where the renewable energy source is poised to expand dramatically amid a renewable energy surge in the coming years as international power companies invest in the province.

Fresh capital is being deployed in the Alberta’s electricity generation sector for both renewable and natural gas-fired power projects after years of uncertainty caused by changes and reversals in the province’s power market, said Duane Reid-Carlson, president of power consulting firm EDC Associates, who advises renewable power developers on electric projects in the province.

“From the mix of projects that we see in the queue at the (Alberta Electric System Operator) and the projects that have been announced, Alberta, a powerhouse for both green energy and fossil fuels, has no shortage of thermal and renewable projects,” Reid-Carlson said, adding that he sees “a great mix” of independent power companies and foreign firms looking to build renewable projects in Alberta.

Alberta is a unique power market in Canada because its electricity supply is not dominated by a Crown corporation such as BC Hydro, Hydro One or Hydro Quebec. Instead, a mix of private-sector companies and a few municipally owned utilities generate electricity, transmit and distribute that power to households and industries under long-term contracts.

Last week, Perimeter Solar Inc., backed by Danish solar power investor Obton AS, announced Sept. 30 that it had struck a deal to sell renewable energy to Calgary-based pipeline giant TC Energy Corp. with 74.25 megawatts of electricity from a new 130-MW solar power project immediately south of Calgary. Neither company disclosed the costs of the transaction or the project.

“We are very pleased that of all the potential off-takers in the market for energy, we have signed with a company as reputable as TC Energy,” Obton CEO Anders Marcus said in a release announcing the deal, which it called “the largest negotiated energy supply agreement with a North American energy company.”

Perimeter expects to break ground on the project, which will more than double the amount of solar power being produced in the province, by the end of this year.

A report published Monday by the Energy Information Administration, a unit of the U.S. Department of Energy, estimated that renewable energy powered 3 per cent of Canada’s energy consumption in 2018.

Between the Claresholm project and other planned solar installations, utility companies are poised to install far more solar power than the province is currently planning for, even as Alberta faces challenges with solar expansion today.

University of Calgary adjunct professor Blake Shaffer said it was “ironic” that the Claresholm Solar project was announced the exact same day as the Alberta Electric System Operator released a forecast that under-projected the amount of solar in the province’s electric grid.

The power grid operator (AESO) released its forecast on Sept. 30, which predicted that solar power projects would provide just 1 per cent of Alberta’s electricity supply by 2030 at 231 megawatts.

Shaffer said the AESO, which manages and operates the province’s electricity grid, is assuming that on a levelized basis solar power will need a price over $100 per megawatt hour for new investment. However, he said, based on recent solar contracts for government infrastructure projects, the cost is closer to $70 MW/h.

Most forecasting organizations like the International Energy Agency have had to adjust their forecasts for solar power adoption higher in the past, as growth of the renewable energy source has outperformed expectations.

Calgary-based Greengate Power has also proposed a $500-million, 400-MW solar project near Vulcan, a town roughly one-hour by car southeast of Calgary.

“So now we’re getting close to 700 MW (of solar power),” Shaffer said, which is three times the AESO forecast.

Related News

• Electricity Forum News

• Renewable Energy News

Methane Hydrate CO2 Sequestration uses carbon capture and nitrogen injection to swap gases in seafloor hydrates along the Gulf of Mexico, releasing methane for electricity while storing CO2, according to new simulation research.

Key Points

A method injecting CO2 and nitrogen into hydrates to store CO2 while releasing methane for power.

✅ Nitrogen aids CO2-methane swap in hydrate cages, speeding sequestration

✅ Gulf Coast proximity to emitters lowers transport and power costs

✅ Revenue from methane electricity could offset carbon capture

The world is quickly realizing it may need to actively pull carbon dioxide out of the atmosphere to stave off the ill effects of climate change. Scientists and engineers have proposed various carbon capture techniques, but most would be extremely expensive—without generating any revenue. No one wants to foot the bill.

One method explored in the past decade might now be a step closer to becoming practical, as a result of a new computer simulation study. The process would involve pumping airborne CO2 down into methane hydrates—large deposits of icy water and methane right under the seafloor, beneath water 500 to 1,000 feet deep—where the gas would be permanently stored, or sequestered. The incoming CO2 would push out the methane, which would be piped to the surface and burned to generate electricity, whether sold locally or via exporters like Hydro-Que9bec to help defray costs, to power the sequestration operation or to bring in revenue to pay for it.

Many methane hydrate deposits exist along the Gulf of Mexico shore and other coastlines. Large power plants and industrial facilities that emit CO2 also line the Gulf Coast, where EPA power plant rules could shape deployment, so one option would be to capture the gas directly from nearby smokestacks, keeping it out of the atmosphere to begin with. And the plants and industries themselves could provide a ready market for the electricity generated.

A methane hydrate is a deposit of frozen, latticelike water molecules. The loose network has many empty, molecular-size pores, or “cages,” that can trap methane molecules rising through cracks in the rock below. The computer simulation shows that pushing out the methane with CO2 is greatly enhanced if a high concentration of nitrogen is also injected, and that the gas swap is a two-step process. (Nitrogen is readily available anywhere, because it makes up 78 percent of the earth’s atmosphere.) In one step the nitrogen enters the cages; this destabilizes the trapped methane, which escapes the cages. In a separate step, the nitrogen helps CO2 crystallize in the emptied cages. The disturbed system “tries to reach a new equilibrium; the balance goes to more CO2 and less methane,” says Kris Darnell, who led the study, published June 27 in the journal Water Resources Research. Darnell recently joined the petroleum engineering software company Novi Labs as a data scientist, after receiving his Ph.D. in geoscience from the University of Texas, where the study was done.

A group of labs, universities and companies had tested the technique in a limited feasibility trial in 2012 on Alaska’s North Slope, where methane hydrates form in sandstone under deep permafrost. They sent CO2 and nitrogen down a pipe into the hydrate. Some CO2 ended up being stored, and some methane was released up the same pipe. That is as far as the experiment was intended to go. “It’s good that Kris [Darnell] could make headway” from that experience, says Ray Boswell at the U.S. Department of Energy’s National Energy Technology Laboratory, who was one of the Alaska experiment leaders but was not involved in the new study. The new simulation also showed that the swap of CO2 for methane is likely to be much more extensive—and to happen quicker—if CO2 enters at one end of a hydrate deposit and methane is collected at a distant end.

The technique is somewhat similar in concept to one investigated in the early 2010s by Steven Bryant and others at the University of Texas. In addition to numerous methane hydrate deposits, the Gulf Coast has large pools of hot, salty brine in sedimentary rock under the coastline. In this system, pumps would send CO2 down into one end of a deposit, which would force brine into a pipe that is placed at the other end and leads back to the surface. There the hot brine would flow through a heat exchanger, where heat could be extracted and used for industrial processes or to generate electricity, supporting projects such as electrified LNG in some markets. The upwelling brine also contains some methane that could be siphoned off and burned. The CO2 dissolves into the underground brine, becomes dense and sinks further belowground, where it theoretically remains.

Either system faces big practical challenges, and building shared CO2 storage hubs to aggregate captured gas is still evolving. One is creating a concentrated flow of CO2; the gas makes up only .04 percent of air, and roughly 10 percent of the smokestack emission from a typical power plant or industrial facility. If an efficient methane hydrate or brine system requires an input that is 90 percent CO2, for example, concentrating the gas will require an enormous amount of energy—making the process very expensive. “But if you only need a 50 percent concentration, that could be more attractive,” says Bryant, who is now a professor of chemical and petroleum engineering at the University of Calgary. “You have to reduce the [CO2] capture cost.”

Another major challenge for the methane hydrate approach is how to collect the freed methane, which could simply seep out of the deposit through numerous cracks and in all directions. “What kind of well [and pipe] structure would you use to grab it?” Bryant asks.

Given these realities, there is little economic incentive today to use methane hydrates for sequestering CO2. But as concentrations rise in the atmosphere and the planet warms further, and as calls for an electric planet intensify, systems that could capture the gas and also provide energy or revenue to run the process might become more viable than techniques that simply pull CO2 from the air and lock it away, offering nothing in return.

Related News

• Electricity Forum News

• Climate Change News

EU Nuclear Reactor Life Extension focuses on energy security, carbon-free electricity, and safety as ageing reactors face gas shortages, high power prices, and regulatory approvals across the UK and EU amid winter supply risks.

Key Points

EU Nuclear Reactor Life Extension is the policy to keep ageing reactors safely generating affordable, low-carbon power.

✅ Extends reactor operation via inspections and component upgrades

✅ Addresses gas shortages, price volatility, and winter supply risks

✅ Requires national regulator approval and cost-benefit analysis

Shaken by the loss of Russian natural gas since the invasion of Ukraine, European countries are questioning whether they can extend the lives of their ageing nuclear reactors to maintain the supply of affordable, carbon-free electricity needed for net-zero across the bloc — but national regulators, companies and governments disagree on how long the atomic plants can be safely kept running.

Europe avoided large-scale blackouts last winter despite losing its largest supplier of natural gas, and as Germany temporarily extended nuclear operations to bolster stability, but industry is still grappling with high electricity prices and concerns about supply.

Given warnings from the International Energy Agency that the coming winters will be particularly at risk from a global gas shortage, governments have turned their attention to another major energy source — even as some officials argue nuclear would do little to solve the gas issue in the near term — that would exacerbate the problem if it too is disrupted: Europe’s ageing fleet of nuclear power plants.

Nuclear accounts for nearly 10% of energy consumed in the European Union, with transport, industry, heating and cooling traditionally relying on coal, oil and natural gas.

Historically nuclear has provided about a quarter of EU electricity and 15% of British power, even as Germany shut down its last three nuclear plants recently, underscoring diverging national paths.

Taken together, the UK and EU have 109 nuclear reactors running, even as Europe is losing nuclear power in several markets, most of which were built in the 1970s and 1980s and were commissioned to last about 30 years.

That means 95 of those reactors — nearly 90% of the fleet — have passed or are nearing the end of their original lifespan, igniting debates over how long they can safely continue to be granted operating extensions, with some arguing it remains a needed nuclear option for climate goals despite age-related concerns.

Regulations differ across borders, with some countries such as Germany turning its back on nuclear despite an ongoing energy crisis, but life extension discussions are usually a once-a-decade affair involving physical inspections, cost/benefit estimates for replacing major worn-out parts, legislative amendments, and approval from the national nuclear safety authority.

Related News

• Electricity Forum News

• Power Generation News