Ukraine Prepares for Winter Amid Energy Challenges

California Duck Curve highlights midday solar oversupply and steep evening peak demand, stressing grid stability. Solutions include battery storage, demand response, diverse renewables like wind, geothermal, nuclear, and regional integration to reduce curtailment.

Key Points

A mismatch between midday solar surplus and evening demand spikes, straining the grid without storage and flexibility.

✅ Midday solar oversupply forces curtailment and wasted clean energy.

✅ Evening ramps require fast, fossil peaker plants to stabilize load.

✅ Batteries, demand response, regional trading flatten the curve.

California's remarkable success in adopting solar power, including a near-100% renewable milestone, has created a unique challenge: managing the infamous "duck curve." This distinctive curve illustrates a growing mismatch between solar electricity generation and the state's energy demands, creating potential problems for grid stability and ultimately threatening to slow California's progress in the fight against climate change.

The Shape of the Problem

The duck curve arises from a combination of high solar energy production during midday hours and surging energy demand in the late afternoon and evening when solar power declines. During peak solar hours, the grid often has an overabundance of electricity, and curtailments are increasing as a result, while as the sun sets, demand surges when people return home and businesses ramp up operations. California's energy grid operators must scramble to make up this difference, often relying on fast-acting but less environmentally friendly power sources.

The Consequences of the Duck Curve

The increasing severity of the duck curve has several potential consequences for California:

• Grid Strain: The rapid ramp-up of power sources to meet evening demand puts significant strain on the electrical grid. This can lead to higher operational costs and potentially increase the risk of blackouts during peak demand times.
• Curtailed Energy: To avoid overloading the grid, operators may sometimes have to curtail excess solar energy during midday, as rising curtailment reports indicate, essentially wasting clean electricity that could have been used to displace fossil fuel generation.
• Obstacle to More Solar: The duck curve can make it harder to add new solar capacity, as seen in Alberta's solar expansion challenges, for fear of further destabilizing the grid and increasing the need for fossil fuel-based peaking plants.

Addressing the Challenge

California is actively seeking solutions to mitigate the duck curve, aligning with national decarbonization pathways that emphasize practicality. Potential strategies include:

• Energy Storage: Deploying large-scale battery storage can help soak up excess solar electricity during the day and release it later when demand peaks, smoothing out the duck curve.
• Demand Flexibility: Encouraging consumers to shift their energy use to off-peak hours through incentives and smart grid technologies can help reduce late-afternoon surges in demand.
• Diverse Power Sources: While solar is crucial, a balanced mix of energy sources, including geothermal, wind, and nuclear, can improve grid stability and reduce reliance on rapid-response fossil fuel plants.
• Regional Cooperation: Integrating California's grid with neighboring states can aid in balancing energy supply and demand across a wider geographical area.

The Ongoing Solar Debate

The duck curve has become a central point of debate about the future of California's energy landscape. While acknowledging the challenge, solar advocates argue for continued expansion, backed by measures like a bill to require solar on new buildings, emphasizing the urgent need to transition away from fossil fuels. Grid operators and some utility companies call for a more cautious approach, emphasizing grid reliability and potential costs if the problem isn't effectively managed.

Balancing California's Needs and its Green Ambitions

Finding the right path forward is essential; it will determine whether California can continue to lead the way in solar energy adoption while ensuring a reliable and affordable electricity supply. Successfully navigating the duck curve will require innovation, collaboration, and a strong commitment to building a sustainable energy system, as wildfire smoke impacts on solar continue to challenge generation predictability.

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Nova Scotia Clean Power Plan 2030 pivots from the Atlantic Loop, scaling wind and solar, leveraging Muskrat Falls via the Maritime Link, adding battery storage and transmission upgrades to decarbonize grid and retire coal.

Key Points

Nova Scotia's 2030 roadmap to replace coal with wind, solar, hydro imports, storage, and grid upgrades.

✅ 1,000 MW onshore wind to supply 50% by 2030

✅ Battery storage sites and New Brunswick transmission upgrades

✅ Continued Muskrat Falls imports via Maritime Link

Nova Scotia is abandoning the proposed Atlantic Loop in its plan to decarbonize its electrical grid by 2030 amid broader discussions about independent grid planning nationwide, Natural Resources and Renewables Minister Tory Rushton has announced.

The province unveiled its clean power plan calling for 30 per cent more wind power and five per cent more solar energy in the Nova Scotia power grid over the coming years. Nova Scotia's plan relies on continued imports of hydroelectricity from the Muskrat Falls project in Labrador via the Emera-owned Maritime Link.

Right now Nova Scotia generates 60 per cent of its electricity by burning fossil fuels, mostly coal, and some increased use of biomass has also factored into the mix. Nova Scotia Power must close its coal plants by 2030 when 80 per cent of electricity must come from renewable sources in order reduce greenhouse gas emissions causing climate changes.

Critics have urged reducing biomass use in electricity generation across the province.

The clean power plan calls for an additional 1,000 megawatts of onshore wind by 2030 which would then generate 50 per cent of the the province's electricity, while also advancing tidal energy in the Bay of Fundy as a complementary source.    

"We're taking the things already know and can capitalize on while we build them here in Nova Scotia," said Rushton, "More importantly, we're doing it at a lower rate so the ratepayers of Nova Scotia aren't going to bear the brunt of a piece of equipment that's designed and built and staying in Quebec."

The province says it can meet its green energy targets without importing Quebec hydro through the Atlantic loop. It would have brought hydroelectric power from Quebec into New Brunswick and Nova Scotia via upgraded transmission links. But the government said the cost is prohibitive, jumping to $9 billion from nearly $3 billion three years ago with no guarantee of a secure supply of power from Quebec.

"The loop is not viable for 2030. It is not necessary to achieve our goal," said David Miller, the provincial clean energy director. 

Miller said the cost of $250 to $300 per megawatt hour was five times higher than domestic wind supply.

Some of the provincial plan includes three new battery storage sites and expanding the transmission link with New Brunswick. Both were Nova Scotia Power projects paused by the company after the Houston government imposed a cap on the utility's rate increased in the fall of 2022.

The province said building the 345-kilovolt transmission line between Truro, N.S., and Salisbury, N.B., and an extension to the Point Lepreau Nuclear Generating Station, as well as aligning with NB Power deals for Quebec electricity underway, would enable greater access to energy markets.

Miller says Nova Scotia Power has revived both.

Nova Scotia Power did not comment on the new plan, but Rushton spoke for the company.

"All indications I've had is Nova Scotia Power is on board for what is taking place here today," he said.

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Manitoba Hydro capacity constraints challenge clean energy growth as industrial demand, hydrogen projects, EV batteries, and electrification strain the grid; limited surplus, renewables, storage, and transmission bottlenecks hinder new high-load connections.

Key Points

Limited surplus power blocks new energy-intensive loads until added generation and transmission expand Manitoba's grid.

✅ No firm commitments for new energy-intensive industrial customers

✅ Single large load could consume remaining surplus capacity

✅ New renewables need transmission; gas, nuclear face trade-offs

Manitoba Hydro lacks the capacity to provide electricity to any new "energy intensive" industrial customers, the Crown corporation warns in a confidential briefing note that undercuts the idea this province can lure large businesses with an ample supply of clean, green energy, as the need for new power generation looms for the utility.

On July 28, provincial economic development officials unveiled an "energy roadmap" that said Manitoba Hydro must double or triple its generating capacity, as electrical demand could double over the next two decades in order to meet industrial and consumer demand for electricity produced without burning fossil fuels.

Those officials said 18 potential new customers with high energy needs were looking at setting up operations in Manitoba — and warned the province must be careful to choose businesses that provide the greatest economic benefit as well as the lowest environmental impact.

In a briefing note dated Sept. 13, obtained by CBC News, Manitoba Hydro warns it doesn't have enough excess power to hook up any of these new heavy electricity-using customers to the provincial power grid.

There are actually 57 proposals to use large volumes of electricity, Hydro says in the note, including eight projects already in the detailed study phase and nine where the proponents are working on construction agreements.

"Manitoba Hydro is unable to offer firm commitments to prospective customers that may align with Manitoba's energy roadmap and/or provincial economic development objectives," Hydro warns in the note, explaining it is legally obliged to serve all existing customers who need more electricity.

"As such, Manitoba Hydro cannot reserve electric supply for particular projects."

Hydro says in the note its "near-term surplus electricity supply" is so limited amid a Western Canada drought that "a single energy-intensive connection may consume all remaining electrical capacity."

Adding more electrical generating capacity won't be easy, even with new turbine investments underway, and will not happen in time to meet demands from customers looking to set up shop in the province, Hydro warns.

The Crown corporation goes on to say it's grappling with numerous requests from existing and prospective energy-intensive customers, mainly for producing hydrogen, manufacturing electric vehicle batteries and switching from fossil fuels to electricity, such as to use electricity for heat in buildings.

In a statement, Hydro said it wants to ensure Manitobans know the corporation is not running out of power — just the ability to meet the needs of large new customers, and continues to provide clean energy to neighboring provinces today.

"The size of loads looking to come to Manitoba are significantly larger than we typically see, and until additional supply is available, that limits our ability to connect them," Hydro spokesperson Bruce Owen said in a statement.

Adding wind power or battery storage, for example, would require the construction of more transmission lines, and deals such as SaskPower's purchase depend on that interprovincial infrastructure as well.

Natural gas plants are relatively inexpensive to build but do not align with efforts to reduce carbon emissions. Nuclear power plants require at least a decade of lead time to build, and tend to generate local opposition.

Hydro has also ruled out building another hydroelectric dam on the Nelson River, where the Conawapa project was put on hold in 2014.

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Alberta Utility Rate Rider will add a modest fee to electricity bills and natural gas charges as the AUC recovers outstanding debt from the COVID-19 deferral program via AESO and the Balancing Pool.

Key Points

A temporary surcharge on Alberta power and gas bills to recover unpaid COVID-19 deferral debt, administered by the AUC.

✅ Applies per kWh and per GJ based on consumption

✅ Recovers unpaid balances from 2020-21 bill deferrals

✅ Collected via AESO and the Balancing Pool under AUC oversight

The province says Alberta ratepayers should expect to see an extra fee on their utility bills in the coming months.

That fee is meant to recover the outstanding debt owed to gas and electricity providers resulting from last year's three-month utility deferral program offered to struggling Albertans during the pandemic.

The provincial government announced the utility deferral program in March 2020 then formalized it with legislation, alongside a consumer price cap on power bills that shaped later policy decisions.

The program allowed residential, farm and small commercial customers who used less than 250,000 kilowatt hours of electricity per year — or consumed less than 2,500 gigajoules per year — to postpone their bills amid the COVID-19 pandemic.

According to the province, 350,000 customers, or approximately 13 per cent of the natural gas and electricity consumer base, took advantage of the program.

Customers had a year to repay providers what they owed. That deadline ended June 18, 2021.

The Alberta Utilities Commission (AUC), which regulates the utilities sector and natural gas and electricity markets and oversees a rate of last resort framework, said the vast majority of consumers have squared up.

But for those who didn't, provincial legislation dictates that Alberta ratepayers must cover any unpaid debt. The legislation exempts Medicine Hat utility customers for electricity and gas co-operative customers for gas.

"When the program was announced, it was very clear that it was a deferral program and that the monies would need to be paid back," said Geoff Scotton, a spokesperson with the Alberta Utilities Commission.

"Now we're in the situation where the providers, in good faith, who enabled those payment deferrals, need to be made whole. That's really the goal here."

Amount to be determined
Margeaux Maron, a spokesperson for Associate Minister of Natural Gas and Electricity Dale Nally, said based on early estimates, $13 to $16 million of $92 million in deferred payments remain outstanding.

As a result, the province expects the average Albertan will end up paying, unlike jurisdictions offering a lump-sum credit, a fraction of a dollar extra per monthly gas and electricity bill over a handful of months.

Scotton said at this point, there are too many unknown factors to know the exact size of the rate rider. However, he said he expects it to be modest.

Scotton said affected parties first have until the end of this week to notify the AUC exactly how much they are still owed.

Those parties include the Alberta Electric System Operator and the Balancing Pool, who essentially acted as bankers with respect to the distribution and transmission of the utilities to customers who deferred their payments.

Regulated service providers may also seek reimbursement on administrative and carrying costs, even as issues like a BC Hydro fund surplus spark debate elsewhere.

Then, Scotton said, once the outstanding amounts are known, the AUC will hold a public proceeding, similar to a Nova Scotia rate case, to determine the amount and the duration of the rate rider to be applied to each natural gas and electricity bill.

The amount will be based on consumption: per kilowatt hour for electricity and per gigajoule for natural gas.

That means larger businesses will end up paying more than the average Albertan.

Scotton said the AUC will expedite the hearing process and it expects to have a decision by the end of the summer.

Rate rider a 'surprise'
Joel MacDonald with Energyrates.ca — an organization which compares energy rates across the country — said it's not the amount of the rate rider that bothers him, but the fact that the repayment process wasn't made clear at the onset of the program.

"It came to us as a bit of a surprise," MacDonald said.

He said what was sold as a deferral program seems more like an electricity rebate program, or an "ability to pay" program.

"As opposed to the retailers looking into collection methods, anything that wasn't paid is basically just being forced upon all Alberta consumers," MacDonald said.

The expectation set out in the deferral legislation and regulations state utility providers such as Enmax and Epcor are expected to use reasonable efforts to try to collect the unpaid balances. It must then detail those reasonable efforts to the AUC.

A spokesperson for Enmax said it first works with its customers to find manageable payment arrangements and connects them with support services if they are unable to pay.

Then, if payment can't be arranged, it said it will work with a collection agency, which may even result in disconnection of service.

The spokesperson said only after all efforts have failed would Enmax seek reimbursement through this program.

Use tax revenues?
MacDonald also questioned why a government program isn't being paid for through general tax revenues.

He compared the utility deferral program to a mortgage subsidy program.

"Imagine that [Canada Mortgage And Housing Corporation] said, 'Hey, we had to give mortgage deferrals and some of these people never paid back their deferrals, so we're going to add an extra $300 to everyone's mortgage,'" he said.

"You'd expect that to come off of some sort of general taxation — not being assigned to other people's mortgages, right?"

In response, Maron said due to the current fiscal challenges facing the government — and the expected minimal costs to consumers, and even as a consumer price cap on electricity remains in place — it was determined that a rate rider would be an appropriate mechanism to repay bad debt associated with the program.

Scotton said rate riders aren't unusual — they're used to fine-tune rates for a set period of time.

He said under normal circumstances, regulated service providers can apply to the AUC to impose a rate rider to recover unexpected costs. And in some instances, they can provide a credit.

But in this situation, he said the debt is aggregated and, in turn, being collected more broadly.

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Ecofiscal Commission EV Policy Shift examines carbon pricing limits, endorsing signal boosters like subsidies, EV incentives, and coal bans, amid advisory changes and public pushback, to accelerate emissions cuts beyond market-based taxes and regulations.

Key Points

An updated stance recognizing carbon pricing limits and backing EV incentives, subsidies, and rules to reduce emissions.

✅ Carbon pricing plus subsidies, EV incentives

✅ Advisory shift; Jack Mintz departs

✅ Focus on emissions cuts, coal power bans

Something strange happened at the Ecofiscal Commission recently. Earlier this month, the carbon-tax advocacy group featured on its website as one of its advisers the renowned Canadian economist (and FP Comment columnist) Jack M. Mintz. The other day, suddenly and without fanfare, Mintz was gone from the website, and the commission’s advisory board.

Advisers come and advisers go, of course, but it turns out there was an impetus for Mintz’s departure. The Ecofiscal Commission in its latest report, dropped just before Canada Day, seemingly shifted from its position that carbon prices were so excellent at mimicking market forces that the tax could repeal and replace virtually the entire vast expensive gallimaufry of subsidies, caps, rules and regulations that are costing Canada a fortune in business and bureaucrats. As some Ecofiscal commissioners wrote just a few months ago, policies that “dictate specific technologies or methods for reducing emissions constrain private choice and increase costs” and were a bad idea.

But, in this latest report, the commission is now musing about the benefits of carbon-tax “signal boosters”: that is, EV subsidies and rules to, for instance, get people to start buying electric vehicles (EVs), as well as bans on coal-fired power. “Even well designed carbon pricing can have limitations,” rationalized the commission. Mintz said he had “misgivings” about the change of tack. He decided it best if he focus his advisory energies elsewhere.

It’s hard to blame the commission for falling like everyone else for the electric-car mania that’s sweeping the nation and the world. Electric cars offer a sexiness that dreary old carbon taxes can never hope to match — especially in light of a new Angus Reid poll last week that showed the majority of Canadians now want governments to shelve any plans for carbon taxes.

So far, because nobody’s really driving these miracle machines, said mania has been limited to breathless news reports about how the electric-vehicle revolution is about to rock our world. EVs comprise just two-tenths of a per cent of all passenger vehicles in North America, despite the media’s endless hype and efforts of green-obsessed governments to cover much of the price tag, like Ontario’s $14,000 rebate for Tesla buyers. In Europe, where virtue-signalling urban environmentalism is the coolest, they’re not feeling the vehicular electricity much more: EVs account for barely one per cent of personal vehicles in France, the U.K. and Germany. When Hong Kong cancelled Tesla rebates in April, sales fell to zero.

Going by the ballyhoo, you’d think EVs were at an inflection point and an unstoppable juggernaut. But it’s one that has yet to even get started. In his 2011 State of the Union address, then president Barack Obama predicted one million electric cars on the road by 2015. Four years later, there wasn’t even a third that many. California offered so many different subsidies for electric vehicles that low-income families could get rebates of up to US$13,500, but it still isn’t even close to reaching its target of having zero-emission vehicles make up 15 per cent of California auto sales by 2025, being stuck at three per cent since 2014. Ontario’s Liberal government last year announced to much laughter its plan to ensure that every family would have at least one zero-emission vehicle (ZEV) by 2024, and Quebec made a plan to make ZEVs worth 15.5 per cent of sales by 2020, while Ottawa’s 2035 EV mandate attracts criticism too. Let’s see how that’s going: Currently, ZEVs make up 0.16 per cent of new vehicle sales in Ontario and 0.38 per cent in Quebec.

The latest sensational but bogus EV news out last week was France’s government announcing the “end of the sale of gasoline and diesel cars by 2040,” and Volvo apparently announcing that as of 2019, all its models would be “electric.” Both announcements made international headlines. Both are baloney. France provided no actual details about this plan (will it literally become a crime to sell a gasoline car? Will hybrids, run partly on gasoline, be allowed?), but more importantly, as automotive writer Ed Wiseman pointed out in The Guardian, a lot will happen in technology and automotive use over the next 23 years that France has no way to predict, with changes in self-driving cars, public car-sharing and fuel technologies. Imagine making rules for today’s internet back in 1994.

Volvo, meanwhile, looked to be recycling and repackaging years-old news to seize on today’s infatuation with electric vehicles to burnish its now Chinese-owned brand. Since 2010, Volvo’s plan has been to focus on engines that were partly electric, with electric turbochargers, but still based on gasoline. Volvo doesn’t actually have an all-electric model, but the gasoline-swigging engine of its popular XC90 SUV is, partly, electrical. When Volvo said all its models would in two years be “electric,” it meant this kind of engine, not that it was phasing out the internal-combustion gasoline engine. But that is what it wanted reporters to think, and judging by all the massive and inaccurate coverage, it worked.

The real story being missed is just how pathetic things look right now for electric cars. Gasoline prices in the U.S. turned historically cheap in 2015 and stayed cheap, icing demand for gasless cars. Tesla, whose founder’s self-promotion had made the niche carmaker magically more valuable than powerhouses like Ford and GM, haemorrhaged US$12 billion in market value last week after tepid sales figures brought some investors back to Earth, even as the company’s new Model 3 began rolling off the line.

Not helping is that environmental claims about environmental cars are falling apart. In June, Tesla was rocked by a controversial Swedish study that found that making one of its car batteries released as much CO2 as eight years of gasoline-powered driving. And Bloomberg reported last week on a study by Chinese engineers that found that electric vehicles, because of battery manufacturing and charging by fossil-fuel-powered electricity sources, emit 50-per-cent more carbon than do internal-combustion engines. Still, the electric-vehicle hype not only continues unabated, it gets bigger and louder every day. If some car company figures out how to harness it, we’d finally have a real automotive revolution on our hands.

Kevin Libin, Financial Post

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AP1000 Refueling Outage Record showcases Westinghouse nuclear power excellence as Sanmen Unit 2 completes its first reactor refueling in 28.14 days, highlighting safety, reliability, outage optimization, and economic efficiency in China.

Key Points

It is the 28.14-day initial refueling at Sanmen Unit 2, a global benchmark achieved with Westinghouse AP1000 technology.

✅ 28.14-day first refueling at Sanmen Unit 2 sets global benchmark

✅ AP1000 design simplifies systems, improves safety and reliability

✅ Outage optimization by Westinghouse and CNNC accelerates schedules

Westinghouse Electric Company China operations today announced that Sanmen Unit 2, one of the world's first AP1000® nuclear power plants, has set a new refueling outage record in the global nuclear power industry, completing its initial outage in 28.14 days.

"Our innovative AP1000 technology allows for simplified systems and significantly reduces the amount of equipment, while improving the safety, reliability and economic efficiency of this nuclear power plant, reflecting global nuclear milestones reached recently," said Gavin Liu, president of the Westinghouse Asia Operating Plant Services Business. "We are delighted to see the first refueling outage for Sanmen Unit 2 was completed in less than 30 days. This is a great achievement for Sanmen Nuclear Power Company and further demonstrates the outstanding performance of AP1000 design."

All four units of the AP1000 nuclear power plants in China have completed their first refueling outages in the past 18 months, aligning with China's nuclear energy development momentum across the sector.  The duration of each subsequent outage has fallen significantly - from 46.66 days on the first outage to 28.14 days on Sanmen Unit 2.

"During the first AP1000 refueling outage at the Sanmen site in December 2019, a Westinghouse team of experts worked side-by-side with the Sanmen outage team to partner on outage optimization, and immediately set a new standard for a first-of-a-kind outage, while major refurbishments like the Bruce refurbishment moved forward elsewhere," said Miao Yamin, chairman of CNNC Sanmen Nuclear Power Company Limited. "Lessons learned were openly exchanged between our teams on each subsequent outage, which has built to this impressive achievement."

Westinghouse provided urgent technical support on critical issues during the outage, as international programs such as Barakah Unit 1 achieved key milestones, to help ensure that work was carried out on schedule with no impact to critical path.

In addition to the four AP1000 units in China, two units are under construction at the Vogtle expansion near Waynesboro, Georgia, USA.

Separately, in the United States, a new reactor startup underscored renewed momentum in nuclear generation this year.

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