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Hydro-Québec Unified Corporate Structure advances the energy transition through integrated planning, strategy, infrastructure delivery, and customer operations, aligning generation, transmission, and distribution while ensuring non-discriminatory grid access and agile governance across assets and behind-the-meter technologies.

Key Points

A cross-functional model aligning strategy, planning, and operations to accelerate Quebec's low-carbon transition.

✅ Four groups: strategy, planning, infrastructure, operations.

✅ Ensures non-discriminatory transmission access compliance.

✅ No staff reductions; staged implementation from Feb 28.

As Hydro-Que9bec prepares to play a key role in the transition to a low-carbon economy, the complexity of the work to be done in the coming decade requires that it develop a global vision of its operations and assets, from the drop of water entering its turbines to the behind-the-meter technologies marketed by its subsidiary Hilo. This has prompted the company to implement a new corporate structure that will maximize cooperation and agility, including employee-led pandemic support that builds community trust, making it possible to bring about the energy transition efficiently with a view to supporting the realization of Quebecers’ collective aspirations.

Toward a single, unified Hydro

Hydro-Québec’s core mission revolves around four major functions that make up the company’s value chain, alongside policy choices like peak-rate relief during emergencies. These functions consist of:

1. Developing corporate strategies based on current and future challenges and business opportunities
2. Planning energy needs and effectively allocating financial capital, factoring in pandemic-related revenue impacts on demand and investment timing
3. Designing and building the energy system’s multiple components
4. Operating assets in an integrated fashion and providing the best customer experience by addressing customer choice and flexibility expectations across segments.

Accordingly, Hydro-Québec will henceforth comprise four groups respectively in charge of strategy and development; integrated energy needs planning; infrastructure and the energy system; and operations and customer experience, including billing accuracy concerns that can influence satisfaction. To enable the company to carry out its mission, these groups will be able to count on the support of other groups responsible for corporate functions.

Across Canada, leadership changes at other utilities highlight the need to rebuild ties with governments and investors, as seen with Hydro One's new CEO in Ontario.

“For over 20 years, Hydro-Québec has been operating in a vertical structure based on its main activities, namely power generation, transmission and distribution. This approach must now give way to one that provides a cross-functional perspective allowing us to take informed decisions in light of all our needs, as well as those of our customers and the society we have the privilege to serve,” explained Hydro-Québec’s President and Chief Executive Officer, Sophie Brochu.

In terms of gender parity, the management team continues to include several men and women, thus ensuring a diversity of viewpoints.

Hydro-Québec’s new structure complies with the regulatory requirements of the North American power markets, in particular with regard to the need to provide third parties with non-discriminatory access to the company’s transmission system. The frameworks in place ensure that certain functions remain separate and help coordinate responses to operational events such as urban distribution outages that challenge continuity of service.

These changes, which will be implemented gradually as of Monday, February 28, do not aim to achieve any staff reductions.

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Duke Energy Carolinas Solar RFP draws 3.9 GW of utility-scale bids, oversubscribed in DEP and DEC, below avoided cost rates, minimal battery storage, strict PPA terms, and interconnection challenges across North and South Carolina.

Key Points

Utility-scale solar procurement in DEC and DEP, evaluated against avoided cost, with few storage bids and PPA terms.

✅ 3.9 GW bids for 680 MW; DEP most oversubscribed

✅ Most projects 7-80 MWac; few include battery storage

✅ Bids must price below 20-year avoided cost estimate

Last week the independent administrator for Duke’s 680 MW solar solicitation revealed data about the projects which have bid in response to the offer, showing a massive amount of interest in the opportunity.

Overall, 18 individuals submitted bids for projects in Duke Energy Carolinas (DEC) territory and 10 in Duke Energy Progress (DEP), with a total of more than 3.9 GW of proposals – more nearly 6x the available volume. DEP was relatively more over-subscribed, with 1.2 GWac of projects vying for only 80 MW of available capacity.

This is despite a requirement that such projects come in below the estimate of Duke’s avoided cost for the next 20 years, and amid changes in solar compensation that could affect project economics. Individual projects varied in capacity from 7-80 MWac, with most coming within the upper portion of that range.

These bids will be evaluated in the spring of 2019, and as Duke Energy Renewables continues to expand its portfolio, Duke Energy Communications Manager Randy Wheeless says he expects the plants to come online in a year or two.

Lack of storage

Despite recent trends in affordable batteries, of the 78 bids that came in only four included integrated battery storage. Tyler Norris, Cypress Creek Renewables’ market lead for North Carolina, says that this reflects that the methodology used is not properly valuing storage.

“The lack of storage in these bids is a missed opportunity for the state, and it reflects a poorly designed avoided cost rate structure that improperly values storage resources, commercially unreasonable PPA provisions, and unfavorable interconnection treatment toward independent storage,” Norris told pv magazine.

“We’re hopeful that these issues will be addressed in the second RFP tranche and in the current regulatory proceedings on avoided cost and state interconnection standards and grid upgrades across the region.”

Limited volume for North Carolina?

Another curious feature of the bids is that nearly the same volume of solar has been proposed for South Carolina as North Carolina – despite this solicitation being in response to a North Carolina law and ongoing legal disputes such as a church solar case that challenged the state’s monopoly model.

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U.S. Russian Uranium Import Ban reshapes nuclear fuel supply, bolstering energy security, domestic enrichment, and sanctions policy while diversifying reactor-grade uranium sources and supply chains through allies, waivers, and funding to sustain utilities and reliability.

Key Points

A U.S. law halting Russian uranium imports to boost energy security diversify nuclear fuel and revive U.S. enrichment.

✅ Cuts Russian revenue; reduces geopolitical risk.

✅ Funds U.S. enrichment; supports reactor fuel supply.

✅ Enables waivers to prevent utility shutdowns.

In a move aimed at reducing reliance on Russia and fostering domestic energy security for the long term, the United States has banned imports of Russian uranium, a critical component of nuclear fuel. This decision, signed into law by President Biden in May 2024, marks a significant shift in the U.S. nuclear fuel supply chain and has far-reaching economic and geopolitical implications.

For decades, Russia has been a major supplier of enriched uranium, a processed form of uranium used to power nuclear reactors. The U.S. relies on Russia for roughly a quarter of its enriched uranium needs, feeding the nation's network of 94 nuclear reactors operated by utilities which generate nearly 20% of the country's electricity. This dependence has come under scrutiny in recent years, particularly following Russia's invasion of Ukraine.

The ban on Russian uranium is a multifaceted response. First and foremost, it aims to cripple a key revenue stream for the Russian government. Uranium exports are a significant source of income for Russia, and by severing this economic tie, the U.S. hopes to weaken Russia's financial capacity to wage war.

Second, the ban serves as a national energy security measure. Relying on a potentially hostile nation for such a critical resource creates vulnerabilities. The possibility of Russia disrupting uranium supplies, either through political pressure or in the event of a wider conflict, is a major concern. Diversifying the U.S. nuclear fuel supply chain mitigates this risk.

Third, the ban is intended to revitalize the domestic uranium mining and enrichment industry, building on earlier initiatives such as Trump's uranium order announced previously. The U.S. has historically been a major uranium producer, but environmental concerns and competition from cheaper foreign sources led to a decline in domestic production. The ban, coupled with $2.7 billion in federal funding allocated to expand domestic uranium enrichment capacity, aims to reverse this trend.

The transition away from Russian uranium won't be immediate. The law includes a grace period until mid-August 2024, and waivers can be granted to utilities facing potential shutdowns if alternative suppliers aren't readily available. Finding new sources of enriched uranium will require forging partnerships with other uranium-producing nations like Kazakhstan, Canada on minerals cooperation, and Australia.

The long-term success of this strategy hinges on several factors. First, successfully ramping up domestic uranium production will require overcoming regulatory hurdles and addressing environmental concerns, alongside nuclear innovation to modernize the fuel cycle. Second, securing reliable alternative suppliers at competitive prices is crucial, and supportive policy frameworks such as the Nuclear Innovation Act now in law can help. Finally, ensuring the continued safe and efficient operation of existing nuclear reactors is paramount.

The ban on Russian uranium is a bold move with significant economic and geopolitical implications. While challenges lie ahead, the potential benefits of a more secure and domestically sourced nuclear fuel supply chain are undeniable. The success of this initiative will be closely watched not only by the U.S. but also by other nations seeking to lessen their dependence on Russia for critical resources.

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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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BC Hydro drought operations address climate change impacts with hydropower scheduling, reservoir management, water conservation, inflow forecasting, and fish habitat protection across the Lower Mainland and Vancouver Island while maintaining electricity generation from storage facilities.

Key Points

BC Hydro drought operations conserve water, protect fish, and sustain hydropower during extended heat and low inflows.

✅ Proactive reservoir releases protect downstream salmon spawning.

✅ Reduced flows at Puntledge, Coquitlam, and Ruskin/Stave facilities.

✅ System relies on northern storage to maintain electricity supply.

BC Hydro is adjusting its operating plans around power generation as extended heat and little forecast rain continue to impact the province, a report says.

“Unpredictable weather patterns related to climate change are expected to continue in the years ahead and BC Hydro is constantly adapting to these evolving conditions, especially after events such as record demand in 2021 that tested the grid,” said the report, titled “Casting drought: How climate change is contributing to uncertain weather and how BC Hydro’s generation system is adapting.”

The study said there is no concern with BC Hydro being able to continue to deliver power through the drought because there is enough water at its larger facilities, even as issues like crypto mining electricity use draw scrutiny from observers.

Still, it said, with no meaningful precipitation in the forecast, its smaller facilities in the Lower Mainland and on Vancouver Island will continue to see record low or near record low inflows for this time of the year.

“In the Lower Mainland, inflows since the beginning of September are ranked in the bottom three compared to historical records,” the report said.

The report said the hydroelectric system is directly impacted by variations in weather and the record-setting, unseasonably dry and warm weather this fall highlights the impacts of climate change, while demand patterns can be counterintuitive, as electricity use even increased during Earth Hour 2018 in some areas, hinting at challenges to come.

It noted symptoms of climate change include increased frequency of extreme events like drought and intense storms, and rapid glacial melt.

“With the extremely hot and dry conditions, BC Hydro has been taking proactive steps at many of our South Coast facilities for months to conserve water to protect the downstream fish habit,” spokesperson Mora Scott said. “We began holding back water in July and August at some facilities anticipating the dry conditions to help ensure we would have water storage for the later summer and early fall salmon spawning.”

Scott said BC Hydro’s reservoirs play an important role in managing these difficult conditions by using storage and planning releases to provide protection to downstream river flows. The reservoirs are, in effect, a battery waiting to be used for power.

While the dry conditions have had an impact on BC Hydro’s watersheds, several unregulated natural river systems — not related to BC Hydro — have fared worse, with rivers drying up and thousands of fish killed, the report said.

BC Hydro is currently seeing the most significant impacts on operations at Puntledge and Campbell River on Vancouver Island as well as Coquitlam and Ruskin/Stave in the Lower Mainland.

To help manage water levels on Vancouver Island, BC Hydro reduced Puntledge River flows by one-third last week and on the Lower Mainland reduced flows at Coquitlam by one-third and Ruskin/Stave by one quarter.

However, the utility company said, there are no concerns about continued power delivery.

“British Columbians benefit from BC Hydro’s integrated, provincial electricity system, which helps send power across the province, including to Vancouver Island, and programs like the winter payment plan support customers during colder months,” staff said.

Most of the electricity generated and used in B.C. is produced by larger facilities in the north and southeast of the province — and while water levels in those areas are below normal levels, there is enough water to meet the province’s power needs, even as additions like Site C's electricity remain a subject of debate among observers.

The Glacier Media investigation found a quarter of BC Hydro's power comes from the Mica, Revelstoke and Hugh Keenleyside dams on the Columbia River. Some 29% comes from dams in the Peace region, including the under-construction Site C project that has faced cost overruns. At certain points of the year, those reservoirs are reliant on glacier water.

Still, BC Hydro remains optimistic.

Forecasts are currently showing little rain in the near-term; however, historically, precipitation and inflows show up by the end of October. If that does not happen, BC Hydro said it would continue to closely track weather and inflow forecasts to adapt its operations to protect fish, while regional cooperation such as bridging with Alberta remains part of broader policy discussions.

Among things BC Hydro said it is doing to adapt are:

Continuously working to improve its weather and inflow forecasting;
Expanding its hydroclimate monitoring technology, including custom-made solutions that have been designed in-house, as well as upgrading snow survey stations to automated, real-time snow and climate stations, and;
Investing in capital projects — like spillway gate replacements — that will increase resiliency of the system to climate change.

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Generation Impact Report reveals how Canada's electricity sector can recruit Millennials and Gen Z, highlighting workforce gaps, career pathways, innovative projects, secure pay, and renewable energy opportunities to attract young talent nationwide.

Key Points

An EHRC survey on youth views of electricity careers and recruitment strategies to build a skilled workforce.

✅ Surveyed 1,500 Canadians aged 18-36 nationwide

✅ Highlights barriers: low awareness of sector roles

✅ Emphasizes fulfilling work, secure pay, innovation

Young Canadians make up far less of the electricity workforce than other sectors, says Electricity Human Resources Canada, as noted in an EHRC investment announcement that highlights sector priorities, and its latest report aims to answer the question “Why?”.

The report, “Generation Impact: Future Workforce Perspectives”, was based on a survey of 1500 respondents across Canada between the ages of 18 and 36. This cohort’s perspectives on the electricity sector were mostly Positive or Neutral, and that Millennial and Gen Z Canadians are largely open to considering careers in electricity, especially as initiatives such as a Nova Scotia energy training program expand access.

The biggest barrier is a knowledge gap in electrical safety that limits awareness of the opportunities available.

To an industry looking to develop a pipeline of young talent, “Generation Impact” reveals opportunities for recruitment; key factors that Millennial and Gen Z Canadians seek in their ideal careers include fulfilling work, secure pay and the chance to be involved in innovative projects, including specialized arc flash training in Vancouver opportunities that build expertise.

“The electricity sector is already home to the kinds of fulfilling and innovative careers that many in the Millennial and Gen Z cohorts are looking for,” said Michelle Branigan, CEO of EHRC. “Now it’s just a matter of communicating effectively about the opportunities and benefits, including leadership in worker safety initiatives, our sector can offer.”

“Engaging young workers in Canada’s electricity sector is critical for developing the resiliency and innovation needed to support the transformation of Canada’s energy future, especially as working from home drives up electricity bills and reshapes demand,” said Seamus O’Regan, Canada’s Minister of Natural Resources. “The insights of this report will help to position the sector competitively to leverage the talent and skills of young Canadians.”

“Generation Impact” was funded in part by the Government of Canada’s Student Work Placement Program and Natural Resources Canada’s Emerging Renewable Power Program, in a context of rising residential electricity use that underscores workforce needs.

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