U.S. power plants to burn less coal in 2009

Utility Battery Storage Rankings measure grid-connected capacity, not ownership, highlighting MW, MWh, and watts per customer across PJM, MISO, and California IOUs, featuring Duke Energy, IPL, ancillary services, and frequency regulation benefits.

Key Points

Rankings that track energy storage connected to utility grids, comparing MW, MWh, and W/customer rather than ownership.

✅ Ranks by MW, MWh, and watts per customer, not asset ownership

✅ Highlights PJM, MISO cases and California IOUs' deployments

✅ Examples: Duke Energy, IPL, IID; ancillary services, frequency response

The rankings do not tally how much energy storage a utility built or owns, but how much was connected to their system. So while IPL built and owns the storage facility in its territory, Duke does not own the 16 MW of storage that connected to its system in 2016. Similarly, while California’s utilities are permitted to own some energy storage assets, they do not necessarily own all the storage facilities connected to their systems.

Measured by energy (MWh), IPL ranked fourth with 20 MWh, and Duke Energy Ohio ranked eighth with 6.1 MWh.

Ranked by energy storage watts per customer, IPL and Duke actually beat the California utilities, ranking fifth and sixth with 42 W/customer and 23 W/customer, respectively.

Duke ready for next step

Given Duke’s plans, including projects in Florida that are moving ahead, the utility is likely to stay high in the rankings and be more of a driving force in development. “Battery technology has matured, and we are ready to take the next step,” Duke spokesman Randy Wheeless told Utility Dive. “We can go to regulators and say this makes economic sense.”

Duke began exploring energy storage in 2012, and until now most of its energy storage efforts were focused on commercial projects in competitive markets where it was possible to earn revenues. Those included its 36 MW Notrees battery storage project developed in partnership with the Department of Energy in 2012 that provides frequency regulation for the Electric Reliability Council of Texas market and two 2 MW storage projects at its retired W.C. Beckjord plant in New Richmond, Ohio, that sells ancillary services into the PJM Interconnection market.

On the regulated side, most of Duke’s storage projects have had “an R&D slant to them,” Wheeless said, but “we are moving beyond the R&D concept in our regulated territory and are looking at storage more as a regulated asset.”

“We have done the demos, and they have proved out,” Wheeless said. Storage may not be ready for prime time everywhere, he said, but in certain locations, especially where it can it can be used to do more than one thing, it can make sense.

Wheeless said Duke would be making “a number of energy storage announcements in the next few months in our regulated states.” He could not provide details on those projects.

More flexible resources
Location can be a determining factor when building a storage facility. For IPL, serving the wholesale market was a driving factor in the rationale to build its 20 MW, 20 MWh storage facility in Indianapolis.

IPL built the project to address a need for more flexible resources in light of “recent changes in our resource mix,” including decreasing coal-fired generation and increasing renewables and natural gas-fired generation, as other regions plan to rely on battery storage to meet rising demand, Joan Soller, IPL’s director of resource planning, told Utility Dive in an email. The storage facility is used to provide primary frequency response necessary for grid stability.

The Harding Street storage facility in May. It was the first energy storage project in the Midcontinent ISO. But the regulatory path in MISO is not as clear as it is in PJM, whereas initiatives such as Ontario storage framework are clarifying participation. In November, IPL with the Federal Energy Regulatory Commission, asking the regulator to find that MISO’s rules for energy storage are deficient and should be revised.

Soller said IPL has “no imminent plans to install energy storage in the future but will continue to monitor battery costs and capabilities as potential resources in future Integrated Resource Plans.”

California legislative and regulatory push

In California, energy storage did not have to wait for regulations to catch up with technology. With legislative and regulatory mandates, including CEC long-duration storage funding announced recently, as a push, California’s IOUs took high places in SEPA’s rankings.

Southern California Edison and San Diego Gas & Electric were first and fourth (63.2 MW and 17.2 MW), respectively, in terms of capacity. SoCal Ed and SDG&E were first and second (104 MWh and 28.4 MWh), respectively, and Pacific Gas and Electric was fifth (17 MWh) in terms of energy.

But a public power utility, the Imperial Irrigation District (IID), ended up high in the rankings – second in capacity (30 MW) and third  in energy (20 MWh) – even though as a public power entity it is not subject to the state’s energy storage mandates.

But while IID was not under state mandate, it had a compelling regulatory reason to build the storage project. It was part of a settlement reached with FERC over a September 2011 outage, IID spokeswoman Marion Champion said.

IID agreed to a $12 million fine as part of the settlement, of which $9 million was applied to physical improvements of IID’s system.

IID ended up building a 30 MW, 20 MWh lithium-ion battery storage system at its El Centro generating station. The system went into service in October 2016 and in May, IID used the system’s 44 MW combined-cycle natural gas turbine at the generating station.

Passing savings to customers
The cost of the storage system was about $31 million, and based on its experience with the El Centro project, Champion said IID plans to add to the existing batteries. “We are continuing to see real savings and are passing those savings on to our customers,” she said.

Champion said the battery system gives IID the ability to provide ancillary services without having to run its larger generation units, such as El Centro Unit 4, at its minimum output. With gas prices at $3.59 per million British thermal units, it costs about $26,880 a day to run Unit 4, she said.

IID’s territory is in southeastern California, an area with a lot of renewable resources. IID is also not part of the California ISO and acts as its own balancing authority. The battery system gives the utility greater operational flexibility, in addition to the ability to use more of the surrounding renewable resources, Champion said.

In May, IID’s board gave the utility’s staff approval to enter into contract negotiations for a 7 MW, 4 MWh expansion of its El Centro storage facility. The negotiations are ongoing, but approval could come in the next couple months, Champion said.

The heart of the issue, though, is “the ability of the battery system to lower costs for our ratepayers,” Champion said. “Our planning section will continue to utilize the battery, and we are looking forward to its expansion,” she said.” I expect it will play an even more important role as we continue to increase our percentage of renewables.”

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US Summer Energy Bills Crisis is driven by record heatwaves, soaring electricity prices, AC cooling demand, energy poverty risks, and LIHEAP relief, straining low-income households, vulnerable seniors, and budgets amid volatile utilities and peak demand.

Key Points

Rising household energy costs from extreme heat, higher electricity prices, and AC demand, straining vulnerable families.

✅ Record heatwaves drive peak electricity and cooling loads

✅ Tiered rates and volatile markets inflate utility bills

✅ LIHEAP aid and cooling centers offer short-term relief

As the sweltering heat of summer continues to grip much of the United States, American households are grappling with a staggering rise in energy bills. The combination of record-breaking temperatures and rising electricity prices is placing an unprecedented financial strain on families, raising concerns about the long-term impact on household budgets and overall well-being.

Record Heat and Energy Consumption

This summer has witnessed some of the hottest temperatures on record across the country. With many regions experiencing prolonged heatwaves, the demand for air conditioning and cooling systems has surged amid unprecedented electricity demand across parts of the U.S. The increased use of these energy-intensive appliances has led to a sharp rise in electricity consumption, which, combined with elevated energy prices, has pushed household energy bills to new heights.

The situation is particularly dire for households that are already struggling financially. Many families are facing energy bills that are not only higher than usual but are reaching levels that are unsustainable, underscoring electricity struggles for thousands of families across the country. This has prompted concerns about the potential for energy poverty, where individuals are forced to make difficult choices between paying for essential services and covering other necessary expenses.

Impact on Low-Income and Vulnerable Households

Low-income households and vulnerable populations are disproportionately affected by these soaring energy costs. For many, the financial burden of high energy bills is compounded by energy insecurity during the pandemic and other economic pressures, such as rising food prices and stagnant wages. The strain of paying for electricity during extreme heat can lead to tough decisions, including cutting back on other essential needs like healthcare or education.

Moreover, the heat itself poses a serious health risk, particularly for the elderly, children, and individuals with pre-existing health conditions. High temperatures can exacerbate conditions such as cardiovascular and respiratory illnesses, making the need for reliable cooling even more critical. For those struggling to afford adequate cooling, the risk of heat-related illnesses and fatalities increases significantly.

Utilities and Energy Pricing

The sharp rise in energy bills can be attributed to several factors, including higher costs of electricity production and distribution. The ongoing transition to cleaner energy sources, while necessary for long-term environmental sustainability, has introduced short-term volatility in energy markets. Additionally, power-company supply chain crises and increased demand during peak summer months have contributed to higher prices.

Utilities are often criticized for their pricing structures, which can be complex and opaque. Some regions, including areas where California electricity bills soar under scrutiny, use tiered pricing models that charge higher rates as energy consumption increases. This can disproportionately impact households that need to use more energy during extreme heat, further exacerbating financial strain.

Government and Community Response

In response to the crisis, various government and community initiatives are being rolled out to provide relief. Federal and state programs aimed at assisting low-income households with energy costs are being expanded. These programs, such as the Low-Income Home Energy Assistance Program (LIHEAP), offer financial assistance to help with utility bills, but demand often outstrips available resources.

Local community organizations are also stepping in to offer support. Initiatives include distributing fans and portable air conditioners, providing temporary cooling centers, and offering financial assistance to help cover energy costs. These efforts are crucial in helping to mitigate the immediate impact of high energy bills on vulnerable households.

Long-Term Solutions and Sustainability

The current crisis highlights the need for long-term solutions to address both the causes and consequences of high energy costs. Investing in energy efficiency and renewable energy technologies can help reduce the overall demand for electricity and lower long-term costs. Improvements in building insulation, the adoption of energy-efficient appliances, and advancements in smart grid technologies to prevent summer power outages are all essential components of a sustainable energy future.

Furthermore, addressing income inequality and supporting economic stability are critical to ensuring that all households can manage their energy needs without facing financial hardship. Policymakers will need to consider a range of strategies, including financial support programs, regulatory reforms, and infrastructure investments, to create a more equitable and resilient energy system.

Conclusion

As American households endure the double burden of extreme summer heat and skyrocketing energy bills, the need for immediate relief and long-term solutions has never been clearer. The current crisis serves as a reminder of the broader challenges facing the nation’s energy system and the importance of addressing both short-term needs and long-term sustainability. By investing in efficient technologies, supporting vulnerable populations, and developing resilient infrastructure, the U.S. can work towards a future where energy costs are manageable, and everyone has access to the resources they need to stay safe and comfortable.

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Nalcor Energy Pandemic Loss underscores Muskrat Falls delays, hydroelectric risks, oil price shocks, and COVID-19 impacts, affecting ratepayers, provincial debt, timelines, and software commissioning for the Churchill River project and Atlantic Canada subsea transmission.

Key Points

A $171M Q1 2020 downturn linked to COVID-19, oil price collapse, and Muskrat Falls delays impacting schedules and costs.

✅ Q1 2020 profit swing: +$92M to -$171M amid oil price crash

✅ Muskrat Falls timeline slips; cost may reach $13.1B

✅ Software, workforce, COVID-19 constraints slow commissioning

Newfoundland and Labrador's Crown energy corporation reported a pandemic-related profit loss from the first quarter of 2020 on Tuesday, along with further complications to the beleaguered Muskrat Falls hydroelectric project.

Nalcor Energy recorded a profit loss of $171 million in the first quarter of 2020, down from a $92 million profit in the same period last year, due in part to falling oil prices during the COVID-19 pandemic.

The company released its financial statements for 2019 and the first quarter of 2020 on Tuesday, and officials discussed the numbers in a livestreamed presentation that detailed the impact of the global health crisis on the company's operations.

The loss in the first quarter was caused by lower profits from electricity sales and a drop in oil prices due to the pandemic and other global events, company officials said.

The novel coronavirus also added to the troubles plaguing the Muskrat Falls hydroelectric dam on Labrador's Churchill River, amid Quebec-N.L. energy tensions that long predate the pandemic.

Work at the remote site stopped in March over concerns about spreading the virus. Operations have been resuming slowly, with a reduced workforce tackling the remaining jobs.

Officials with Nalcor said it will likely be another year before the megaproject is complete.

CEO Stan Marshall estimates the months of delays could bring the total cost to $13.1 billion including financing, up from the previous estimate of $12.7 billion -- though the total impact of the coronavirus on the project's price tag has yet to be determined.

"If we're going to shut down again, all of that's wrong," Marshall said. "But otherwise, we can just carry on and we'll have a good idea of the productivity level. I'm hoping that by September we'll have a more definitive number here."

The 824 megawatt hydroelectric dam will eventually send power to Newfoundland, and later Nova Scotia, through subsea cables, even as Nova Scotia boosts wind and solar in its energy mix.

It has seen costs essentially double since it was approved in 2012, and faced significant delays even before pandemic-forced shutdowns in North America and around the world this spring.

Cost and schedule overruns were the subject of a sweeping inquiry that held hearings last year, while broader generation choices like biomass use have drawn scrutiny as well.

The commissioner's report faulted previous governments for failing to protect residents by proceeding with the project no matter what, and for placing trust in Nalcor executives who "frequently" concealed information about schedule, cost and related risks.

Some of the latest delays have come from challenges with the development of software required to run the transmission link between Labrador and Newfoundland, where winter reliability issues have been flagged in reports.

The software is still being worked out, Marshall said Tuesday, and the four units at the dam will come online gradually over the next year.

"It's not an all or nothing thing," Marshall said of the final work stages.
Nalcor's financial snapshot follows a bleak fiscal update from the province this month. The Liberal government reported a net debt of $14.2 billion and a deficit of more than $1.1 billion, even as a recent Churchill Falls deal promised new revenues for the province, citing challenges from pandemic-related closures and oil production shutdowns.

Finance Minister Tom Osborne said at the time that help from Ottawa will be necessary to get the province's finances back on track.

Muskrat Falls represents about one-third of the province's debt, and is set to produce more power than the province of about half a million people requires. Anticipated rate increases due to the ballooning costs and questions about Muskrat Falls benefits have posed a significant political challenge for the provincial government.

Ottawa has agreed to work with Newfoundland and Labrador on a rewrite of the project's financial structure, scrapping the format agreed upon in past federal-provincial loan agreements in order to ease the burden on ratepayers, while some argue independent planning would better safeguard ratepayers.

Marshall, a former Fortis CEO who was brought in to lead Nalcor in 2016, has called the project a "boondoggle" and committed to seeing it completed within four years. Though that plan has been disrupted by the pandemic, Marshall said the end is in sight.

"I'm looking forward to a year from now. And I hope to be gone," Marshall said.

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Electric power market crisis highlights grid reliability risks as coal and nuclear retire amid subsidies, mandates, and cheap natural gas; intermittent wind and solar raise blackout concerns, resilience costs, and pricing distortions across regulated markets.

Key Points

Reliability and cost risks as coal and nuclear retire; subsidies distort prices; intermittent renewables strain grid.

✅ Coal and nuclear retirements reduce baseload capacity

✅ Subsidies and mandates distort market pricing signals

✅ Intermittent renewables increase blackout and grid risk

Is anyone paying any attention to the crisis that is going on in our electric power markets?

Over the past six months at least four major nuclear power plants have been slated for shutdown, including the last one in operation in California. Meanwhile, dozens of coal plants have been shuttered as well — despite low prices and cleaner coal. Some of our major coal companies may go into bankruptcy.

This is a dangerous game we are playing here with our most valuable resource — outside of clean air and water. Traditionally, we've received almost half our electric power nationwide from coal and nuclear power, and for good reason. They are cheap sources of power and they are highly resilient and reliable.

The disruption to coal and nuclear power wouldn't be disturbing if this were happening as a result of market forces. That's only partially the case.

#google#

The amazing shale oil and gas revolution is providing Americans with cheap gas for home heating and power generation. Hooray. The price of natural gas has fallen by nearly two-thirds over the last decade and this has put enormous price pressure on other forms of power generation.

But this is not a free-market story of Schumpeterian creative destruction. If it were, then wind and solar power would have been shutdown years ago. They can't possibly compete on a level playing field with $3 natural gas.

In most markets solar and wind power survive purely because the states mandate that as much as 30 percent of residential and commercial power come from these sources. The utilities have to buy it regardless of price, even as electricity demand is flat in many regions. What a sweet deal. The California state legislature just mandated that every new home spend $10,000 on solar panels on the roof.

Well over $100 billion of subsidies to big wind and big solar were doled out over the last decade, and even with the avalanche of taxpayer subsidies and bailout funds many of these companies like Solyndra (which received $500 million in handouts) failed, underscoring why a green revolution hasn't materialized as promised.

These industries are not anywhere close to self sufficiency. In 2017 amid utility trends to watch the wind industry admitted that without a continuation of a multi-billion tax credit, the wind turbines would stop turning.

This combines with the left's war on coal through regulations that have destroyed coal plants in many areas. (Thank goodness for the exports of coal or the industry would be in much bigger trouble.)

Bottom line: Our power market is a Soviet central planner's dream come true and it is extinguishing our coal and nuclear industries.

Why should anyone care?

First, because government subsidies, regulations and mandates make electric power more expensive. Natural gas prices have fallen by two-thirds, but electric power costs have still risen in most areas — thanks to the renewable mandates.

More importantly, the electric power market isn't accurately pricing in the value of resilience and reliability. What is the value of making sure the lights don't go off? What is the cost to the economy and human health if we have rolling brownouts and blackouts because the aging U.S. grid doesn't have enough juice during peak demand.

Politicians, utilities and federal regulators are shortsightedly killing our coal and nuclear capacities without considering the risk of future energy shortages and power disruptions. Once a nuclear plant is shutdown, you can't just fire it back up again when you need it.

Wind and solar are notoriously unreliable. Most places where wind power is used, coal plants are needed to back up the system during peak energy use and when the wind isn't blowing.

The first choice to fix energy markets is to finally end the tangled web of layers and layers of taxpayer subsidies and mandates and let the market choose. Alas, that's nearly impossible given the political clout of big wind and solar.

The second best solution is for the regulators and utilities to take into account the grid reliability and safety of our energy. Would people be willing to pay a little more for their power to ensure against brownouts? I sure would. The cost of having too little energy far exceeds the cost of having too much.

A glass of water costs pennies, but if you're in a desert dying of thirst, that water may be worth thousands of dollars.

I'll admit I'm not sure what the best solution is to the power plant closures. But if we have major towns and cities in the country without electric power for stretches of time because of green energy fixation, Americans are going to be mighty angry and our economy will take a major hit.

When our manufacturers, schools, hospitals, the internet and iPhones shut down, we're not going to think wind and solar power are so chic.

If the lights start to go out five or 10 years from now, we will look back at what is happening today and wonder how we could have been so darn stupid.

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San Juan Generating Station eyed for $1 coal-plant sale, as Farmington and Acme propose CCS retrofit, meeting emissions caps and renewable mandates by selling captured CO2 for enhanced oil recovery via a nearby pipeline.

Key Points

A New Mexico coal plant eyed for $1 and a CCS retrofit to cut emissions and sell CO2 for enhanced oil recovery.

✅ $400M-$800M CCS retrofit; 90% CO2 capture target

✅ CO2 sales for enhanced oil recovery; 20-mile pipeline gap

✅ PNM projects shutdown savings; renewable and emissions mandates

One dollar. That’s how much an aging New Mexico coal plant is worth. And by some estimates, even that may be too much.

Acme Equities LLC, a New York-based holding company, is in talks to buy the 847-megawatt San Juan Generating Station for $1, after four of its five owners decided to shut it down. The fifth owner, the nearby city of Farmington, says it’s pursuing the bargain-basement deal with Acme to avoid losing about 1,600 direct and indirect jobs in the area amid a broader just transition debate for energy workers.

We respectfully disagree with the notion that the plant is not economical

Acme’s interest comes as others are looking to exit a coal industry that’s been plagued by costly anti-pollution regulations. Acme’s plan: Buy the plant "at a very low cost," invest in carbon capture technology that will lower emissions, and then sell the captured CO2 to oil companies, said Larry Heller, a principal at the holding group.

By doing this, Acme “believes we can generate an acceptable rate of return,” Heller said in an email.

Meanwhile, San Juan’s majority owner, PNM Resources Inc., offers a distinctly different view, echoing declining coal returns reported by other utilities. A 2022 shutdown will push ratepayers to other energy alternatives now being planned, saving them about $3 to $4 a month on average, PNM has said.

“We could not identify a solution that would make running San Juan Generating Station economical,” said Tom Fallgren, a PNM vice president, in an email.

The potential sale comes as a new clean-energy bill, supported by Governor Lujan Grisham, is working its way through the state legislature. It would require the state to get half of its power from renewable sources by 2030, and 100 percent by 2045, even as other jurisdictions explore small modular reactor strategies to meet future demand. At the same time, the legislation imposes an emissions cap that’s about 60 percent lower than San Juan’s current levels.

In response, Acme is planning to spend $400 million to $800 million to retrofit the facility with carbon capture and sequestration technology that would collect carbon dioxide before it’s released into the atmosphere, Heller said. That would put the facility into compliance with the pending legislation and, at the same time, help generate revenue for the plant.

The company estimates the system would cut emissions by as much as 90 percent, and the captured gas could be sold to oil companies, which uses it to enhance well recovery. The bottom line, according to Heller: “A winning financial formula.”

It’s a tricky formula at best. Carbon-capture technology has been controversial, even as new coal plant openings remain rare, expensive to install and unproven at scale. Additionally, to make it work at the San Juan plant, the company would need to figure out how to deliver the CO2 to customers since the nearest pipeline is about 20 miles (32 kilometers) away.

Reducing costs

Acme is also evaluating ways to reduce costs at San Juan, Heller said, including approaches seen at operators extending the life of coal plants under regulatory scrutiny, such as negotiating a cheaper coal-supply contract and qualifying for subsidies.

Farmington’s stake in the plant is less than 10 percent. But under terms of the partnership, the city — population 45,000 — can assume full control of San Juan should the other partners decide to pull out, mirroring policy debates over saving struggling nuclear plants in other regions. That’s given Farmington the legal authority to pursue the plant’s sale to Acme.

At the end of the day, nobody wants the energy

“We respectfully disagree with the notion that the plant is not economical,” Farmington Mayor Nate Duckett said by email. Ducket said he’s in better position than the other owners to assess San Juan’s importance “because we sit at Ground Zero.”

The city’s economy would benefit from keeping open both the plant and a nearby coal mine that feeds it, according to Duckett, with operations that contribute about $170 million annually to the local area.

While the loss of those jobs would be painful to some, Camilla Feibelman, a Sierra Club chapter director, is hard pressed to see a business case for keeping San Juan open, pointing to sector closures such as the Three Mile Island shutdown as evidence of shifting economics. The plant isn’t economical now, and would almost certainly be less so after investing the capital to add carbon-capture systems.

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BC Hydro Grid Modernization accelerates clean energy and electrification, upgrading transmission lines, substations, and hydro dams to deliver renewable power for EVs and heat pumps, strengthen grid reliability, and enable industrial decarbonization in British Columbia.

Key Points

A $36B, 10-year plan to expand and upgrade B.C.'s clean grid for electrification, reliability, and industrial growth.

✅ $36B for lines, substations, and hydro dam upgrades

✅ Enables EV charging, heat pumps, and smart demand response

✅ Prioritizes industrial electrification and Indigenous partnerships

In a significant move towards a clean energy transition, British Columbia has announced a substantial $36-billion investment to enlarge and upgrade its electricity grid over the next ten years. The announcement last Tuesday from BC Hydro indicates a substantial 50 percent increase from its prior capital plan. A major portion of this investment is directed towards new consumer connections and improving current infrastructure, including substations, transmission lines, and hydro dams for more efficient power generation.

The catalyst behind this major investment is the escalating demand for clean energy across residential, commercial, and industrial sectors in British Columbia. Projections show a 15 percent rise in electricity demand by 2030. According to the Canadian Climate Institute's models, achieving Canada’s climate goals will require extensive electrification across various sectors, raising questions about a net-zero grid by 2050 nationwide.

BC Hydro is planning substantial upgrades to the electrical grid to meet the needs of a growing population, decreasing industry carbon emissions, and the shift towards clean technology. This is vital, especially as the province works towards improving housing affordability and as households face escalating costs from the impacts of climate change and increasing exposure to harsh weather events. Affordable, reliable power and access to clean technologies such as electric vehicles and heat pumps are becoming increasingly important for households.

British Columbia is witnessing a significant shift from fossil fuels to clean electricity in powering homes, vehicles, and workplaces. Electric vehicle usage in B.C. has increased twentyfold in the past six years. Last year, one in every five new light-duty passenger vehicles sold in B.C. was electric – the highest rate in Canada. Additionally, over 200,000 B.C. homes are now equipped with heat pumps, indicating a growing preference for the province’s 98 percent renewable electricity.

The investment also targets reducing industrial emissions and attracting industrial investment. For instance, the demand for transmission along the North Coastline, from Prince George to Terrace, is expected to double this decade, especially from sectors like mining. Mining companies are increasingly looking for locations with access to clean power to reduce their carbon footprint.

This grid enhancement plan in B.C. is reflective of similar initiatives in provinces like Quebec and the legacy of Manitoba hydro history in building provincial systems. Hydro-Québec announced a substantial $155 to $185 billion investment in its 2035 Action Plan last year, aimed at supporting decarbonization and economic growth. By 2050, Hydro-Québec predicts a doubling of electricity demand in the province.

Both utilities’ strategies focus on constructing new facilities and enhancing existing assets, like upgrading dams and transmission lines. Hydro-Québec, for instance, includes energy efficiency goals in its plan to double customer savings and potentially save over 3,500 megawatts of power.

However, with this level of investment, provinces need to engage in dialogue about priorities and the optimal use of clean electricity resources, with concepts like macrogrids offering potential benefits. Quebec, for instance, has shifted from a first-come, first-served basis to a strategic review process for significant new industrial power requests.

B.C. is also moving towards strategic prioritization in its energy strategy, evident in its recent moratorium on new connections for virtual currency mining due to their high energy consumption.

Indigenous partnership and leadership are also key in this massive grid expansion. B.C.’s forthcoming Call for Power and Quebec’s financial partnerships with Indigenous communities indicate a commitment to collaborative approaches. British Columbia has also allocated $140 million to support Indigenous-led power projects.

Regarding the rest of Canada, electricity planning varies in provinces with deregulated markets like Ontario and Alberta. However, these provinces are adapting too, and the federal government has funded an Atlantic grid study to improve regional planning efforts. Ontario, for example, has provided clear guidance to its system operator, mirroring the ambition in B.C. and Quebec.

Utilities are rapidly working to not only expand and modernize energy grids but also to make them more resilient, affordable, and smarter, as demonstrated by recent California grid upgrades funding announcements across the sector. Hydro-Québec focuses on grid reliability and affordability, while B.C. experiments with smart-grid technologies.

Both Ontario and B.C. have programs encouraging consumers to reduce consumption in real-time, demonstrating the potential of demand-side management. A recent instance in Alberta showed how customer participation could prevent rolling blackouts by reducing demand by 150 megawatts.

This is a crucial time for all Canadian provinces to develop larger, smarter energy grids, including a coordinated western Canadian electricity grid approach for a sustainable future. Utilities are making significant strides towards this goal.
 

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