New hysteria surrounds nuclear power

2019 Grid Edge Trends highlight evolving demand response, DER orchestration, real-time operations, AMI data, and EV charging, as wholesale markets seek flexibility and resiliency amid tighter reserve margins and fossil baseload retirements.

Key Points

Shifts toward DER-enabled demand response and real-time, behind-the-meter flexibility.

✅ Real-time DER dispatch enhances reliability during tight reserves

✅ AMI and ICT improve forecasting, monitoring, and control of resources

✅ Demand response shifts toward aggregated behind-the-meter orchestration

Which grid edge trends will continue into 2019 as the digital grid matures and what kind of disruption is on the horizon in the coming year?

From advanced metering infrastructure endpoints to electric-vehicle chargers, grid edge venture capital investments to demand response events, hundreds of data points go into tracking new trends at the edge of the grid amid ongoing grid modernization discussions across utilities.

Trends across these variables tell a story of transition, but perhaps not yet transformation. Customers hold more power than ever before in 2019, with utilities and vendors innovating to take advantage of new opportunities behind the meter. Meanwhile, external factors can always throw things off-course, including the data center boom that is posing new power challenges, and reliability is top of mind in light of last year's extreme weather events. What does the 2018 data say about 2019?

For one thing, demand response evolved, enabled by new information and communications technology. Last year, wholesale market operators increasingly sought to leverage the dispatch of distributed energy resource flexibility in close to real time. Three independent system operators and regional transmission organizations called on demand response five times in total for relief in the summer of 2018, including the NYISO.

The demand response events called in the last 18 months send a clear message: Grid operators will continue to call events year-round. This story unfolds as reserve margins continue to tighten, fossil baseload generation retirements continue, and system operators are increasingly faced with proving the resiliency and reliability of their systems while efforts to invest in a smarter electricity infrastructure gain momentum across the country.

In 2019, the total amount of flexible demand response capacity for wholesale market participation will remain about the same. However, the way operators and aggregators are using demand response is changing as information and communications technology systems improve and utilities are using AI to adapt to electricity demands, allowing the behavior of resources to be more accurately forecasted, monitored and controlled.

These improvements are allowing customer-sited resources to offer  flexibility services closer to real-time operations and become more reactive to system needs. At the same time, traditional demand response will continue to evolve toward the orchestration of DERs as an aggregate flexible resource to better enable growing levels of renewable energy on the grid.

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Manitoba Hydro Integrated Resource Plan outlines electrification-driven demand growth, clean electricity needs, wind generation, energy efficiency, hydropower strengths, and net-zero policy impacts, guiding investments to expand capacity and decarbonize Manitoba's grid.

Key Points

Manitoba Hydro IRP forecasting 2.5x demand, clean power needs, and capacity additions via wind and energy efficiency.

✅ Projects electricity demand could more than double within 20 years.

✅ Leverages 97% hydro supply; adds wind generation and efficiency.

✅ Positions for net-zero, electrification, and new capacity by the 2030s.

Electrical demand in Manitoba could more than double in the next 20 years, a trend echoed by BC Hydro's call for power in response to electrification, according to a new report from Manitoba Hydro.

On Tuesday, the Crown corporation released its first-ever Integrated Resource Plan (IRP), which not only predicts a significant increase in electrical demand, but also that new sources of energy, and a potential need for new power generation, could be needed in the next decade.

“Right now, what [our customers] are telling us, with the climate change objectives, with federal policy, provincial policies, is they see using electricity much more in the future than they do today,” said president and CEO of Manitoba Hydro Jay Grewal.

“And our current, where we’re at now, our customers have told us through all this consultation and engagement over the last two years, they’re going to want and need more than 2.5 times the electricity than we have in the province today.”

The IRP indicates that the move towards low or no-carbon energy sources will accelerate the need for clean electricity, which will require significant investments, including new turbine investments to expand capacity. Some of the clean energy measures Hydro is looking at for the future include wind generation and energy efficiency.

The report also found that Manitoba is in a good position as it prepares for the future due to its hydroelectric system, which delivers around 97 per cent of the yearly electricity. However, the province’s existing supply is limited, and vulnerable to Western Canada drought impacts on hydropower, so other electrical energy sources will be needed.

“Something Manitobans may not realize is, we are in such a privileged province, because 97 per cent of the electricity produced in Manitoba today is clean energy and net zero,” Grewal said.

Manitoba also supplies power to neighbouring utilities, with a SaskPower purchase agreement to buy more electricity under an expanded deal.

The IRP is the result of a two-year development process that involved multiple rounds of engagement with customers and other interested parties. The IRP is not a development plan, but it arrives as Hydro warns it can't service new energy-intensive customers under current capacity, and it outlines how Manitoba Hydro will monitor, prepare and respond to the changes in the energy landscape.

“We spoke with over 15,000 of our customers, whether they’re residential, commercial, industrial, industry associations, regulators, government – across the board, we talked with our customers,” said Grewal.

“And what we did was through this work, we understood what our customers are anticipating using electricity for going forward.

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Ontario Clean Energy Adjustment lowers hydro bills by shifting global adjustment costs, cutting time-of-use rates, and using OPG debt financing; ratepayers get inflation-capped increases for four years, then repay costs over 20 years.

Key Points

A 20-year line item repaying debt used to lower rates for 10 years by shifting global adjustment costs off hydro bills.

✅ 17% average bill cut takes effect after royal assent

✅ OPG-managed entity assumes debt for 10 years

✅ 20-year surcharge repays up to $28B plus interest

Ontarians will see lowered hydro bills for the next 10 years, but will then pay higher costs for the following 20 years, under new legislation tabled Thursday.

Ten weeks after announcing its plan to lower hydro bills, the Liberal government introduced legislation to lower time-of-use rates, take the cost of low-income and rural support programs off bills, and introduce new social programs.

It will lower time-of-use rates by removing from bills a portion of the global adjustment, a charge consumers pay for above-market rates to power producers. For the next 10 years, a new entity overseen by Ontario Power Generation will take on debt to pay that difference.

Then, the cost of paying back that debt with interest -- which the government says will be up to $28 billion -- will go back onto ratepayers' bills for the next 20 years as a "Clean Energy Adjustment."

An average 17-per-cent cut to bills will take effect 15 days after the hydro legislation receives royal assent, even as a Nov. 1 rate increase was set by the Ontario Energy Board, but there are just eight sitting days left before the Ontario legislature breaks for the summer. Energy Minister Glenn Thibeault insisted that leaves the opposition "plenty" of time for review and debate.

Premier Kathleen Wynne promised to cut hydro bills and later defended a 25% rate cut after widespread anger over rising costs helped send her approval ratings to record lows.

Electricity bills in the province have roughly doubled in the last decade, due in part to green energy initiatives, and Thibeault said the goal of this plan is to better spread out those costs.

"Like the mortgage on your house, this regime will cost more as we refinance over a longer period of time, but this is a more equitable and fair approach when we consider the lifespan of the clean energy investments, and generating stations across our province," he said.

NDP critic Peter Tabuns called it a "get-through-the-election" next June plan.

"We're going to take on a huge debt so Kathleen Wynne can look good on the hustings in the next few months and for decades we're going to pay for it," he said.

The legislation also holds rate increases to inflation for the next four years. After that, they'll rise more quickly, as illustrated by a leaked cabinet document the Progressive Conservatives unveiled Thursday.

The Liberals dismissed the document as containing outdated projections, but confirmed that it went before cabinet at some point before the government decided to go ahead with the hydro plan.

From about 2027 onward -- when consumers would start paying off the debt associated with the hydro plan -- Ontario electricity consumers will be paying about 12 per cent more than they would without the Liberal government's plan to cut costs in the short term, even though a deal with Quebec was not expected to reduce hydro bills, the government document projected.

But that was just one of many projections, said Energy Minister Glenn Thibeault.

"We have been working on this plan for months, and as we worked on it the documents and calculations evolved," he said.

The government's long-term energy plan is set to be updated this spring, and Thibeault said it will provide a more accurate look at how the hydro plan will reduce rates, even as a recovery rate could lead to higher hydro bills in certain circumstances.

Progressive Conservative critic Todd Smith said the "Clean Energy Adjustment" is nothing more than a revamped debt retirement charge, which was on bills from 2002 to 2016 to pay down debt left over from the old Ontario Hydro, the province's giant electrical utility that was split into multiple agencies in 1999 under the previous Conservative government.

"The minister can call it whatever he wants but it's right there in the graph, that there is going to be a new charge on the line," Smith said. "It's the debt retirement charge on steroids."

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U.S. Hybrid Vehicle Sales Outlook highlights rising hybrid demand as an EV bridge, driven by emissions rules, range anxiety, charging infrastructure gaps, and automaker strategies from Ford, Toyota, and Stellantis across U.S. markets.

Key Points

Forecast of U.S. hybrid sales shaped by EV adoption, emissions rules, charging access, and automaker strategies.

✅ S&P sees hybrids at 24% of U.S. sales by 2028

✅ Bridges ICE to EV amid range and charging concerns

✅ Ford, Toyota, Stellantis expand U.S. hybrid lineups

Hybrid gasoline-electric vehicles may not be dying as fast as some predicted in the auto sector’s rush to develop all-electric models.

Ford Motor is the latest of several top automakers, including Toyota and Stellantis, planning to build and sell hundreds of thousands of hybrid vehicles in the U.S. over the next five years, industry forecasters told Reuters.

The companies are pitching hybrids as an alternative for retail and commercial customers who are seeking more sustainable transportation, but may not be ready to make the leap to a full electric vehicle.

"Hybrids really serve a lot of America," said Tim Ghriskey, senior portfolio strategist at New York-based investment manager Ingalls & Snyder. "Hybrid is a great alternative to a pure electric vehicle (and) it's an easier sell to a lot of customers."

Interest in hybrids is rebounding as consumer demand for pure electrics has not accelerated as quickly as expected, with EV market share dipping in Q1 2024 according to some analyses. Surveys cite a variety of reasons for tepid EV demand, from high initial cost and concerns about range to lengthy charging times and a shortage of public charging infrastructure in many regions.

“With the tightening of emissions requirements, hybrids provide a cleaner fleet without requiring buyers to take the leap into pure electrics,” said Sam Fiorani, vice president at AutoForecast Solutions.

S&P Global Mobility estimates hybrids will more than triple over the next five years, accounting for 24% of U.S. new vehicle sales in 2028. Sales of pure electrics will claim about 37%, supported by strong U.S. EV sales into 2024 momentum, leaving combustion vehicles — including so-called “mild” hybrids — with a nearly 40% share.

S&P estimates hybrids will account for just 7% of U.S. sales this year, and pure electrics 9%, underscoring that EV sales still lag gas cars as internal combustion engine (ICE) vehicles take more than 80%.

Historically, hybrids have accounted for less than 10% of total U.S. sales, with Toyota’s long-running Prius among the most popular models. The Japanese automaker has consistently said hybrids will play a key role in the company's long-range electrification plans as it slowly ramps up investment in pure EVs.

Ford is the latest to roll out more aggressive hybrid plans. On its second-quarter earnings call in late July, Chief Executive Jim Farley surprised analysts, saying Ford expects to quadruple its hybrid sales over the next five years after earlier promising an aggressive push into all-electric vehicles.

“This transition to EVs will be dynamic,” Farley told analysts. “We expect the EV market to remain volatile until the winners and losers shake out.”

Among Ford’s competitors, General Motors appears to have little interest in hybrids in the U.S., while Stellantis will follow Toyota and Ford’s hedge by offering U.S. buyers a choice of different powertrains, including hybrids, until sales of pure electric vehicles start to take off after mid-decade, a potential EV inflection point according to forecaster GlobalData.

In a statement, GM said it, echoing leadership's view that EVs won't go mainstream until key issues are addressed, "continues to be committed to its all-electric future ... While we will have hybrid vehicles in our global fleet, our focus remains on transitioning our portfolio to electric by 2030.”

Stellantis said hybrids now account for 36% of Jeep Wrangler sales and 19% of Chrysler Pacifica sales. In addition to new pure electric models coming soon, "we are very bullish on hybrids going forward," a spokesperson said.

This year, manufacturers are marketing more than 60 hybrids in the U.S. Toyota and its premium Lexus brand are selling at least 18 different hybrid models, enabling the Japanese automaker to maintain its stranglehold on the sector.

Hyundai and sister brand Kia offer seven hybrid models, with Ford and Lincoln six. Stellantis offers just three, and GM’s sole entry, due out later this year, is a hybrid version of the Chevrolet Corvette sports car.

But hybrids remain in short supply at many U.S. dealerships.

Andrew DiFeo, dealer principal at Hyundai of St. Augustine, south of Jacksonville, FL, doesn't see EV adoption hitting the levels the Biden administration wants until EV charging networks are as ubiquitous as gas stations.

"Hybrids are a great bridge to whatever the future holds,” said DiFeo, adding, “I've got zero in stock (and) I've got customers that want all of them."

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Nova Scotia Power Rate Increase Settlement faces UARB scrutiny as regulators weigh electricity rates, fuel costs, storm rider provisions, Bill 212 limits, and Muskrat Falls impacts on ratepayers and affordability for residential and industrial customers.

Key Points

A deal proposing 13.8% electricity hikes for 2023-2024, before the UARB, covering fuel costs, a storm rider, and Bill 212.

✅ UARB review may set different rates than the settlement

✅ Fuel cost prepayment and hedging incentives questioned

✅ Storm rider shifts climate risk onto ratepayers

Nova Scotia Premier Tim Houston is calling on provincial regulators to reject a settlement agreement between Nova Scotia Power and customer groups that would see electricity rates rise by nearly 14% electricity rate hike over the next two years.

"It is our shared responsibility to protect ratepayers and I can't state strongly enough how concerned I am that the agreement before you does not do that," Houston wrote in a letter to the Nova Scotia Utility and Review Board late Monday.

Houston urged the three-member panel to "set the agreement aside and reach its own conclusion on the aforementioned application."

"I do not believe, based on what I know, that the proposed agreement is in the best interest of ratepayers," he said.

The letter does not spell out what his Progressive Conservative government would do if the board accepts the settlement reached last week between Nova Scotia Power and lawyers representing residential, small business and large industrial customer classes.

Other groups also endorsed the deal, although Nova Scotia Power's biggest customer — Port Hawkesbury Paper — did not sign on.

'We're protecting the ratepayers'
Natural Resources Minister Tory Rushton said the province was not part of the negotiations leading up to the settlement.

"As a government or department we had no intel on those conversations that were taking place," he said Tuesday. "So, we saw the information the same as the public did late last week, and right now we're protecting the ratepayers of Nova Scotia, even though the province cannot order Nova Scotia Power to lower rates under current law. We want to make sure that that voice is still heard at the UARB level."

Rushton said he didn't want to presuppose what the UARB will say.

"But I think the premier's been very loud and clear and I believe I have been, too. The ratepayers are at the top of our mind. We have different tools at our [disposal] and we'll certainly do what we can and need to [do] to protect those ratepayers."

The settlement agreement
If approved by regulators, rates would rise by 6.9 per cent in 2023 and 6.9 per cent in 2024 — almost the same amount on the table when hearings before the review board ended in September.

The Houston government later intervened with legislation, known as Bill 212, that capped rates to cover non-fuel costs by 1.8 per cent. It did not cap rates to cover fuel costs or energy efficiency programs.

In a statement announcing the agreement, Nova Scotia Power president Peter Gregg claimed the settlement adhered "to the direction provided by the provincial government through Bill 212."

Consumer advocate Bill Mahody, representing residential customers, told CBC News the proposed 13.8 per cent increase was "a reasonable rate increase given the revenue requirement that was testified to at the hearing."

Settlement 'remarkably' similar to NSP application
The premier disagrees, noting that the settlement and rate application that triggered the rate cap are "remarkably consistent."

He objects to the increased amount of fuel costs rolled into rates next year before the annual true up of actual fuel costs, which are automatically passed on to ratepayers.

"If Nova Scotia Power is effectively paid in advance, what motive do they have to hedge and mitigate the adjustment eventually required," Houston asked in his letter.

He also objected to the inclusion of a storm rider in rates to cover extreme weather, which he said pushed the risk of climate change on to ratepayers.

Premier second-guesses Muskrat Falls approval
Houston also second-guessed the board for approving Nova Scotia Power's participation in the Muskrat Falls hydro project in Labrador.

"The fact that Nova Scotians have paid over $500 million for this project with minimal benefit, and no one has been held accountable, is wrong," he said. "It was this board of the day that approved the contracts and entered the final project into rates."

Ratepayers are committed to paying $1.7 billion for the Maritime Link to bring the green source of electricity into the province, while rate mitigation talks in Newfoundland lack public details for their customers.

Although the Maritime Link was built on time and on budget by an affiliated company, only a fraction of Muskrat Falls hydro has been delivered because of ongoing problems in Newfoundland, including an 18% electricity rate hike deemed unacceptable by the province's consumer advocate.

"I find it remarkable that those contracts did not include different risk sharing mechanisms; they should have had provisions for issues in oversight of project management. Nevertheless, it was approved, and is causing significant harm to ratepayers in the form of increased rates."

Houston notes that because of non-delivery from Muskrat Falls, Nova Scotia Power has been forced to buy much more expensive coal to burn to generate electricity.

Opposition reaction
Opposition parties in Nova Scotia reacted to Houston's letter.

NDP Leader Claudia Chender dismissed it as bluster.

"It exposes his Bill 212 as not really helping Nova Scotians in the way that he said it would," she said. "Nothing in the settlement agreement contravenes that bill. But it seems that he's upset that he's been found out. And so here we are with another intervention in an independent regulatory body."

Liberal Leader Zach Churchill said the government should intervene to help ratepayers directly.

"We just think that it makes more sense to do that directly by supporting ratepayers through heating assistance, lump-sum electricity credits, rebate programs and expanding the eligibility for that or to provide funding directly to ratepayers instead of intervening in the energy market in this way," he said.

The premier's office said that no one was available when asked about an interview on Tuesday.

"The letter speaks for itself," the office responded.

Nova Scotia Power issued a statement Tuesday. It did not directly address Houston's claims.

"The settlement agreement is now with the NS Utility and Review Board," the utility said.

"The UARB process is designed to ensure customers are represented with strong advocates and independent oversight. The UARB will determine whether the settlement results in just and reasonable rates and is in the public interest."

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BC Hydro Crypto Mining Moratorium pauses high-load connection requests, as BCUC reviews electricity demand, gigawatt-hours and megawatt load forecasts, data center growth, and potential rate impacts on the power grid and industrial customers.

Key Points

A BC order pausing crypto mining connections while BC Hydro and BCUC assess load, grid impacts, and ratepayer risks.

✅ 18-month pause on new high-load crypto connections

✅ 1,403 MW in requests suspended; 273 MW existing or pending

✅ Seeks to manage demand, rates, and grid reliability

In its Nov. 1, 2022 load update briefing note to senior executives of the Crown corporation, BC Hydro shows that the entire large industrial sector accounted for 6,591 gigawatt-hours during the period – one percent less than forecast in the service plan.

BC Hydro censored load statistics about crypto mining, coal mining and chemicals from the briefing note, which was obtained under the freedom of information law and came amid scrutiny over B.C. electricity imports because it feared that disclosure would harm Crown corporation finances and third-party business interests.

Crypto mining requires high-powered computers to run and be cooled around the clock constantly. So much so that cabinet ordered the BC Utilities Commission (BCUC) last December to place an 18-month moratorium on crypto mining connection requests, while other jurisdictions, such as the N.B. Power crypto review, undertook similar pauses to assess impacts.

In a news release, the government said 21 projects seeking 1,403 megawatts were temporarily suspended. The government said that would be enough to power 570,000 homes or 2.1 million electric vehicles for a year.

A report issued by BC Hydro before Christmas said there were already 166 megawatts of power from operational projects at seven sites. Another six projects with 107 megawatts were nearing connection, bringing its total load to 273 megawatts.

Richard McCandless, a retired assistant deputy minister who analyzes the performance of BC Hydro and the Insurance Corp of British Columbia, said China's May 2021 ban on crypto mining had a major ripple effect on those seeking cheap and reliable power.

"When China cracked down, these guys fled to different areas," McCandless said in an interview. "So they took their computers and went somewhere else. Some wound up in B.C."

He said BC Hydro's secrecy about crypto loads appears rooted in the Crown corporation underestimating load demand, even as new generating stations were commissioned to bolster capacity.

"Crypto is up so dramatically; they didn't want to show that," McCandless said. "Maybe they didn't want to be seen as being asleep at the switch."

Indeed, BCUC's April 21 decision on BC Hydro's 2021 revenue forecasts through the 2025 fiscal year included BC Hydro's forecast increase for crypto and data centres of about 100 gigawatt-hours through fiscal 2024 before returning to 2021 levels by 2025. In addition, the BCUC document said that BC Hydro's December 2020 load forecast was lower than the previous one because of project cancellations and updated load requests, amid ongoing nuclear power debate in B.C.

"Given the segment's continued uncertainty and volatility, the forecast assumes these facilities are not long-lived," the BC Hydro application said.

A September 2022 report to the White House titled "Crypto-Assets in the United States" said increased electricity demand from crypto-asset mining could lead to rate increases.

"Crypto-asset mining in upstate New York increased annual household electric bills by [US]$82 and annual small business electric bills by [US]$164, with total net losses from local consumers and businesses estimated to be [US]$179 million from 2016-2018," the report said. The information mentioned Plattsburgh, New York's 18-month moratorium in 2018. Manitoba announced a similar suspension almost a month before B.C.

B.C.'s total core domestic load of 23,666 gigawatt-hours was two percent higher than the service plan amid BC Hydro call for power planning, with commercial and light industrial (9,198 gigawatt-hours) and residential (7,877 gigawatt-hours) being the top two customer segments.

"A cooler spring and warmer summer supported increased loads, as the Western Canada drought strained hydropower production regionally. However, warmer daytime temperatures in September impacted heating more than cooling," said the briefing note.

"Commercial and light industrial consumption benefited from warmer temperatures in August but has also been impacted to a lesser degree by the reduced heating load in the first three weeks of October."

Loads improved relative to 2021, but offices, retail businesses and restaurants remained below pre-pandemic levels. Education, recreation and hotel sectors were in line with pre-pandemic levels. Light industrial sector growth offset the declines.

For heavy industry, pulp and paper electricity use was 15 percent ahead of forecast, but wood manufacturing was 16 percent below forecast. The briefing note said oil and gas grew nine percent relative to the previous year but, alongside ongoing LNG power demand, fell nine percent below the service plan.

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