Wind farm opponents turn up heat

Pickering Nuclear Alert Error prompts Ontario investigation into the Alert Ready emergency alert system, Pelmorex safeguards, and public response at Pickering Nuclear Generating Station, including potassium iodide orders and geo-targeted notification issues.

Key Points

A mistaken Ontario emergency alert about the Pickering plant, now under probe for human error and system safeguards.

✅ Investigation led by Emergency Management Ontario

✅ Alert Ready and Pelmorex safeguards under review

✅ KI pill demand surged; geo-targeting questioned

A number of questions still remain a week after an emergency alert was mistakenly sent out to people across Ontario warning of an unspecified incident at the Pickering Nuclear Generating Station. 

The province’s solicitor general has stepped in and says an investigation into the incident should be completed fairly quickly according to the minister.

However, the nuclear scare has still left residents on edge with tens of thousands of people ordering potassium iodide, or KI, pills that protect the body from radioactive elements in the days following the incident.

Here’s what we know and still don’t know about the mistaken Pickering nuclear plant alert:

Who sent the alert?

According to the Alert Ready Emergency Alert System website, the agency works with several federal, provincial and territorial emergency management officials, Environment and Climate Change Canada and Pelmorex, a broadcasting industry and wireless service provider, to send the alerts.

Martin Belanger, the director of public alerting for Pelmorex, a company that operates the alert system, said there are a number of safeguards built in, including having two separate platforms for training and live alerts.

"The software has some steps and some features built in to minimize that risk and to make sure that users will be able to know whether or not they're sending an alert through the... training platform or whether they're accessing the live system in the case of a real emergency," he said.

Only authorized users have access to the system and the province manages that, Belanger said. Once in the live system, features make the user aware of which platform they are using, with various prompts and messages requiring the user's confirmation. There is a final step that also requires the user to confirm their intent of issuing an alert to cellphones, radio and TVs, Belanger said.

Last Sunday, a follow-up alert was sent to cellphones nearly two hours after the original notification, and during separate service disruptions such as a power outage in London residents also sought timely information.

What has the investigation revealed?

It’s still unclear as to how exactly the alert was sent in error, but Solicitor General Sylvia Jones has tapped the Chief of Emergency Management Ontario to investigate.

"It's very important for me, for the people of Ontario, to know exactly what happened on Sunday morning," Jones said.

Jones said initial observations suggest human error was responsible for the alert that was sent out during routine tests of the emergency alert.

“I want to know what happened and equally important, I want some recommendations on insurances and changes we can make to the system to make sure it doesn't happen again,” Jones said.

Jones said she expects the results of the probe to be made public.

Can you unsubscribe from emergency alerts?

It’s not possible to opt out of receiving the alerts, according to the Alert Ready Emergency Alert System website, and Ontario utilities warn about scams to help customers distinguish official notices.

“Given the importance of warning Canadians of imminent threats to the safety of life and property, the CRTC requires wireless service providers to distribute alerts on all compatible wireless devices connected to an LTE network in the target area,” the website reads.

The agency explains that unlike radio and TV broadcasting, the wireless public alerting system is geo-targeted and is specific to the a “limited area of coverage”, and examples like an Alberta grid alert have highlighted how jurisdictions tailor notices for their systems.

“As a result, if an emergency alert reaches your wireless device, you are located in an area where there is an imminent danger.”

The Pickering alert, however, was received by people from as far as Ottawa to Windsor.

Is the Pickering Nuclear Generating Station closing?

The Pickering nuclear plant has been operating since 1971, and had been scheduled to be decommissioned this year, but the former Liberal government -- and the current Progressive Conservative government -- committed to keeping it open until 2024. Decommissioning is now set to start in 2028.

It operates six CANDU reactors, and in contingency planning operators have considered locking down key staff to maintain reliability, generates 14 per cent of Ontario's electricity and is responsible for 4,500 jobs across the region, according to OPG, while utilities such as Hydro One's relief programs have supported customers during broader crises.

What should I do if I receive an emergency alert?

Alert Ready says that if you received an alert on your wireless device it’s important to take action “safely”.

“Stop what you are doing when it is safe to do so and read the emergency alert,” the agency says on their website.

“Alerting authorities will include within the emergency alert the information you need and guidance for any action you are required to take, and insights from U.S. grid pandemic response underscore how critical infrastructure plans intersect with public safety.”

“This could include but is not limited to: limit unnecessary travel, evacuate the areas, seek shelter, etc.”

The wording of last Sunday's alert caused much initial confusion, warning residents within 10 kilometres of the plant of "an incident," though there was no "abnormal" release of radioactivity and residents didn't need to take protective steps, but emergency crews were responding.

“In the event of a real emergency, the wording would be different,” Jones said.

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OEB Hydro One Rate Decision 2023-2027 sets approved transmission and distribution rates in Ontario, with a settlement reducing revenue requirement, modest bill impacts, higher productivity factors, inflation certainty, DVA credits, and First Nations participation measures.

Key Points

OEB-approved Hydro One 2023-2027 transmission and distribution rates settlement, lowering costs and limiting bill impacts.

✅ $482.7M revenue reductions vs. original proposal

✅ Avg bill impact: +$0.69 trans., +$2.43 distr. per month

✅ Faster DVA refunds; productivity and efficiency incentives

The Ontario Energy Board (OEB) issued its Decision and Order on an application filed by Hydro One Networks Inc. (Hydro One) on August 5, 2021 seeking approval for changes to the rates it charges for electricity transmission and distribution, beginning January 1, 2023 and for each subsequent year through to December 31, 2027. 

The proceeding resulted in the filing of a settlement proposal that the OEB has now approved after concluding that it is in the public interest. 

The negotiated reductions in Hydro One's transmission and distribution revenue requirements over the 2023 to 2027 period total $482.7 million compared to the requests made by Hydro One in its application.

The OEB found that the reductions in Hydro One's proposed capital expenditure and operating, maintenance and administration costs were reasonable, and should not compromise the safety and reliability of Hydro One's transmission and distribution systems. It also concluded that the estimated bill impacts for both transmission and distribution customers are reasonable, and that the January 1, 2023 implementation and effective date of the new rates is appropriate.

In the broader Canadian context, pressures on utility finances at other companies, such as Manitoba Hydro's debt provide additional background for stakeholders.

Bill Impacts

This proceeding related to both transmission and distribution operations.

Transmission

The new transmission revenue requirement will affect Ontario electricity consumers across the province because it will be incorporated into updated transmission rates, which are paid by electricity distributors and other large consumers connected directly to the transmission system, and distributors then pass this cost on to their customers.

As a result of the settlement approved on the transmission portion of the application, it is estimated that for a typical Hydro One residential customer with a monthly consumption of 750 kWh, the total bill impact averaged over the 2023-2027 period will be an increase of $0.69 per month or 0.5%, which follows the 2021 electricity rate reductions that affected many businesses.

Distribution

The new OEB-approved distribution rates will affect Hydro One's distribution customers, including areas served through acquisitions such as the Peterborough Distribution sale which expanded its customer base.

As a result of the settlement reached on the distribution portion of the application, it is estimated that for a typical residential distribution customer of Hydro One with a monthly consumption of 750 kWh, the total bill impact averaged over the 2023-2027 period will be an increase of $2.43 per month or 1.5%.
This proceeding included 24 approved intervenors representing a wide variety of customer classes and other interests. Representatives of 18 of those intervenors participated in the settlement conference. Having this diversity of perspective enriches the already thorough examination of evidence and argument that the OEB routinely undertakes when considering an application.

Other features of the settlement proposal include:

• A commitment by Hydro One to include, in future operational and capital investment plans, a discussion of how the proposed spending will directly support the achievement of Hydro One's climate change policy.
• Eliminating further updates to reflect changes to inflation in 2022 and 2023 as originally proposed, to provide Hydro One's customers with greater certainty as to the potential impacts of inflation on their bills.
• Increases in the productivity factors and supplemental stretch factors for both the distribution and transmission business segments which will provide Hydro One with additional incentives to achieve greater efficiencies during the 2023 to 2027 period.
• Undertaking certain measures to seek economic participation or equity investment opportunities from First Nations.
• Disposition of net credit balances in deferral and variance accounts (DVAs) owed to customers will be returned over a shorter period of time:
• Transmission DVA – $22.5M over a one-year period in 2023 (versus five years)
• Distribution DVA – $85.9M over a three-year period – 2023-2025 (versus five years)
• Undertaking certain measures to continue examining cost-effective transmission and distribution line losses
• In the decision, the OEB acknowledged the efforts involved by parties to participate in this entire proceeding, including the settlement conference, considering the number of participants, the complexity of the issues, and the challenging logistics of a "virtual" proceeding. The OEB commended the parties and OEB staff for achieving a comprehensive settlement on all issues.

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California Managed Decline of Fossil Fuels aligns oil phaseout with carbon neutrality, leveraging ZEV adoption, solar and wind growth, severance taxes, drilling setbacks, fracking oversight, CARB rules, and CalGEM regulation to deliver a just transition.

Key Points

California's strategy to phase out oil and gas while meeting carbon-neutral goals through policy, regulation, and equity.

✅ Severance taxes fund clean energy and workforce transition.

✅ Setbacks restrict drilling near schools, homes, and hospitals.

✅ CARB and CalGEM tighten fracking oversight and ZEV targets.

California’s energy past is on a collision course with its future. Think of major oil-producing U.S. states, and Texas, Alaska or North Dakota probably come to mind. Although its position relative to other states has been falling for 20 years, California remains the seventh-largest oil-producing state, with 162 million barrels of crude coming up in 2018, translating to tax revenue and jobs.

At the same time, California leads the nation in solar rooftops and electric vehicles on the road by a wide margin and ranking fifth in installed wind capacity. Clean energy is the state’s future, and the state is increasingly exporting its energy policies across the West, influencing regional markets. By law, California must have 100 percent carbon-free electricity by 2045, and an executive order signed by former Governor Jerry Brown calls for economywide carbon-neutrality by the same year.

So how can the state reconcile its divergent energy path? How should clean-energy-minded lawmakers wind down California’s oil and gas sector in a way that aligns with the state’s long-term climate targets while providing a just transition for the industry’s workforce?

Any efforts to reduce fossil fuel supply must run parallel to aggressive demand-reduction measures such as California’s push to have 5 million zero-emission vehicles on the road by 2030, said Ethan Elkind, director of Berkeley Law's climate program, especially amid debates over keeping the lights on without fossil fuels in the near term. After all, if oil demand in California remains strong, crude from outside the state will simply fill the void.

“If we don’t stop using it, then that supply is going to get here, even if it’s not produced in-state,” Elkind said in an interview.

Lawmakers have a number of options for policies that would draw down and eventually phase out fossil fuel production in California, according to a new report from the Center for Law, Energy and the Environment at the UC Berkeley School of Law, co-authored by Elkind and Ted Lamm.

They could impose a higher price on California's oil production through a "severance" tax or carbon-based fee, with the revenue directed to measures that wean the state from fossil fuels. (California, alone among major oil-producing states, does not have an oil severance tax.)

Lawmakers could establish a minimum drilling setback from schools, playgrounds, homes and other sensitive sites. They could push the state's oil and gas regulator, the California Geologic Energy Management Division, to prioritize environmental and climate concerns.

A major factor holding lawmakers back is, of course, politics, including debates over blackouts and climate policy that shape public perception. Given the state’s clean-energy ambitions, it might surprise non-Californians that the oil and gas industry is one of the Golden State’s most powerful special interest groups.

Overcoming a "third-rail issue" in California politics
The Western States Petroleum Association, the sector’s trade group in California's capital of Sacramento, spent $8.8 million lobbying state policymakers in 2019, more than any other interest group. Over the last five years, the group, which cultivates both Democratic and Republican lawmakers, has spent $43.3 million on lobbying, nearly double the total of the second-largest lobbying spender.

Despite former Governor Brown’s reputation as a climate champion, critics say he was unwilling to forcefully take on the oil and gas industry. However, things may take a different turn under Brown's successor, Governor Gavin Newsom.

In May 2019, when Newsom released California's midyear budget revision (PDF), the governor's office noted the need for "careful study and planning to decrease demand and supply of fossil fuels, while managing the decline in a way that is economically responsible and sustainable.”

Related reliability concerns surfaced as blackouts revealed lapses in power supply across the state.

Writing for the advocacy organization Oil Change International, David Turnbull observed, “This may mark the first time that a sitting governor in California has recognized the need to embark upon a managed decline of fossil fuel supply in the state.”

“It is significant because typically this is one of those third-rail issues, kind of a hot potato that governors don’t even want to touch at all — including Jerry Brown, to a large extent, who really focused much more on the demand side of fuel consumption in the state,” said Berkeley Law’s Elkind.

California's revised budget included $1.5 million for a Transition to a Carbon-Neutral Economy report, which is being prepared by University of California researchers for the California Environmental Protection Agency. In an email, a CalEPA spokesperson said the report is due by the end of this year.

Winding down oil and gas production
Since the release of the revised budget last May, Newsom has taken initial steps to increase oversight of the oil and gas industry. In July 2019, he fired the state’s top oil and gas regulator for issuing too many permits to hydraulically fracture, or frack, wells.

Later in the year, he appointed new leadership to oversee oil and gas regulation in the state, and he signed a package of bills that placed constraints on fossil fuel production. The next month, Newsom halted the approval of new fracking operations until pending permits could be reviewed by a panel of scientists at Lawrence Livermore National Laboratory. The California Geologic Energy Management Division (CalGEM) did not resume issuing fracking permit approvals until April of this year.

Not all steps have been in the same direction. This month Newsom dropped a proposal to add dozens of analysts, engineers and geologists at CalGEM, citing COVID-related economic pressure. The move would have increased regulatory oversight on fossil fuel producers and was opposed by the state's oil industry.

Ultimately, more durable measures to wind down fossil fuel supply and demand will require new legislation, even as regulators weigh whether the state needs more power plants to maintain reliability.

A 2019 bill by Assemblymember Al Muratsuchi (D-Torrance), AB 345, would have codified the minimum 2,500-foot setback for new oil and gas wells. However, before the final vote in the Assembly, the bill’s buffer requirement was dropped and replaced with a requirement for CalGEM “to consider a setback distance of 2,500 feet.” The bill passed the Assembly in January over "no" votes from several moderate Democrats; it now awaits action in the Senate.

A bill previously introduced by Assemblymember Phil Ting (D-San Francisco), AB 1745, didn’t even make it that far. Ting’s bill would have required that all new passenger cars registered in the state after January 1, 2040, be zero-emission vehicles (ZEV). The bill died in committee without a vote in April 2018.

But the backing of the California Air Resources Board (CARB), one of the world's most powerful air-quality regulators, could change the political conversation. In March, CARB chair Mary Nichols said she now supports consideration of California establishing a 100 percent zero-emission vehicle sales target by 2030, as policymakers also consider a revamp of electricity rates to clean the grid.

“In the past, I’ve been skeptical about whether that would do more harm than good in terms of the backlash by dealers and others against something that sounded so un-California like,” Nichols said during an online event. “But as time has gone on, I’ve become more convinced that we need to send the longer-term signal about where we’re headed.”

Another complicating factor for California’s political leaders is the lack of a willing federal partner — at least in the short term — in winding down oil and gas production, amid warnings about a looming electricity shortage that could pressure the grid.

Under the Trump administration, the Bureau of Land Management, which oversees 15 million acres of federal land in California, has pushed to open more than 1 million acres of public and private land across eight counties in Central California to fracking. In January 2020, California filed a federal lawsuit to block the move.

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NY & NJ Utility Shutoff Moratorium suspends power, heat, and water disconnections amid COVID-19, as PSEG, Con Edison, Avangrid, and American Water pledge relief, supporting vulnerable customers with payment plans and health protections.

Key Points

A temporary pause on power, heat, and water shutoffs during COVID-19, as major utilities act to protect affected customers.

✅ Applies to power, gas, and water; restores prior shutoffs.

✅ Voluntary utility action; no PSC order required in NY.

✅ Initial moratorium runs through April; payment plans available.

New Jersey and New York utilities will keep the power, heat and water on for all customers in response to the coronavirus emergency, both states announced Friday.

Major utilities have agreed to suspend utility shut-offs, a particular concern for people who may be out of work and cannot afford to pay their bills.

“No utility can turn off service … if a person cannot pay their bill as a result of responding to this virus situation,” said New York Gov. Andrew Cuomo during a press conference Friday.

Utilities in New York have voluntarily agreed to this measure, according to the governor’s office, reflecting a broader state moratorium on disconnections during emergencies. No order from the Public Service Commission is expected.

With growing concerns about the economic impacts of a virtual shutdown of businesses and large events to curtail the spread of the novel coronavirus, advocates are increasingly pushing financial relief for families amid pandemic energy insecurity pressures. There’s a campaign in New York to suspend evictions and foreclosures, with growing political support. A similar call has gone out in New Jersey.

As the weather warms, shut-offs of electric and gas service due to nonpayment tend to pick up. If people are quarantined or out of work due to a widespread economic slowdown, some advocates say they shouldn’t have to worry about having the lights or heat turned off, especially as examples of unpaid utility bills straining cities have emerged elsewhere.

“We recognize that customers may experience financial difficulty as a result of the outbreak, whether they or a family member fall ill, are required to quarantine, or because their income is otherwise affected,” said Michael Jennings, a spokesperson for Public Service Enterprise Group — the parent company of Public Service Electric and Gas Company, New Jersey’s largest utility — in a statement.

The company’s policy will be in place at least through the end of April, as will Atlantic City Electric’s, and other utilities such as PG&E's pandemic response included a similar moratorium during the outbreak.

“Curtailing shut-offs is good public policy to make sure New Jersey residents aren’t left in the lurch as they’re dealing with coronavirus,” said Eric Miller, director of the Natural Resources Defense Council’s New Jersey energy policy program. “Not having a safe place to be because you don't have electricity, gas or water doesn’t do anything to help address the coronavirus.”

Water service has also drawn attention. Major cities, including Atlanta and Detroit, have suspended shut-offs to ensure residents have water to wash their hands, while Texas utilities waived fees to support customers as well. Seattle suspended water and electric shutoffs.

American Water, which operates in 16 states and has 650,000 customers in New Jersey and 350,000 in New York, has halted any shutoffs amid the coronavirus pandemic and will also restore service, and similarly Hydro One reconnected customers in Canada to maintain access. New York City does not shut off service for nonpayment, but does issue liens against people’s property.

“Everyone, regardless as to what industry, has to have a heightened responsibility that’s encompassed in compassion and take everything into consideration,” New Jersey state Sen. Teresa Ruiz (D-Essex) told POLITICO. “Now is not the time to be worrying about late payments or bills. We need to get past this, hopefully, to see what we’re facing and then deal with other things.”

PSEG Long Island, a subsidiary of PSEG that handles day-to-day operations for the Long Island Power Authority, was the first New York utility to announce it is also suspending shutoffs before the governor’s announcement. The moratorium will remain in place through the end of April.

Rich Berkley, with the Public Utility Law Project, which advocates for low-income customers in New York, said he’s been in touch with state officials to make sure the issue of utility bills is considered during the pandemic. New York already has requirements for utilities to offer deferred payment agreements before shutting off service, he noted.

“The state has to act to protect the most vulnerable households first,” he said. “To the extent that the state is declaring areas of emergency, this should be part of the remedies the state deploys.”

But he noted that not everyone will have trouble paying their utility bills if they’re under quarantine.

“Given the background of a collapsing stock and equity market, all of which matters to the utilities, and shifts in electricity demand during COVID-19, we have to be careful about blanket moratoriums [on shutoffs] in New York,” Berkley said.

Con Edison, the largest utility in the state serving most of New York City, had already informed the Department of Public Service it will suspend all shut-offs in the one-mile radius New Rochelle containment area, spokesperson Michael Clendenin said on Thursday. The moratorium on shutoffs now includes its entire New York City and Westchester County territory.

Avangrid, which owns New York State Electric & Gas and Rochester Gas & Electric, serving broad swathes of upstate New York, will suspend shut-offs due to unpaid bills for 30 days, spokesperson Michael Jamison said.

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Ontario Global Adjustment and ICI balance hydro rates, renewable cost shift, and peak demand. Class A and Class B customers face demand response decisions amid pandemic occupancy uncertainty and volatile GA charges through 2022.

Key Points

A pricing model where GA costs and ICI peak allocation shape Class A/B bills, driven by renewables cost shifts.

✅ Renewable cost shift trims GA; larger Class A savings expected.

✅ Class A peak strategy returns; occupancy uncertainty persists.

✅ Class B faces volatile GA; limited levers beyond efficiency.

Ontario’s large commercial electricity customers can approach the looming annual decision about their billing structure for the 12 months beginning July 1 with the assurance of long-term relief on a portion of their costs, amid changes coming for electricity consumers that could affect planning. That’s to be weighed against uncertainties around energy demand and whether a locked-in cost allocation formula that looked favourable in pre-pandemic times will remain so until June 30, 2022.

“The biggest unknown is we just don’t know when the people are coming back,” Jon Douglas, director of sustainability with Menkes Property Management Services, reflected during a webinar sponsored by the Building Owners and Managers Association (BOMA) of Greater Toronto last week. “The occupancy in our office buildings this fall, and going into the new year, could really impact the outcome of the decision.”

After a year of operational upheaval and more modifications to provincial electricity pricing policies, BOMA Toronto’s regularly scheduled workshop ahead of the June 15 deadline for eligible customers to opt into the Industrial Conservation Initiative (ICI) program had a lot of ground to cover. Notably, beginning in January, all commercial customers have seen a reduction in the global adjustment (GA) component of their monthly hydro bills after the Ontario government shifted costs associated with contracted non-hydroelectric renewable supply to reduce the burden on industrial ratepayers from electricity rates to the general provincial account — a move that trims approximately $258 million per month from the total GA charged to industrial and commercial customers. However, they won’t garner the full benefit of that until 2022 since they’re currently repaying about $333 million in GA costs that were deferred in April, May and June of 2020.

Renewable cost shift pares the global adjustment
For now, Ontario government officials estimate the renewable cost shift equates to a 12 per cent discount relative to 2020 prices, even as typical bills may rise about 2% as fixed pricing ends in some cases. Once last year’s GA deferral is repaid at the end of 2021, they project the average Class A customer participating in the ICI program should realize a 16 per cent saving on the total hydro bill, while Class B customers paying the GA on a volumetric per kilowatt-hour (kWh) basis will see a slightly more moderate 15 per cent decrease.

“This is the biggest change to electricity pricing that’s happened since the introduction of ICI,” Tim Christie, director of electricity policy, economics and system planning for Ontario’s Ministry of Energy, Northern Development and Mines, told online workshop attendees. “The government is funding the out-of-market costs of renewables. It does tail off into the 2030s as those contracts (for wind, solar and biomass generation) expire, but over the next eight-ish years, it’s pretty steady at around just over $3 billion per year.”

Extrapolating from 2020 costs, he pegged average electricity costs at roughly 9.1 cents/kWh for Class A commercial customers and 13.2 cents/kWh for Class B, a point of concern for Ontario manufacturers facing high rates as well. However, energy management specialists suggest actual 2021 numbers haven’t proved that out.

“In commercial buildings, we’re averaging 10 to 12 cents for Class A in 2021, and we’re seeing more than that for about 14, 15 cents for Class B,” reported Scott Rouse, managing partner with the consulting firm, Energy@Work.

GA costs for Class B customers dropped nearly 30 per cent in the first four months of 2021 compared to the last four months of 2020, when they averaged 11.8 cents/kWh. Thus far, though, there have been significant month-to-month fluctuations, with a low of 5.04 cents/kWh in February and a high of 10.9 cents/kWh in April contributing to the four-month average of 8.3 cents/kWh.

“In 2020, system-wide GA very often averaged more than $1 billion per month,” Rouse said. “This February it dropped to $500 million, which was really quite surprising. So it is a very volatile cost.”

Although welcome, the renewable cost shift does alter the payback on energy-saving investments, particularly for demand response mechanisms like energy storage. When combined with pandemic-related uncertainty and a series of policy and program reversals alongside calls to clean up Ontario’s hydro policy in recent years, the industry’s appetite for some more capital-intensive technologies appears to be flagging.

“Volatility puts a pause on some of the innovation,” said Terry Flynn, general manager with BentallGreenOak and chair of BOMA Toronto’s energy committee. “It could be a leading edge, but it might be a bleeding edge that won’t bear any fruit because the way the commodity costs are structured will change.”

“There’s kind of a wait-and-see approach on some of these bigger investments,” Douglas concurred.

Industrial Conservation Initiative underpins commercial class divide
Turning to the ICI, Class A customers — defined as those with average monthly energy demand of at least 1 megawatt (MW) — encountered some unexpected changes to the program rules during 2020. Meanwhile, Class B customers — encompassing the vast share of commercial properties smaller than about 350,000 square feet — confront the persistent reality of electricity cost allocation that offloads the burden from larger players onto them.

Through the ICI, participating Class A customers pay a share of the global adjustment that’s prorated to their energy use during the five hours of the period from May 1 to April 30 when the highest overall system demand is recorded. This gives Class A customers the opportunity to lock in a favourable factor for calculating their share of monthly system-wide global adjustment costs if they can successful project and curtail energy loads during those five hours of peak demand. On the flipside, Class B customers pay the remainder of those system-wide costs, on a straightforward per-kWh basis, once Class A payments have been reconciled.

“Class B has sometimes been regarded as the forgotten middle child of the customer classes in Ontario where all the shifted costs in the system kind of pile up,” acknowledged Mark Olsheski, vice president, energy and environment, with Sussex Strategy Group. “Likewise, there can be big unpredictable and uncontrollable swings in the global adjustment rate from month to month and, outside of pure energy efficiency, there really is precious little opportunity or empowerment for a Class B customer to take actions to lower their bills.”

Nevertheless, COVID-19 presents a few extra hiccups for Class A customers this year. Conventionally, late May is when they receive notification of the cost allocation factor that would be used to determine their GA for the upcoming July 1 to June 30 period. This year, though, all current ICI participants will retain the factor they secured by responding to the five hours of peak demand during the 12 months from May 1, 2019 to April 30, 2020 after the Ontario government placed a temporary halt on the peak demand response aspect of the program last summer. Regardless, eligible ICI participants must formally opt into the program by June 15 or they will be billed as Class B customers.

Peak chasing resumes for summer 2021
Since peak demand hours conventionally occur from June to September, Class A customers will once again be studying forecasts intently and preparing to respond via Peak Perks as the heat wave season sets in. That should help alleviate some of the system stresses that arose last summer — prompting policy-makers to reject lobbying for a continued pause on peak demand response.

“The policy rationale was to allow consumers to focus on their operations when recovering from COVID as opposed to reducing peaks. The other issue was that we did not expect the peaks to be high last summer given COVID shutdowns,” Christie recounted. “But due to some hot weather, more people at home and also the lack of ICI response, we saw peaks we haven’t seen in many, many years come up last summer. So the peak hiatus has ended and this summer we’ll be back to responding to ICI as per normal.”

Among Class A customers, owners/managers of office and retail facilities generally have the most to lose from a billing formula tied to the energy demand of more densely occupied buildings in the summer of 2019. However, they could be much more competitively positioned for 2022-23 if their buildings remain below full occupancy and energy demand stays lower than usual this summer.

“Where we can improve is the IESO (Independent Electricity System Operator) and the LDCs (local distribution companies) need to help customers get their real-time data, especially in light of the phantom demand issue, interpret their bills and their Class A versus B scenarios much more easily and comprehensively,” urged Lee Hodgkinson, vice president, technical services, sustainability and ESG, with Dream Unlimited. “ I look for APIs (application programming interface) and direct data flow from the LDCs to the building owners so that we can access that data really easily.”

Given Class A’s historic advantages, few eligible ICI participants are expected to migrate out to Class B. From a sustainability perspective, there’s perhaps more cause to question how the ICI’s 1-MW threshold encourages strategies to move in the other direction.

“You could jack up demand in some buildings and get them into Class A basically by firing up the chillers on the weekend and then pouring cooling outside to get rid of it,” Douglas noted. “That has nothing to do with climate change strategy or sustainability, but it’s a cost- saving strategy, and, sometimes, when you look at the math, it’s hundreds of thousands of dollars you can save.”

Brian Hewson, vice president, consumer protection and industry performance with the Ontario Energy Board (OEB), confirmed the OEB is currently scrutinizing the discrepancy that leaves Class B as the only consumer group with no flexibility to curtail energy load during higher-priced periods, and will be providing advice to the Ministry of Energy. In the interim, that status does, at least, simplify tactics.

“Just reduce your kWh and it doesn’t matter what time of day because you’re paying that fixed rate for 24 hours a day. So if you can curb your demand at night, you get a big bang for your dollar,” Rouse advised.

“We do talk about rates a lot, but if you’re not using it, you’re not paying for it,” Flynn agreed. “A lot of our focus is still on really to try to reduce the number of kilowatts that we use. That seems to be the best thing to do.”

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Nova Scotia Integrated Resource Plan evaluates NSPI supply options, UARB oversight, Muskrat Falls imports, coal retirements, wind and biomass expansion, transmission upgrades, storage, and least-cost pathways to decarbonize the grid for ratepayers.

Key Points

A 25-year roadmap assessing supply, imports, costs, and emissions to guide least-cost decarbonization for Nova Scotia.

✅ Compares wind, biomass, gas, imports, and storage costs

✅ Addresses coal retirements, emissions caps, and reliability

✅ Recommends transmission upgrades and Muskrat Falls utilization

Maintaining a viable electricity network requires good long-term planning and, as a recent grid operations report notes, ongoing operational improvements. The existing stock of generating assets can become obsolete through aging, changes in fuel prices or environmental considerations. Future changes in demand must be anticipated.

Periodically, an integrated resource plan is created to predict how all this will add up during the ensuing 25 years. That process is currently underway and is led by Nova Scotia Power Inc. (NSPI) and will be submitted for approval to the Utilities and Review Board (UARB).

Coal-fired plants are still the largest single source of electricity in Nova Scotia. They need to be replaced with more environmentally friendly sources when they reach the end of their useful lives. Other sources include wind, hydroelectricity from rivers, biomass, as seen in increased biomass use by NS Power, natural gas and imports from other jurisdictions.

Imports are used sparingly today but will be an important source when the electricity from Muskrat Falls comes on stream. That project has big capacity. It can produce all the power needed in Newfoundland and Labrador (NL), where Quebec's power ambitions influence regional flows, plus the amount already committed to Nova Scotia, and still have a lot left over.

Some sources of electricity are more valuable than others. The daily amount of power from wind and solar cannot be controlled. Fuel-based sources and hydro can.

Utilities make their profits by providing the capital necessary to build infrastructure. Most of the money is borrowed but a portion, typically 30 per cent, usually comes from NSPI or a sister company. On that they receive a rate of return of nine per cent. Nova Scotia can borrow money today at less than two per cent.

The largest single investment of that type is the $1.577-billion Maritime Link connecting power from Newfoundland to Nova Scotia. It continues through to the New Brunswick border to facilitate exports to the United States. NSPI’s sister company, NSP Maritime Link Inc. (NSPML), is making nine per cent on $473 million of the cost.

There is little unexploited hydro capacity in Nova Scotia and there will not be any new coal-fired plants. Large-scale solar is not competitive in Nova Scotia’s climate. Nova Scotia’s needs would not accommodate the amount of nuclear capacity needed to be cost-effective, even as New Brunswick explores small reactors in its strategy.

So the candidates for future generating resources are wind, natural gas, biomass (though biomass criticism remains) and imports from other jurisdictions. Tidal is a promising opportunity but is still searching for a commercially viable technology. 

NSPI is commendably transparent about its process (irp.nspower.ca). At this stage there is little indication of the conclusions they are reaching but that will presumably appear in due course.

The mountains of detail might obscure the fact that NSPI is not an unbiased arbiter of choices for the future.

It is reported that they want to prematurely close the Trenton 5 coal plant in 2023-25. It is valued at $88.5 million. If it is closed early, ratepayers will still have to pay off the remaining value even though the plant will be idle. NSPI wants to plan a decommissioning of five of its other seven plants. There is a federal emissions constraint but retiring coal plants earlier than needed will cost ratepayers a lot.

Whenever those plants are closed, there will be a need for new sources of power. NSPI is proposing to plan for new investments in new transmission infrastructure to facilitate imports. Other possibilities would be additional wind farms, consistent with the shift to more wind and solar projects, thermal plants that burn natural gas or biomass, or storage for excess wind power that arrives before it can be used. The investment in storage could be anywhere from $20 million to $200 million.

These will add to the asset burden funded by ratepayers, even as industrial customers seek discounts while still paying for shuttered coal infrastructure.

External sources of new power will not provide NSPI the same opportunity: wind power by independent producers might be less expensive because they are willing to settle for less than nine per cent or because they are more efficient. Buying more power from Muskrat Falls will use transmission infrastructure we are already paying for. If a successful tidal technology is found, it will not be owned by NSPI or a sister company, which are no longer trying to perfect the technology.

This is not to suggest that NSPI would misrepresent the alternatives. But they can tilt the discussion in their favour. How tough will they be negotiating for additional Muskrat Falls power when it hurts their profits? Arguing for premature coal retirement on environmental grounds is fair game but whether the cost should be accepted is a political choice. 

NSPI is in a conflict of interest. We need a different process. An independent body should author the integrated resource plan. They should be fully informed about NSPI’s views.

They should communicate directly with Newfoundland and Labrador for Muskrat power, with independent wind producers, and with tidal power companies. The UARB cannot do any of these things.

The resulting plan should undergo the same UARB review that NSPI’s version would. This enhances the likelihood that Nova Scotians will get the least-cost alternative.

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