Financial statements filed at the legislature show a loss of $43 million in fiscal 2022-23, mostly due to problems at the utility's Bayside natural gas plant and its Point Lepreau nuclear generating station. 

CEO Lori Clark cited outages at the two plants, higher prices and other factors.

"NB Power operates in a complex business environment and we experienced many challenges in 2022/23 that were outside of our control, including higher fuel prices due to the global energy crisis and inflation," Clark said in a statement.

N.B. Power CEO Lori Clark said there were a number of things 'that were outside of our control, including higher fuel prices,' soaring inflation, and outages at Bayside and Lepreau. (Ed Hunter/CBC)

The figure of $43 million doesn't include another $234 million in losses that the Crown corporation is allowed to shift off its balance sheet and into a separate deferral account — essentially a different accounting envelope. 

It can then recoup the money from customers with surcharges.

That calculation will be made in October, meaning an influx in revenue in the next three months could erase or reduce the losses in the deferral account and avoid or mitigate the need for surcharges.

Customers would see those extra amounts on their bills next April.

Either way, the 2022-23 statements show that losses that have driven N.B. Power's debt back up to 94 per cent of its equity, the same as it was in 2020.

The progress it was making — the figure was down to 87 per cent in 2022 — has been wiped out. The debt now stands at $5.4 billion.

The Bayside natural gas generating station is part of N.B. Power's Courtney Bay generating complex in Saint John. (Robert Jones/CBC)

N.B. Power saw its costs soar last year after its Bayside gas plant in Saint John required a new turbine and generator at a cost of around $46 million — the same price the utility paid to buy the facility in 2019.

The utility's nuclear generation station at Point Lepreau also had a bad year, forcing N.B. Power to buy replacement power from Quebec.

The extra electricity purchases cost $269 million and were offset by $34 million of extra revenue from higher-than-expected electricity sales, leaving a total of almost $234 million in losses in the deferral account.

The surcharges to customers are subject to approval by the Energy Utilities Board and can't add more than three per cent to any regular rate increase.

The losses make it more difficult for N.B. Power to reach the target set by the Higgs government of getting its debt to 80 per cent of equity by 2027.

The utility pointed to that objective in a recently filed court application attempting to overturn a March rate ruling by the EUB.

8.9% hike requested

N.B. Power asked the EUB for an 8.9 per cent rate hike to take effect April 1, but the board ruled that updated figures from the utility warranted only a 5.7 per cent increase.

A surplus in the deferral account last October required the corporation to rebate customers, which shaved another percentage point off its rate increase, reducing it to 4.8.

But the utility says the EUB failed to use a broader set of new numbers in its decision and also failed to take into account that 2027 debt-to-equity ratio goal.

It's asking the New Brunswick Court of Appeal to award it the 8.9 per cent increase it asked for.

Clark's statement said the corporation's leadership is "committed to making the necessary changes to improve N.B. Power's financial situation and are expecting stronger results in the new 2023/24 fiscal year."

She said the new strategic plan includes "transforming our overall operations and seeking new partnerships to positively impact the bottom line."

Point Lepreau also had a bad year, forcing N.B. Power to buy replacement power from Quebec for $269 million, although that was offset by $34 million of extra revenue from higher-than-expected electricity sales, leaving a total of almost $234 million in losses in the deferral account. (Shane Fowler/CBC)

Among those partnerships is a possible deal with Ontario Power Generation to have that utility take an ownership stake in Point Lepreau.

But even that, and a court victory awarding N.B. Power a higher rate increase, wouldn't mark the end of the utility's financial challenges. 

It recently filed its environmental impact assessment application for an upgrade of the Mactaquac hydroelectric power dam that could cost $2.7 billion to $3.7 billion and must be undertaken soon.

N.B. Power also has yet to settle on how — or whether — to convert its Belledune coal generating station to another energy source — another costly project — ahead of a federal phase-out of coal power in 2030. 

It became clear small modular nuclear reactors aren't, on their own, the magic bullet that will replace coal in the next seven years, or achieve net-zero emissions by 2050.

But utility officials made it equally clear it'll be much harder to get there without them.

"The one thing I can tell you based on what we know today is there's no one solution. We need to throw everything we've got at a net-zero future," said Brad Coady, N.B. Power's executive director of business development and strategic planning.

Coady underscored the key role of emissions-free nuclear power when he told MLAs that if the Point Lepreau generating station near Saint John hadn't started operating in 1983, there would now probably be three coal-fired power plants in Belledune, in northern New Brunswick, not just one.

"Our whole carbon picture in New Brunswick would be completely different," he  said.

N.B. Power's Brad Coady said giving up the Mactaquac Dam's clean, renewable, emissions-free electricity is virtually unthinkable in light of the net-zero target. (John Collicott/CBC News)

Coady acknowledged cost overruns and performance issues at Point Lepreau but said without the plant, three coal plants in Belledune might be generating 2,000 megawatts of greenhouse-gas emitting power, not just the current 450.

"That would have been an absolute nightmare to solve today if we hadn't had nuclear in our mix." 

Renewable power not enough, MLA told

The two days of meetings of the legislature's climate change and environmental stewardship committee were held so supporters and opponents of small reactors could make their case.

But at times the sessions turned into a Jenga-like head-scratcher illustrating the complex challenge — and the high-risk decisions — facing the province.

MLAs were told renewable power, like wind and solar, won't be enough to hit key deadlines.

Belledune is New Brunswick's last coal-fired power plant and must shut down, or convert to another fuel source, in time for a federal coal phaseout in 2030.

There's also a net-zero carbon goal looming in 2050.

N.B. Power and the province are grappling with whether to extend the life of the utility's largest hydroelectric dam at Mactaquac, west of Fredericton on the St. John River. (James West/The Canadian Press)

At the same time, N.B. Power and the province are grappling with whether to extend the life of the utility's largest hydroelectric dam at Mactaquac, west of Fredericton on the St. John River.

And it's all happening amid record growth in the province — growth that will likely drive greater demand for electricity.

The utility says the all-time record for peak demand, set the morning of Feb. 4 of this year in the midst of a harsh winter cold snap, won't be the last.

"It's a trend. We're going to set peak demand records on a regular basis as we go forward," said Andy Hayward, the utility's chief nuclear engineer.

"We're going to attract more population to the province. We're going to attract industry to the province. The demand's going to go up."

Bill Labbe of ARC Clean Energy says its first small modular reactor will be ready by 2030. (Jacques Poitras/CBC)

Quebec wasn't able to export surplus power from its grid to New Brunswick on Feb. 4, Hayward said, and there was actually too much wind for turbines to generate power.

"One of the reasons we look to nuclear is it's available 24/7," Hayward said.

He and Coady cited a 2021 paper by University of New Brunswick economist and research chair Herb Emery, which said without Lepreau the province might still be emitting greenhouse gases at much higher 2005 levels. 

What, then, are the pieces of the puzzle N.B. Power has to work with? 

If nuclear power is a valid option, the question becomes whether the two companies developing small reactors in Saint John can pull it off and by what date.

Rory O'Sullivan, CEO of Moltex Energy, says his company's proposed SMR won't be ready for 2030. (Ed Hunter/CBC)

ARC Clean Energy says its first SMR will be ready to operate at Point Lepreau by 2030. But its 100 megawatts would not be enough to replace Belledune's 450 megawatts from coal.

There would still be "a significant shortfall in megawatts," ARC CEO Bill Labbe said.

Moltex Energy Canada's proposed SMR, also to be located at Lepreau, would generate 300 megawatts, coming closer to filling the gap.

But company CEO Rory O'Sullivan said it won't be ready for 2030.

Moltex's technology will use waste from the existing Point Lepreau generating station to power its reactor. O'Sullivan said the company will build its waste facility by 2030 "or just after," and the reactor itself after that. 

So SMRs won't be enough to make up for Belledune in time for 2030 — even assuming Mactaquac remains in place.

Small modular nuclear reactors operating at Point Lepreau may not be, on their own, the magic bullet that will replace coal in the next seven years. (Submitted by NB Power)

N.B. Power's been talking about the dam refurbishment for a decade but no final decision has been made on the project, which carries an estimated cost of around $3 billion or more.

As pricey as that is, Coady told MLAs that giving up the dam's clean, renewable, emissions-free electricity is virtually unthinkable in light of the net-zero target.

"It almost becomes a no-brainer," he said.

"You almost need to have it. There's alternatives if you don't [but] the costs of those alternatives are going to make Mactaquac look like it's very cheap, good value for money. We're going to have to get there." 

The dam also makes it easier for the utility to add other renewable sources to its grid, he said, because a dam can run all-out when demand is high, then gear down and store water during less busy times when wind can take over.

Importing power another option

N.B. Power recently issued a new request for proposals for an additional 220 megawatts of renewable power, the majority of it from wind, and 50 megawatts of battery storage capacity that would give it more flexibility when demand fluctuates.

It's also shopping for a supply what's called torrified biomass in the coming year and will test it in March 2024 to see if it burns well at Belledune.

Coady said the biomass product resembles charcoal briquettes and "kind of mimics the actions of coal."

It could burn enough to replace Belledune's full 450-megawatt update and would be considered carbon neutral because it would come from sustainably harvested forests, the utility said.

Importing power is another piece of the puzzle, especially if the proposed Atlantic Loop — a regional connection of provincial power grids — is built, allowing N.B. Power to buy more hydroelectricity from Quebec and Labrador.

N.B. Power will issue its latest integrated resource plan this fall, a document published every three years that projects where and how it will generate electricity into the future.

Coady pointed out that when the last one was published in 2020, Ottawa hadn't approved the province's carbon pricing system for large industry. 

And at the time the one before that was released, there was no federal requirement to phase out coal — so the plan will always have to adapt to new realities and alternative scenarios, he told the committee.

"There will be a Plan B, C and D for net zero for New Brunswick, under all scenarios with and without nuclear, and with and without Mactaquac, I might add." 

Newfoundland and Labrador imposed the exact same charges in that province early Thursday morning. 

The amounts are half of what is expected to be an eight-cent charge in New Brunswick. 

Parties connected to the petroleum industry in Nova Scotia pushed for the province to follow New Brunswick's eight-cent plan, but the board found fault with that approach, according to David Roberts. 

"Nobody thought that the cost was really going to reach that amount," said Roberts, who is Nova Scotia's consumer advocate. 

David Roberts acts as consumer advocate at Nova Scotia's Utilities and Review Board. He argued against allowing oil companies to charge an extra eight cents to pay for federal clean-fuel standards, like in New Brunswick. The body settled on half that amount. (CBC)

He argued an eight-cent increase is well beyond expenses oil companies are likely to face and would punish drivers needlessly.

"There's not going to be any rebates going back to consumers if, as it turns out, they were paying four or five cents a litre more than the clean fuel regulations would have required to compensate suppliers," he said in an interview.

Campaign launched over cost

The New Brunswick government has been waging a major social media and advertising campaign to convince residents the upcoming eight-cent increase on gasoline and diesel is required. 

It claims the full amount is necessary to help oil companies pay for the high cost of federal clean fuel regulations that otherwise they would claw from the vulnerable retailers they supply. 

"New Brunswick has made amendments to how regulators set maximum prices because if this change was not made, small retailers in the province would have to absorb the additional cost of the federal government's clean fuel regulation," the province wrote in materials distributed last week that included rare, full front-page newspaper advertisements.

"Prices may go up by as much as eight cents per litre as a result of the clean fuel regulations." 

But Nova Scotia has decided four cents should be adequate, a ruling that will save consumers in that province about $1 million a week in clean fuel charges over what New Brunswick consumers will pay.

Clean fuel regulations took effect in Canada on July 1, but costs associated with them are to be included in formulas that set regulated prices in Nova Scotia and New Brunswick for the first time this Friday. 

The national regulations are meant to cut the "carbon intensity" of automotive fuels sold across the country.

The New Brunswick government took out a full two-page ad in the Telegraph-Journal last week to criticize federal carbon policies. The ads blame Ottawa entirely for the eight-cent fuel-price increase. (Robert Jones/CBC)

They are aimed at making refiners and importers of fuel lower the emission intensity of products they manufacture or resell by setting targets for those emissions and establishing financial rewards and penalties to reach them. 

The regulations do not apply to heating fuels or to petroleum products exported from Canada.

Companies can earn credits by changing practices

Refiners can comply with the new rules in different ways, including putting more ethanol in domestic gasoline, selling biodiesel products or finding ways to reduce their own refining emissions.

Companies that come in below the federal government's emissions intensity ceiling will earn credits they can sell on a market being set up for that purpose. Other producers can buy those credits if their fuels fall short.

It's also possible to earn credits through investments in things unrelated to refining, like electric-vehicle charging stations.

Oil companies have complained that making those changes will be costly and, in response, the New Brunswick and Nova Scotia governments each passed new rules to allow those costs to be passed to consumers. 

The New Brunswick Energy and Utilities Board and Nova Scotia's Utilities and Review Board each held its own hearing to determine what those costs might be, but ultimately reached different conclusions.

Both regulators hired Angie Brown, with the consulting company Grant Thornton, to report on what would be fair. 

She built a model around existing clean fuel rules and credit-trading markets operating in California and estimated, based on the California experience, it would take roughly eight cents per litre added to gasoline and diesel retail prices in both provinces to compensate refiners and importers. 

Brown was questioned about the relevance of using California data to estimate costs of the new Canadian policy, but she said there were few examples to go by. 

"I acknowledge this is an imperfect solution and relying on actual data would likely get you a better outcome," said Brown during her Nova Scotia testimony. 

However, she argued if oil companies were under-compensated for new costs, they could decide to stop supplying local markets.

"I think there are some pretty significant risks if you do take the wait-and-see approach," she said.

Too early to fix costs, consultant says

Brown's modelling and recommendations went largely uncontested in New Brunswick, but not in Nova Scotia.

The Nova Scotia board hired a second expert who argued that because no one knows yet how expensive the new clean fuel rules will be, it is too early to charge consumers for them.

Vijay Muralidharan, with Calgary's R Cube Economic Consulting Inc., agreed the new regulations will add costs to oil companies, but said regulators should wait at least a couple of months to get some data on how companies actually respond to the rules.

"Any cost projection at this point would be an estimation with a relatively high degree of potential error, said Muralidharan in his evidence.

The Shell refinery, upgrader and petrochemical facility northeast of Edmonton has installed solar panels and signed wind energy contracts to cut down on the greenhouse gases it emits during manufacturing. It's the kind of change new federal clean-fuel standards are seeking to force on the petroleum industry. (Kyle Bakx/CBC)

"Therefore, we recommend that the Board wait and conduct a study with the primary suppliers of fuel, once the new Clean Fuel Standard has been initiated, to understand the realized impact on their business before amending the current regulatory framework."

Reasons for the decision have not yet been issued, but its ruling to add four cents of clean fuel costs falls halfway between Grant Thornton's eight-cent recommendation and R Cube's advice of no immediate increase.

Roberts said R Cube's involvement in the Nova Scotia hearing likely had an important influence on the outcome, that was missing in New Brunswick.

"The difference is that there were no alternate scenarios put to the New Brunswick board other than the one that was included in the Grant Thornton report," said Roberts.

"The New Brunswick board accepted the [Grant Thornton] recommendation. The Nova Scotia board did not." 

Newfoundland and Labrador regulators have not held a hearing on clean fuel costs yet but were instructed by the province to implement an interim charge and earlier Thursday selected Nova Scotia's amounts as its own.