SkyPower to build wind power project in Fermeuse

New England oil-fired generation surges as ISO New England manages a cold snap, dual-fuel switching, and a natural gas price spike, highlighting winter reliability challenges, LNG and pipeline limits, and rising CO2 emissions.

Key Points

Reliance on oil-burning power plants during winter demand spikes when natural gas is costly or constrained.

✅ Driven by dual-fuel switching amid high natural gas prices

✅ ISO-NE winter reliability rules encourage oil stockpiles

✅ Raises CO2 emissions despite coal retirements and renewables growth

New England is relying on oil-fired generators for the most electricity since 2018 as a frigid blast boosts demand for power and natural gas prices soar across markets. 

Oil generators were producing more than 4,200 megawatts early Thursday, accounting for about a quarter of the grid’s power supply, according to ISO New England. That was the most since Jan. 6, 2018, when oil plants produced as much as 6.4 gigawatts, or 32% of the grid’s output, said Wood Mackenzie analyst Margaret Cashman.  

Oil is typically used only when demand spikes, because of higher costs and emissions concerns. Consumption has been consistently high over the past three weeks as some generators switch from gas, which has surged in price in recent months. New England generators are producing power from oil at an average rate of almost 1.8 gigawatts so far this month, the highest for January in at least five years. 

Oil’s share declined to 16% Friday morning ahead of an expected snowstorm, which was “a surprise,” Cashman said. 

“It makes me wonder if some of those generators are aiming to reserve their fuel for this weekend,” she said.

During the recent cold snap, more than a tenth of the electricity generated in New England has been produced by power plants that haven’t happened for at least 15 years.

Burning oil for electricity was standard practice throughout the region for decades. It was once our most common fuel for power and as recently as 2000, fully 19% of the six-state region’s electricity came from burning oil, according to ISO-New England, more than any other source except nuclear power at the time.

Since then, however, natural gas has gotten so cheap that most oil-fired plants have been shut or converted to burn gas, to the point that just 1% of New England’s electricity came from oil in 2018, whereas about half our power came from natural gas generation regionally during that period. This is good because natural gas produces less pollution, both particulates and greenhouse gasses, although exactly how much less is a matter of debate.

But as you probably know, there’s a problem: Natural gas is also used for heating, which gets first dibs. Prolonged cold snaps require so much gas to keep us warm, a challenge echoed in Ontario’s electricity system as supply tightens, that there might not be enough for power plants – at least, not at prices they’re willing to pay.

After we came close to rolling brownouts during the polar vortex in the 2017-18 winter because gas-fired power plants cut back so much, ISO-NE, which has oversight of the power grid, established “winter reliability” rules. The most important change was to pay power plants to become dual-fuel, meaning they can switch quickly between natural gas and oil, and to stockpile oil for winter cold snaps.

We’re seeing that practice in action right now, as many dual-fuel plants have switched away from gas to oil, just as was intended.

That switch is part of the reason EPA says the region’s carbon emissions have gone up in the pandemic, from 22 million tons of CO2 in 2019 to 24 million tons in 2021. That reverses a long trend caused partly by closing of coal plants and partly by growing solar and offshore wind capacity: New England power generation produced 36 million tons of CO2 a decade ago.

So if we admit that a return to oil burning is bad, and it is, what can we do in future winters? There are many possibilities, including tapping more clean imports such as Canadian hydropower to diversify supply.

The most obvious solution is to import more natural gas, especially from fracked fields in New York state and Pennsylvania. But efforts to build pipelines to do that have been shot down a couple of times and seem unlikely to go forward and importing more gas via ocean tanker in the form of liquefied natural gas (LNG) is also an option, but hits limits in terms of port facilities.

Aside from NIMBY concerns, the problem with building pipelines or ports to import more gas is that pipelines and ports are very expensive. Once they’re built they create a financial incentive to keep using natural gas for decades to justify the expense, similar to moves such as Ontario’s new gas plants that lock in generation. That makes it much harder for New England to decarbonize and potentially leaves ratepayers on the hook for a boatload of stranded costs.

Related News

• Electricity Forum News

• Power Generation News

Jay Grewal Manitoba Hydro Appointment marks the first woman CEO at the Crown utility, amid debt, rate increase plans, privatization debate, and Metis legal challenge, following board turmoil and Premier Pallister's strained relations.

Key Points

The selection of Jay Grewal as Manitoba Hydro's first woman CEO amid debt, rate hikes, and legal disputes.

✅ First woman CEO of Manitoba Hydro

✅ Faces debt, rate hikes, and project overruns

✅ Amid privatization debate and Metis legal action

The Manitoba government has appointed a new president and chief executive officer at its Crown-owned energy utility.

Jay Grewal becomes the first woman to head Manitoba Hydro, and takes over the top spot as the utility faces mounting financial challenges, rising electricity demand and turmoil.

Grewal has previously held senior roles at Capstone Mining Corp and B.C. Hydro, and is currently president of the Northwest Territories Power Corporation.

She will replace outgoing president Kelvin Shepherd, who recently announced he is retiring, on Feb. 4.

The utility was hit by the sudden resignations of nine of its 10 board members in March, who said they had been unable to meet with Premier Brian Pallister to discuss pressing issues like servicing energy-intensive customers facing the utility.

Manitoba Hydro is also in the middle of a battle between the Progressive Conservative government and the Manitoba Metis Federation over the cancellation of two agreements that would have given the Metis $87 million.

The federation has launched a legal challenge over one deal and says its likely going to do the same over the second agreement.

Grewal also takes over the utility at a time when it has racked up billions of dollars in debt building new generating stations and transmission lines. Manitoba Hydro has told the provincial regulatory agency it needs rate increases of nearly eight per cent a year for the next few years to help pay for the projects.

The utility also exports electricity, with deals such as SaskPower's purchase agreement expanding sales to Saskatchewan.

"Ms. Grewal is a proven leader, with extensive senior leadership experience in the utility, resource and consulting sectors," Crown Services Minister Colleen Mayer said in a written statement Thursday.

The Opposition New Democrats said Grewal's appointment is a sign the government wants to privatize Manitoba Hydro. Grewal's time at B.C. Hydro coincided with the privatization of some parts of that Crown utility, the NDP said.

The B.C. premier at the time, Gordon Campbell, was recently hired by Manitoba to review two major projects that ran over-budget and have added to the provincial debt.

NDP Leader Wab Kinew asked Pallister in the legislature Thursday to promise not to privatize Manitoba Hydro. Pallister would only point to a law that requires a referendum to be held before a Crown entity can be sold off.

"We stand by that (law)," Pallister said. "We believe Manitobans are the proper decision-makers in respect of any of the future structuring of Manitoba Hydro."

Related News

• Electricity Forum News

• Power Generation News

Nova Scotia Power Rate Regulation explains how the privately owned utility is governed by the Utility Review Board, limiting government authority, while COVID-19 relief measures include suspended disconnections, waived fees, payment plans, and emergency assistance.

Key Points

URB oversight where the board, not the province, sets power rates, with COVID-19 relief pausing disconnections and fees.

✅ Province lacks authority to order rate cuts

✅ URB regulates Nova Scotia Power rates

✅ Relief: no disconnections, waived fees, payment plans

The province can't ask Nova Scotia Power to lower its rates to ease the financial pressure on out-of-work residents because it lacks the authority to take that kind of action, even as the Nova Scotia regulator approved a 14% hike in a separate proceeding, the provincial energy minister said Thursday.

Derek Mombourquette said he is in "constant contact" with the privately owned utility.

"The conversations are ongoing with Nova Scotia Power," he said after a cabinet meeting.

When asked if the Liberal government would order the utility to lower electricity rates as households and businesses struggle with the financial fallout from the COVID-19 pandemic, Mombourquette said there was nothing he could do.

"We don't have the regulatory authority as a government to reduce the rates," he told reporters during a conference call.

"They're independent, and they are regulated through the (Nova Scotia Utility Review Board). My conversations with Nova Scotia Power essentially have been to do whatever they can to support Nova Scotians, whether it's residents or businesses in this very difficult time."

Asked if the board would take action, the minister said: "I'm not aware of that," despite the premier's appeals to regulators in separate rate cases.

However, the minister noted that the utility, owned by Emera Inc., has suspended disconnections for bill non-payment for at least 90 days, a step similar to reconnection efforts by Hydro One announced in Ontario.

It has also relaxed payment timelines and waived penalties and fees, while some jurisdictions offered lump-sum credits to help with bills.

Nova Scotia Power CEO Wayne O'Connor has also said the company is making additional donations to a fund available to help low-income individuals and families pay their energy bills.

In late March, Ontario cut electricity rates for residential consumers, farms and small businesses in response to a surge in people forced to work from home as a result of the pandemic, alongside bill support measures for ratepayers.

Premier Doug Ford said there would be a 45-day switch to off-peak rates, later moving to a recovery rate framework, which meant electricity consumers would be paying the lowest rate possible at any time of day.

The change was expected to cost the province about $162 million.

Related News

• Electricity Forum News

• Energy Policy News

Ultra-Low Overnight Price Plan delivers flexible electricity pricing from Hydro One and the Ontario Energy Board, with TOU, tiered options, off-peak EV charging savings, balanced billing, and an online calculator to optimize bills.

Key Points

An Ontario pricing option with ultra-low night rates, helping Hydro One customers save by shifting usage to off-peak.

✅ Four periods with ultra-low overnight rate for EV charging

✅ Compare TOU vs tiered with Hydro One's online calculator

✅ Balanced billing and due date choice support budget control

Hydro One has announced that customers have even more choice and flexibility when it comes to how they are billed for electricity with the company's launch of the Ontario Energy Board's new Ultra-Low Overnight Electricity Price Plan for customers. A new survey of Ontario customers, conducted by Innovative Research Group, shows that 74 per cent of Ontarians find having choice between electricity pricing plans useful.

"As their trusted energy advisor, we want our customers to know we have the insights and tools to help them make the right choice when it comes to their electricity plans," said Teri French, Executive Vice President, Safety, Operations and Customer Experience. "We know that choice and flexibility are important to our customers, and we are proud to now offer them a third option so they can select the plan that best fits their lifestyle."

The same survey revealed that fewer than half of Ontarians are familiar with either tiered or the new ultra-low overnight price plans. To better support its customers Hydro One is providing an online calculator to help them choose which pricing plan best suits their lifestyle. The company also offers additional flexibility and assistance in managing household budgets by providing customers with the ability to choose their billing due date and flatten usage spikes from temperature fluctuations through balanced billing.

During the pandemic, Ontario introduced electricity relief to support families, small businesses and farms, complementing these customer options.

"By offering families and small businesses more choice, we are putting them back in control of their energy bills," said Todd Smith, Minister of Energy. "Starting today Hydro One customers have a new option - the Ultra-Low Electricity Price Plan - which could help them save money each year, while making our province's grid more efficient."

Electricity price plan options

• New Ultra-Low Overnight price plan (ULO): Designed for customers who use more electricity at night, such as those who charge their electric vehicle, this new price plan can help customers keep costs down and take control of their electricity bill by shifting usage to the ultra-low overnight price period and related off-peak electricity rates when province-wide electricity demand is lower.
• This plan has four price periods that are the same in the summer as they are in the winter and includes an ultra-low overnight rate.
• Time-of-Use price plan (TOU): TOU provides customers with more control over their electricity bill by adjusting their usage habits with time-of-use rates used in other jurisdictions as well.
• In this plan, electricity prices change throughout each weekday, when demand is on-peak, and peak hydro rates can affect overall costs.
• Tiered price plan (RPP): Tiered pricing provides customers with the flexibility to use electricity at any time of day at the same low price up until the threshold is exceeded during the month, after that usage is charged at a higher price.
• For residential customers, the winter period (November 1 – April 30) threshold is 1,000 kWh per month and the summer period (May 1 – October 31) threshold is 600 kWh per month. 
• For small business customers, the threshold is 750 kWh throughout the year, while broader stable electricity pricing supports industrial and commercial companies.

Related News

• Electricity Forum News

• Utility Operations News

Lake Erie Connector Investment advances a 1,000 MW HVDC transmission link connecting Ontario to the PJM Interconnection, enhancing grid reliability, clean power trade, and GHG reductions through a public-private partnership led by CIB and ITC.

Key Points

A $1.7B public-private HVDC project linking Ontario and PJM to boost reliability, cut GHGs, and enable clean power trade.

✅ 1,000 MW, 117 km HVDC link between Ontario and PJM

✅ $655M CIB and $1.05B private financing, ITC to own-operate

✅ Cuts system costs, boosts reliability, reduces GHG emissions

The Canada Infrastructure Bank (CIB) and ITC Investment Holdings (ITC) have signed an agreement in principle to invest $1.7 billion in the Lake Erie Connector project.

Under the terms of the agreement, the CIB will invest up to $655 million or up to 40% of the project cost. ITC, a subsidiary of Fortis Inc., and private sector lenders will invest up to $1.05 billion, the balance of the project's capital cost.

The CIB and ITC Investment Holdings signed an agreement in principle to invest $1.7B in the Lake Erie Connector project.

The Lake Erie Connector is a proposed 117 kilometre underwater transmission line connecting Ontario with the PJM Interconnection, the largest electricity market in North America, and aligns with broader regional efforts such as the Maine transmission line to import Quebec hydro to strengthen cross-border interconnections.

The 1,000 megawatt, high-voltage direct current connection will help lower electricity costs for customers in Ontario and improve the reliability and security of Ontario's energy grid, complementing emerging solutions like battery storage across the province. The Lake Erie Connector will reduce greenhouse gas emissions and be a source of low-carbon electricity in the Ontario and U.S. electricity markets.

During construction, the Lake Erie Connector is expected to create 383 jobs per year and drive more than $300 million in economic activity, and complements major clean manufacturing investments like a $1.6 billion battery plant in the Niagara Region that supports the EV supply chain. Over its life, the project will provide 845 permanent jobs and economic benefits by boosting Ontario's GDP by $8.8 billion.

The project will also help Ontario to optimize its current infrastructure, avoid costs associated with existing production curtailments or shutdowns. It can leverage existing generation capacity and transmission lines to support electricity demand, alongside new resources such as the largest battery storage project planned for southwestern Ontario.

ITC continues its discussions with First Nations communities and is working towards meaningful participation in the near term and as the project moves forward to financial close.

The CIB anticipates financial close late in 2021, pending final project transmission agreements, with construction commencing soon after. ITC will own the transmission line and be responsible for all aspects of design, engineering, construction, operations and maintenance.

ITC acquired the Lake Erie Connector project in August 2014 and it has received all necessary regulatory and permitting approvals, including a U.S. Presidential Permit and approval from the Canada Energy Regulator.

This is the CIB's first investment commitment in a transmission project and another example of the CIB's momentum to quickly implement its $10B Growth Plan, amid broader investments in green energy solutions in British Columbia that support clean growth.

Endorsements

This project will allow Ontario to export its clean, non-emitting power to one of the largest power markets in the world and, as a result, benefit Canadians economically while also significantly contributing to greenhouse gas emissions reductions in the PJM market. The project allows Ontario to better manage peak capacity and meet future reliability needs in a more sustainable way. This is a true win-win for both Canada and the U.S., both economically and environmentally.
Ehren Cory, CEO, Canada Infrastructure Bank

The Lake Erie Connector has tremendous potential to generate customer savings, help achieve shared carbon reduction goals, and increase electricity system reliability and flexibility. We look forward to working with the CIB, provincial and federal governments to support a more affordable, customer-focused system for Ontarians. 
Jon Jipping, EVP & COO, ITC Investment Holdings Inc., a subsidiary of Canadian-based Fortis Inc. 

We are encouraged by this recent announcement by the Canada Infrastructure Bank. Mississaugas of the Credit First Nation has an interest in projects within our historic treaty lands that have environmental benefits and that offer economic participation for our community.
Chief Stacey Laforme, Mississaugas of the Credit First Nation

While our evaluation of the project continues, we recognize this project can contribute to the economic resilience of our Shareholder, the Mississaugas of the Credit First Nation. Subject to the successful conclusion of our collaborative efforts with ITC, we look forward to our involvement in building the necessary infrastructure that enable Ontario's economic engine.
Leonard Rickard, CEO, Mississaugas of the Credit Business Corporation

The Lake Erie Connector demonstrates the advantages of public-private partnerships to develop critical infrastructure that delivers greater value to Ontarians. Connecting Ontario's electricity grid to the PJM electricity market will bring significant, tangible benefits to our province. This new connection will create high-quality jobs, improve system flexibility, and allow Ontario to export more excess electricity to promote cost-savings for Ontario's electricity consumers.
Greg Rickford, Minister of Energy, Northern Development and Mines, Minister of Indigenous Affairs

With the US pledging to achieve a carbon-free electrical grid by 2035, Canada has an opportunity to export clean power, helping to reduce emissions, maximizing clean power use and making electricity more affordable for Canadians. The Lake Erie Connector is a perfect example of that. The Canada Infrastructure Bank's investment will give Ontario direct access to North America's largest electricity market - 13 states and D.C. This is part of our infrastructure plan to create jobs across the country, tackle climate change, and increase Canada's competitiveness in the clean economy, alongside innovation programs like the Hydrogen Innovation Fund that foster clean technology.

Quick Facts

• The Lake Erie Connector is a 1,000 megawatt, 117 kilometre long underwater transmission line connecting Ontario and Pennsylvania.
• The PJM Interconnection is a regional transmission organization coordinating the movement of wholesale electricity in all or parts of Delaware, Illinois, Indiana, Kentucky, Maryland, Michigan, New Jersey, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West Virginia and the District of Columbia.
• The project will help to reduce electricity system costs for customers in Ontario, and aligns with ongoing consultations on industrial electricity pricing and programs, while helping to support future capacity needs.
• The CIB is mandated to invest CAD $35 billion and attract private sector investment into new revenue-generating infrastructure projects that are in the public interest and support Canadian economic growth.
• The investment commitment is subject to final due diligence and approval by the CIB's Board.

Related News

• Electricity Forum News

• EV Infrastructure News

US Nuclear Generating Costs 2017 show USD33.50/MWh for nuclear energy, the lowest since 2008, as capital expenditures, fuel costs, and operating costs declined after license renewals and uprates, supporting a reliable, low-carbon grid.

Key Points

The 2017 US nuclear average was USD33.50/MWh, lowest since 2008, driven by reduced capital, fuel, and operating costs.

✅ Average cost USD33.50/MWh, lowest since 2008

✅ Capital, fuel, O&M costs fell sharply since 2012 peak

✅ License renewals, uprates, market reforms shape competitiveness

Average total generating costs for nuclear energy in 2017 in the USA were at their lowest since 2008, according to a study released by the Nuclear Energy Institute (NEI), amid a continuing nuclear decline debate in other regions.

The report, Nuclear Costs in Context, found that in 2017 the average total generating cost - which includes capital, fuel and operating costs - for nuclear energy was USD33.50 per megawatt-hour (MWh), even as interest in next-generation nuclear designs grows among stakeholders. This is 3.3% lower than in 2016 and more than 19% below 2012's peak. The reduction in costs since 2012 is due to a 40.8% reduction in capital expenditures, a 17.2% reduction in fuel costs and an 8.7% reduction in operating costs, the organisation said.

The year-on-year decline in capital costs over the past five years reflects the completion by most plants of efforts to prepare for operation beyond their initial 40-year licence. A few major items - a series of vessel head replacements; steam generator replacements and other upgrades as companies prepared for continued operation, and power uprates to increase output from existing plants - caused capital investment to increase to a peak in 2012. "As a result of these investments, 86 of the [USA's] 99 operating reactors in 2017 have received 20-year licence renewals and 92 of the operating reactors have been approved for uprates that have added over 7900 megawatts of electricity capacity. Capital spending on uprates and items necessary for operation beyond 40 years has moderated as most plants are completing these efforts," it says.

Since 2013, seven US nuclear reactors have shut down permanently, with the Three Mile Island debate highlighting wider policy questions, and another 12 have announced their permanent shutdown. The early closure for economic reasons of reliable nuclear plants with high capacity factors and relatively low generating costs will have long-term economic consequences, the report warns: replacement generating capacity, when needed, will produce more costly electricity, fewer jobs that will pay less, and, for net-zero emissions objectives, more pollution, it says.

NEI Vice President of Policy Development and Public Affairs John Kotek said the "hardworking men and women of the nuclear industry" had done an "amazing job" reducing costs through the institute's Delivering the Nuclear Promise campaign and other initiatives, in line with IAEA low-carbon lessons from the pandemic. "As we continue to face economic headwinds in markets which do not properly compensate nuclear plants, the industry has been doing its part to reduce costs to remain competitive," he said.

"Some things are in urgent need of change if we are to keep the nation's nuclear plants running and enjoy their contribution to a reliable, resilient and low-carbon grid. Namely, we need to put in place market reforms that fairly compensate nuclear similar to those already in place in New York, Illinois and other states," Kotek added.

Cost information in the study was collected by the Electric Utility Cost Group with prior years converted to 2017 dollars for accurate historical comparison.

Related News

• Electricity Forum News

• Power Generation News