N.L. premier says Muskrat Falls costs are too great for optimism about benefits

Ontario Electricity Rates update: OEB sets time-of-use and tiered pricing for residential customers, with kWh charges for peak, mid-peak, and off-peak periods reflecting COVID-19 impacts on demand, supply costs, and pricing.

Key Points

Ontario Electricity Rates are OEB-set time-of-use and tiered prices that set per-kWh costs for residential customers.

✅ Time-of-use: 21.7 peak, 15.0 mid-peak, 10.5 off-peak cents/kWh

✅ Tiered: 12.6 cents/kWh up to 1000 kWh, then 14.6 cents/kWh

✅ Average 700 kWh home pays about $2.24 more per month

Energy bills for the typical Ontario home are going up by about two per cent with fixed pricing coming to an end on Nov. 1, the Ontario Energy Board says. 

The province's electricity regulator has released new time-of-use pricing and says the rate for the average residential customer using 700 kWh per month will increase by about $2.24.

The change comes as Ontario stretches into its eight month of the COVID-19 pandemic with new case counts reaching levels higher than ever seen before.

Time-of-use pricing had been scrapped for residential bills for much for the pandemic with a single fixed COVID-19 hydro rate set for all hours of the day. The move, which came into effect June 1, was meant "to support families, small business and farms while Ontario plans for the safe and gradual reopening of the province," the OEB said at the time.

Ontario later set the off-peak price until February 7 around the clock to provide additional relief.

Fixed pricing meant customers' bills reflected how much power they used, rather than when they used it. Customers were charged 12.8 cents/kWh under the COVID-19 recovery rate no matter their time of use.

Beginning November, the province says customers can choose between time-of-use and tiered pricing options. Rates for time-of-use plans will be 21.7 cents/kWh during peak hours, 15 cents/kWh for mid-peak use and 10.5 cents/kWh for off-peak use. 

Customers choosing tiered pricing will pay 12.6 cents/kWh for the first 1000 kWh each month and then 14.6 cents/kWh for any power used beyond that.

The energy board says the increase in pricing reflects "a combination of factors, including those associated with the COVID-19 pandemic, that have affected demand, supply costs and prices in the summer and fall of 2020."

Asked for his reaction to the move Tuesday, Premier Doug Ford said, "I hate it," adding the province inherited an energy "mess" from the previous Liberal government and are "chipping away at it."

Related News

• Electricity Forum News

• Energy Policy News

BPA Privatization would sell the Bonneville Power Administration's transmission lines, raising FERC-regulated grid rates for ratepayers, impacting hydropower and the California-Oregon Intertie under the Trump 2018 budget proposal in the Pacific Northwest region.

Key Points

Selling Bonneville's transmission grid to private owners, raising rates and returns, shifting costs to ratepayers.

✅ Trump 2018 budget targets BPA transmission assets for sale.

✅ Higher capital costs, taxes, and profit would raise transmission rates.

✅ California-Oregon Intertie and hydropower flows face price impacts.

President Trump's 2018 budget proposal is so chock-full of noxious elements — replacing food stamps with "food boxes," drastically cutting Medicaid and Medicare, for a start — that it's unsurprising that one of its most misguided pieces has slipped under the radar.

That's the proposal to privatize the government-owned Bonneville Power Administration, which owns about three-quarters of the high-voltage electric transmission lines in a region that includes California, Washington state and Oregon, serving more than 13.5 million customers. By one authoritative estimate, any such sale would drive up the cost of transmission by 26%-44%.

The $5.2-billon price cited by the Trump administration, moreover, is nearly 20% below the actual value of the Bonneville grid — meaning that a private buyer would pocket an immediate windfall of $1.2 billion, at the expense of federal taxpayers and Bonneville customers.

Trump's plan for Portland, Ore.-based Bonneville is part of a larger proposal to sell off other government-owned electricity bodies, including the Colorado-based Western Area Power Administration and the Oklahoma-based Southwestern Power Administration. But Bonneville is by far the largest of the three, accounting for nearly 90% of the total $5.8 billion the budget anticipates collecting from the sales. The proposal is also part of the administration's

Both plans are said to be politically dead-on-arrival in Washington. But they offer a window into the thinking in the Trump White House.

"The word 'muddle' comes to mind," says Robert McCullough, a respected Portland energy consultant, referring to the justification for the privatization sale included in the Trump budget.

The White House suggests that selling the Bonneville grid would result in lower costs. But that narrative, McCullough wrote in a blistering assessment of the proposal, "displays a severe lack of understanding about the process of setting transmission rates."

McCullough's assessment is an update of a similar analysis he performed when the privatization scheme was first raised by the Trump administration last year. In that analysis issued in June, McCullough said the proposal "raises the question of why these valuable assets would be sold at a discount — and who would get the benefit of the discounted price."

The implications of a sale could be dire for Californians. Bonneville is the majority owner of the California-Oregon Intertie, an electrical transmission system that carries power, including Columbia River-generated hydropower and other clean-energy generation in British Columbia that supports the regional exchange, south to California in the summer and excess California generation to the Pacific Northwest in the winter.

But the idea has drawn fire throughout the region. When it was first broached last year, the Public Power Council, an association of utilities in the Northwest, assailed it as an apparent "transfer of value from the people of the Northwest to the U.S. Treasury," drawing parallels to Manitoba Hydro governance issues elsewhere.

The region's political leaders had especially harsh words for the idea this time around. "Oregonians raised hell last year when Trump tried to raise power bills for Pacific Northwesterners by selling off Bonneville Power, and yet his administration is back at it again," Sen. Ron Wyden (D-Ore.) said after the idea reappeared. "Our investment shouldn't be put up for sale to free up money for runaway military spending or tax cuts for billionaires." Sen. Maria Cantwell (D-Wash.) promised in a statement to work to "stop this bad idea in its tracks."

The notion of privatizing Bonneville predates the Trump administration; it was raised by Bill Clinton and again by George W. Bush, who thought the public would gain if the administration could sell its power at market rates. Both initiatives failed.

The same free-enterprise ideology underlies the Trump proposal. Privatizing the transmission lines "encourages a more efficient allocation of economic resources and mitigates unnecessary risk to taxpayers," the budget asserts. "Ownership of transmission assets is best carried out by the private sector where there are appropriate market and regulatory incentives."

But that's based on a misunderstanding of how transmission rates are set, McCullough says. Transmission is essentially a monopoly enterprise, with rates overseen by the Federal Energy Regulatory Commission based on the grid's costs, and with federal scrutiny of public utilities such as the TVA underscoring that oversight. There's very little in the way of market "incentives" involved in transmission, since no one has come forward to build a competing grid.

Those include the owners' cost of capital — which would be much higher for a private owner than a government agency, McCullough observes, as Hydro One investor uncertainty demonstrates in practice. A private owner, unlike the government-owned Bonneville, also would owe federal income taxes, which would be passed on to consumers.

Then there's the profit motive. Bonneville "currently sells and delivers its power at cost," McCullough wrote last year. "Under a private regime, an investor-owned utility would likely charge a higher rate of return, a pattern seen when UK network profits drew regulatory rebukes."

None of these considerations appears to have been factored into the White House budget proposal. "Either there's an unsophisticated person at the Office of Management and Budget thinking up these numbers himself," McCullough told me, "or there would seem to be ongoing negotiations with an unidentified third party." No such buyer has emerged in the past, however.

What's left is a blind faith in the magic of the market, compounded by ignorance about how the transmission market operates. Put it together, and there's reason to wonder if Trump is even serious about this plan.

Related News

• Electricity Forum News

• T&D Business News

BC Tidal Energy Micro-Grids harness predictable tidal currents to replace diesel in remote Indigenous coastal communities, integrating marine renewables, storage, and demand management for resilient off-grid power along Vancouver Island and Haida Gwaii.

Key Points

Community-run tidal turbines and storage deliver reliable, diesel-free electricity to remote B.C. coastal communities.

✅ Predictable power from tidal currents reduces diesel dependence

✅ Integrates storage, demand management, and microgrid controls

✅ Local jobs via marine supply chains and community ownership

Many remote West Coast communities are reliant on diesel for electricity generation, which poses a number of negative economic and environmental effects.

But some sites along B.C.’s extensive coastline are ideal for tidal energy micro-grids that may well be the answer for off-grid communities to generate clean power, suggested experts at a COAST (Centre for Ocean Applied Sustainable Technologies) virtual event Wednesday.

There are 40 isolated coastal communities, many Indigenous communities, and 32 of them are primarily reliant on diesel for electricity generation, said Ben Whitby, program manager at PRIMED, a marine renewable energy research lab at the University of Victoria (UVic).

Besides being a costly and unreliable source of energy, there are environmental and community health considerations associated with shipping diesel to remote communities and running generators, Whitby said.

“It's not purely an economic question,” he said.

“You've got the emissions associated with diesel generation. There's also the risks of transporting diesel … and sometimes in a lot of remote communities on Vancouver Island, when deliveries of diesel don't come through, they end up with no power for three or four days at a time.”

The Heiltsuk First Nation, which suffered a 110,000-litre diesel spill in its territorial waters in 2016, is an unfortunate case study for the potential environmental, social, and cultural risks remote coastal communities face from the transport of fossil fuels along the rough shoreline.

A U.S. barge hauling fuel for coastal communities in Alaska ran aground in Gale Pass, fouling a sacred and primary Heiltsuk food-harvesting area.

There are a number of potential tidal energy sites near off-grid communities along the mainland, on both sides of Vancouver Island, and in the Haida Gwaii region, Whitby said.

Tidal energy exploits the natural ebb and flow of the coast’s tidal water using technologies like underwater kite turbines to capture currents, and is a highly predictable source of renewable energy, he said.

Micro-grids are self-reliant energy systems drawing on renewables from ocean, wave power resources, wind, solar, small hydro, and geothermal sources.

The community, rather than a public utility like BC Hydro, is responsible for demand management, storage, and generation with the power systems running independently or alongside backup fuel generators — offering the operators a measure of energy sovereignty.

Depending on proximity, cost, and renewable solutions, tidal energy isn’t necessarily the solution for every community, Whitby noted, adding that in comparison to hydro, tidal energy is still more expensive.

However, the best candidates for tidal energy are small, off-grid communities largely dependent on costly fossil fuels, Whitby said.

“That's really why the focus in B.C. is at a smaller scale,” he said.

“The time it would take (these communities) to recoup any capital investment is a lot shorter.

“And the cost is actually on a par because they're already paying a significant amount of money for that diesel-generated power.”

Lisa Kalynchuk, vice-president of research and innovation at UVic, said she was excited by the possibilities associated with tidal power, not only in B.C., but for all of Canada’s coasts.

“Canada has approximately 40,000 megawatts available on our three coastlines,” Kalynchuk said.

“Of course, not all this power can be realized, but it does exist, so that leads us to the hard part — tapping into this available energy and delivering it to those remote communities that need it.”

Challenges to establishing tidal power include the added cost and complexity of construction in remote communities, the storage of intermittent power for later use, the economic model, though B.C.’s streamlined regulatory process may ease approvals, the costs associated with tidal power installations, and financing for small communities, she said.

But smaller tidal energy projects can potentially set a track record for more nascent marine renewables, as groups like Marine Renewables Canada pivot to offshore wind development, at a lower cost and without facing the same social or regulatory resistance a large-scale project might face.

A successful tidal energy demo project was set up using a MAVI tidal turbine in Blind Channel to power a private resort on West Thurlow Island, part of the outer Discovery Islands chain wedged between Vancouver Island and the mainland, Whitby said.

The channel’s strong tidal currents, which routinely reach six knots and are close to the marina, proved a good site to test the small-scale turbine and associated micro-grid system that could be replicated to power remote communities, he said.

The mooring system, cable, and turbine were installed fairly rapidly and ran through the summer of 2017. The system is no longer active as provincial and federal funding for the project came to an end.

“But as a proof of concept, we think it was very successful,” Whitby said, adding micro-grid tidal power is still in the early stages of development.

Ideally, the project will be revived with new funding, so it can continue to act as a test site for marine renewable energy and to showcase the system to remote coastal communities that might want to consider tidal power, he said.

In addition to harnessing a local, renewable energy source and increasing energy independence, tidal energy micro-grids can fuel employment and new business opportunities, said Whitby.

The Blind Channel project was installed using the local supply chain out of nearby Campbell River, he said.

“Most of the vessels and support came from that area, so it was all really locally sourced.”

Funding from senior levels of government would likely need to be provided to set up a permanent tidal energy demonstration site, with recent tidal energy investments in Nova Scotia offering a model, or to help a community do case studies and finance a project, Whitby said.

Both the federal and provincial governments have established funding streams to transition remote communities away from relying on diesel.

But remote community projects funded federally or provincially to date have focused on more established renewables, such as hydro, solar, biomass, or wind.

The goal of B.C.’s Remote Community Energy Strategy, part of the CleanBC plan and aligned with zero-emissions electricity by 2035 targets across Canada, is to reduce diesel use for electricity 80 per cent by 2030 by targeting 22 of the largest diesel locations in the province, many of which fall along the coast.

The province has announced a number of significant investments to shift Indigenous coastal communities away from diesel-generated electricity, but they predominantly involve solar or hydro projects.

A situation that’s not likely to change, as the funding application guide in 2020 deemed tidal projects as ineligible for cash.

Yet, the potential for establishing tidal energy micro-grids in B.C. is good, Kalynchuk said, noting UVic is a hub for significant research expertise and several local companies, including ocean and river power innovators working in the region, are employing and developing related service technologies to install and maintain the systems.

“It also addresses our growing need to find alternative sources of energy in the face of the current climate crisis,” she said.

“The path forward is complex and layered, but one essential component in combating climate change is a move away from fossil fuels to other sources of energy that are renewable and environmentally friendly.”

Related News

• Electricity Forum News

• Renewable Energy News

Renewable Electricity Generation is accelerating the shift from fossil fuels, as wind, solar, and hydro boost the electric power sector, lowering emissions and overtaking nuclear while displacing coal and natural gas in the U.S. grid.

Key Points

Renewable electricity generation is power from non-fossil sources like wind, solar, and hydro to cut emissions.

✅ Driven by wind, solar, and hydro adoption

✅ Reduces fossil fuel dependence and emissions

✅ Increasing share in the electric power sector

The transition to electric vehicles is largely driven by a need to reduce our reliance on fossil fuels and reduce emissions associated with burning fossil fuels, while declining US electricity use also shapes demand trends in the power sector. In 2021, 40% of the electricity produced by the electric power sector was derived from non-fossil fuel sources.

Since 2007, the increase in non-fossil fuel sources has been largely driven by “Other Renewables” which is predominantly wind and solar. This has resulted in renewables (including hydroelectric) overtaking nuclear power’s share of electricity generation in 2021 for the first time since 1984. An increasing share of electricity generation from renewables has also led to a declining share of electricity from fossil fuel sources like coal, natural gas, and petroleum, with renewables poised to eclipse coal globally as deployment accelerates.

Includes net generation of electricity from the electric power sector only, and monthly totals can fluctuate, as seen when January power generation jumped on a year-over-year basis.

Net generation of electricity is gross generation less the electrical energy consumed at the generating station(s) for station service or auxiliaries, and the projected mix of sources is sensitive to policies and natural gas prices over time. Electricity for pumping at pumped-storage plants is considered electricity for station service and is deducted from gross generation.

“Natural Gas” includes blast furnace gas and other manufactured and waste gases derived from fossil fuels, while in the UK wind generation exceeded coal for the first time in 2016.

“Other Renewables” includes wood, waste, geo-thermal, solar and wind resources among others.

“Other” category includes batteries, chemicals, hydrogen, pitch, purchased steam, sulfur, miscellaneous technologies, and, beginning in 2001, non-renewable waste (municipal solid waste from non-biogenic sources, and tire-derived fuels), noting that trends vary by country, with UK low-carbon generation stalling in 2019.

Related News

• Electricity Forum News

• Power Generation News

Alberta Capacity Market Overhaul faces scrutiny over electricity costs, reliability targets, investor certainty, and AESO design, as UCP reviews NDP reforms, renewables integration, and deregulated energy-only alternatives impacting generators, ratepayers, and future power price volatility.

Key Points

A shift paying generators for capacity and energy to improve reliability; critics warn of higher electricity costs.

✅ UCP reviewing NDP plan and subsidies amid market uncertainty

✅ AESO cites reliability needs as coal retires, renewables grow

✅ Critics predict overprocurement and premature launch cost spikes

Jason Kenney's government is facing renewed pressure to cancel a massive overhaul of Alberta's power market that one player says will needlessly spike costs by hundreds of millions of dollars, amid an electricity sector in profound change today.

Nick Clark, who owns the Calgary-based electricity retailer Spot Power, has sent the Alberta government an open letter urging it to walk away from the electricity market changes proposed by the former NDP government.

"How can you encourage new industry to open up when one of their raw material costs will increase so dramatically?" Clark said. "The capacity market will add more costs to the consumer and it will be a spiral downwards."

But NDP Leader Rachel Notley, whose government ushered in the changes, said fears over dramatic cost increases are unfounded.

"There are some players within the current electricity regime who have a vested interest in maintaining the current situation," Notley said

Kenney's UCP vowed during the recent election to review the current and proposed electricity market options, as the electricity market heads for a reshuffle, with plans to report on its findings within 90 days.

The party also promised to scrap subsidies for renewable power, while ensuring "a market-based electricity system" that emphasizes competition in Alberta's electricity market for consumers.

The New Democrats had opted to scrap the current deregulated power market — in place since the Klein era — after phasing out coal-fired generation and ushering in new renewable power as part of changes in how Alberta produces and pays for electricity under their climate change strategy.

The Alberta Electric System Operator, which oversees the grid, says the province will need new sources of electricity to replace shuttered coal plants and backstop wind and solar generators, while meeting new consumer demand.

After consulting with power companies and investors, the AESO concluded in late 2016 the electricity market couldn't attract enough investment to build the needed power generation under the current model.

The AESO said at the time investors were concerned their revenues would be uncertain once new plants are running. It recommended what's known as a capacity market, which compensates power generators for having the ability to produce electricity, even when they're not producing it.

In other words, producers would collect revenue for selling electricity into the grid and, separately, for having the capacity to produce power as a backstop, ensuring the lights stay on. Power generators would use this second source of income to help cover plant construction costs.

Clark said the complex system introduces unnecessary costs, which he believes would hurt consumers in the end. He said what's preventing investment in the power market is uncertainty over how the market will be structured in the future.

"What investors need to see in this market is price certainty, regulatory ease, and where the money they're putting into the marketplace is not at risk," he said.

"They can risk their own money, but if in fact the government comes in and changes the policy as it was doing, then money stayed away from the province."

Notley said a capacity market would not increase power bills but would avoid big price swings, with protections like a consumer price cap on power bills also debated, while bringing greener sources of energy into Alberta's grid.

"Moving back to the [deregulated] energy-only market would make a lot of money for a few people, and put consumers, both industrial and residential, at great risk."

Clark disagrees, citing Enmax's recent submissions to the Alberta Utilities Commission, in which the utility argues the proposed design of the capacity market is flawed.

In its submissions to the commission, which is considering the future of Alberta's power market, Enmax says the proposed system would overestimate the amount of generation capacity the province will need in the future. It says the calculation could result in Alberta procuring too much capacity.

The City of Calgary-owned utility says this could drive up costs by anywhere from $147 million to $849 million a year. It says a more conservative calculation of future electricity demand could avoid the extra expense.

An analysis by a Calgary energy consulting firm suggests a different feature of the proposed power market overhaul could also lead to a massive spike in costs.

EDC Associates, hired by the Consumers' Coalition of Alberta, argues the proposal to launch the new system in November 2021 may be premature, because it could bring in additional supplies of electricity before they're needed.

The consultant's report, also filed with the Alberta Utilities Commission, estimates the early launch date could require customers to pay 40 per cent more for electricity amid rising electricity prices in the province — potentially an extra $1.4 billion — in 2021/22.

"The target implementation date is politically driven by the previous government," said Duane Reid-Carlson, president of EDC Associates.

Reid-Carlson recommends delaying the launch date by several years and making another tweak: reducing the proposed target for system reliability, which would scale back the amount of power generation needed to backstop renewable sources.

"You could get a result in the capacity market that would give a similar cost to consumers that the [deregulated] energy-only market design would have done otherwise," he said.

"You could have a better risk profile associated with the capacity market that would serve consumers better through lower cost, lower price volatility, and it would serve generators better by giving them better access to capital at lower costs."

The UCP government did not respond to a request for comment.

Related News

• Electricity Forum News

• Energy Policy News

Texas Power Grid Blackouts loom as ERCOT forecasts record air conditioning load, tight reserve margins, peak demand spikes, and rising natural gas prices; heatwaves could trigger brownouts without added solar, storage, and demand response.

Key Points

Texas Power Grid Blackouts are outages when AC-driven peak demand and ERCOT reserves outstrip supply during heatwaves.

✅ ERCOT forecasts record AC load and tight reserve margins.

✅ Coal retirements cut capacity; gas and solar additions lag.

✅ Peak prices, brownouts likely without storage and demand response.

U.S. Air conditioning related electricity usage will break records and may cause blackouts across the U.S. and in Texas this summer. Power grid operators are forecasting that electricity supplies will exceed demands during the summer months.

Most of Texas will face severe electricity shortages because of hot temperatures, air conditioning, and a strong economy, with millions at risk of electricity shut-offs during extreme heat, Bill Magness the president of the Electric Reliability Council of Texas (ERCOT) told the Associated Press. Magness thinks the large numbers people moving to Texas for retirement will increase the demand for air conditioning and electricity use. Retired people are more likely to be home during the day when temperatures are high – so they are more likely to turn up the air conditioner.

Around 50% of all electricity in Texas is used for air conditioning and 100% of homes in Texas have air conditioners, Forbes reported. That means just a few hot days can strain the grid and a heatwave can trigger brownouts and blackouts, in a system with more blackouts than other developed countries on average.

The situation was made worse by Vistra Energy’s decision to close more coal-fired power plants last year, The Austin American Statesman reported. The closed plants; Big Brown, Sadow, and Monticello, generated around 4,100 megawatts (4.1 million watts) of electricity, enough generation capacity to power two million homes, The Waco Herald-Tribune reported.

Texas Electric Grid Might Not Meet Demand

Texas’s grid has never operated without those plants will make this summer a test of its capacity. Texas only has a 6% reserve of electricity that might fall will because of problems like downed lines or a power plant going offline.

A Vistra subsidiary called Luminant has added around 8,000 megawatts of generation capacity from natural-gas burning plants, The Herald-Tribune reported. Luminant also plans to open a giant solar power plant in Texas to increase grid capacity.

The Texas grid already reached peak capacity in May because of unexpectedly high demand and technical problems that reflect more frequent outages in many states, Houston Public Media reported. Grid capacity fell because portions of the system were offline for maintenance.

Some analysts have suggested starting schools after Labor Day to shift peak August demand, potentially easing stress on the grid.

Electricity Reserves are Tight in Texas

Electricity reserves will be very tight on hot summer days in Texas this summer, Magness predicted. When the thermometer rises, people crank up the air conditioner which burns more electricity.

The grid operator ERCOT anticipates that Texas will need an additional 1,600 megawatts of electricity this summer, but record-high temperatures can significantly increase the demand. If everything is running correctly, Texas’s grid can produce up to 78,184 megawatts of electricity.

“The margin between absolute peak power usage and available peak supply is tighter than in years past,” Andrew Barlow, a spokesman for Texas’s Public Utility Commission admitted.

Around 90% of Texas’s grid has enough generating capacity, ERCOT estimated. That means 10% of Texas’s power grid lacks sufficient generating capacity which increases the possibility of blackouts.

Even if the electricity supply is adequate electricity prices can go up in Texas because of higher natural gas prices, Forbes reported. Natural gas prices might go up over the summer because of increased electricity demands. Texas uses between 8% and 9% of America’s natural gas supply to generate electricity for air conditioning in the summer.

Be Prepared For Blackouts This Summer.

Texas’s problems might affect other regions including neighboring states such as Oklahoma, Arkansas, Louisiana, and New Mexico and parts of Mexico, as lawmakers push to connect Texas’s grid to the rest of the nation to improve resilience because those areas are connected to the same grid. Electricity from states like Colorado might be diverted to Texas in case of power shortages there.

Beyond the U.S., Canadian electricity grids are increasingly exposed to harsh weather that can ripple across markets as well.

Home and business owners can avoid summer blackouts by tapping sources of Off-Grid electricity. The two best sources are backup battery storage and solar panels which can run your home or business if the grid runs dry.

If you have family members with health problems who need air conditioning, or you rely on a business or freelance work that requires electricity for income, backup power is vital. Those who need backup electricity for their business should be able to use the expense of installing it as a tax deduction.

Having backup electricity available might be the only way for Texans to keep cool this summer.

Related News

• Electricity Forum News

• Power Generation News