PMLD replacing old wind turbines

BC Hydro drought operations address climate change impacts with hydropower scheduling, reservoir management, water conservation, inflow forecasting, and fish habitat protection across the Lower Mainland and Vancouver Island while maintaining electricity generation from storage facilities.

Key Points

BC Hydro drought operations conserve water, protect fish, and sustain hydropower during extended heat and low inflows.

✅ Proactive reservoir releases protect downstream salmon spawning.

✅ Reduced flows at Puntledge, Coquitlam, and Ruskin/Stave facilities.

✅ System relies on northern storage to maintain electricity supply.

BC Hydro is adjusting its operating plans around power generation as extended heat and little forecast rain continue to impact the province, a report says.

“Unpredictable weather patterns related to climate change are expected to continue in the years ahead and BC Hydro is constantly adapting to these evolving conditions, especially after events such as record demand in 2021 that tested the grid,” said the report, titled “Casting drought: How climate change is contributing to uncertain weather and how BC Hydro’s generation system is adapting.”

The study said there is no concern with BC Hydro being able to continue to deliver power through the drought because there is enough water at its larger facilities, even as issues like crypto mining electricity use draw scrutiny from observers.

Still, it said, with no meaningful precipitation in the forecast, its smaller facilities in the Lower Mainland and on Vancouver Island will continue to see record low or near record low inflows for this time of the year.

“In the Lower Mainland, inflows since the beginning of September are ranked in the bottom three compared to historical records,” the report said.

The report said the hydroelectric system is directly impacted by variations in weather and the record-setting, unseasonably dry and warm weather this fall highlights the impacts of climate change, while demand patterns can be counterintuitive, as electricity use even increased during Earth Hour 2018 in some areas, hinting at challenges to come.

It noted symptoms of climate change include increased frequency of extreme events like drought and intense storms, and rapid glacial melt.

“With the extremely hot and dry conditions, BC Hydro has been taking proactive steps at many of our South Coast facilities for months to conserve water to protect the downstream fish habit,” spokesperson Mora Scott said. “We began holding back water in July and August at some facilities anticipating the dry conditions to help ensure we would have water storage for the later summer and early fall salmon spawning.”

Scott said BC Hydro’s reservoirs play an important role in managing these difficult conditions by using storage and planning releases to provide protection to downstream river flows. The reservoirs are, in effect, a battery waiting to be used for power.

While the dry conditions have had an impact on BC Hydro’s watersheds, several unregulated natural river systems — not related to BC Hydro — have fared worse, with rivers drying up and thousands of fish killed, the report said.

BC Hydro is currently seeing the most significant impacts on operations at Puntledge and Campbell River on Vancouver Island as well as Coquitlam and Ruskin/Stave in the Lower Mainland.

To help manage water levels on Vancouver Island, BC Hydro reduced Puntledge River flows by one-third last week and on the Lower Mainland reduced flows at Coquitlam by one-third and Ruskin/Stave by one quarter.

However, the utility company said, there are no concerns about continued power delivery.

“British Columbians benefit from BC Hydro’s integrated, provincial electricity system, which helps send power across the province, including to Vancouver Island, and programs like the winter payment plan support customers during colder months,” staff said.

Most of the electricity generated and used in B.C. is produced by larger facilities in the north and southeast of the province — and while water levels in those areas are below normal levels, there is enough water to meet the province’s power needs, even as additions like Site C's electricity remain a subject of debate among observers.

The Glacier Media investigation found a quarter of BC Hydro's power comes from the Mica, Revelstoke and Hugh Keenleyside dams on the Columbia River. Some 29% comes from dams in the Peace region, including the under-construction Site C project that has faced cost overruns. At certain points of the year, those reservoirs are reliant on glacier water.

Still, BC Hydro remains optimistic.

Forecasts are currently showing little rain in the near-term; however, historically, precipitation and inflows show up by the end of October. If that does not happen, BC Hydro said it would continue to closely track weather and inflow forecasts to adapt its operations to protect fish, while regional cooperation such as bridging with Alberta remains part of broader policy discussions.

Among things BC Hydro said it is doing to adapt are:

Continuously working to improve its weather and inflow forecasting;
Expanding its hydroclimate monitoring technology, including custom-made solutions that have been designed in-house, as well as upgrading snow survey stations to automated, real-time snow and climate stations, and;
Investing in capital projects — like spillway gate replacements — that will increase resiliency of the system to climate change.

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Ontario electricity emissions forecast highlights rising grid CO2 as nuclear refurbishments and the Pickering closure drive more natural gas, limited renewables, and delayed Quebec hydro imports, pending advances in storage and transmission upgrades.

Key Points

A projection that Ontario's grid CO2 will rise as nuclear units refurbish or retire, increasing natural gas use.

✅ Nuclear refurbs and Pickering shutdown cut zero-carbon baseload

✅ Gas plants fill capacity gaps, boosting GHG emissions

✅ Quebec hydro imports face cost, transmission, and timing limits

Ontario's energy grid is among the cleanest in North America — but the province’s nuclear plans mean that some of our progress will be reversed over the next decade.

What was once Canada’s largest single source of greenhouse-gas emissions is now a solar-power plant. The Nanticoke Generating Station, a coal-fired power plant in Haldimand County, was decommissioned in stages from 2010 to 2013 — and even before the last remaining structures were demolished earlier this year, Ontario Power Generation had replaced its nearly 4,000 megawatts with a 44-megawatt solar project in partnership with the Six Nations of the Grand River Development Corporation and the Mississaugas of the Credit First Nation.

But neither wind nor solar has done much to replace coal in Ontario’s hydro sector, a sign of how slowly Ontario is embracing clean power in practice across the province. At Nanticoke, the solar panels make up less than 2 per cent of the capacity that once flowed out to southern Ontario over high-voltage transmission lines. In cleaning up its electricity system, the province relied primarily on nuclear power — but the need to extend the nuclear system’s lifespan will end up making our electricity dirtier again.

“We’ve made some pretty great strides since 2005 with the fuel mix,” says Terry Young, vice-president of corporate communications at the Independent Electricity System Operator, the provincial agency whose job it is to balance supply and demand in Ontario’s electricity sector. “There have been big changes since 2005, but, yes, we will see an increase because of the closure of Pickering and the refurbs coming.”

“The refurbs” is industry-speak for the major rebuilds of both the Darlington and Bruce nuclear-power stations. The two are both in the early stages of major overhauls intended to extend their operating lives into the 2060s: in the coming years, they’ll be taken offline and rebuilt. (The Pickering nuclear plant will not be refurbished and will shut down in 2024.)

The catch is that, as the province loses its nuclear capacity in increments, Ontario will be short of electricity in the coming years and the IESO will need to find capacity elsewhere to make sure the lights stay on. And that could mean burning a lot more natural gas — and creating more greenhouse-gas emissions.

According to the IESO’s planning assumptions, electricity will be responsible for 11 megatonnes of greenhouse-gas emissions annually by 2035 (last year, it was three megatonnes). That’s the “reference case” scenario: if conservation and efficiency policies shave off some electricity demand, we could get it down to something like nine megatonnes. But if demand is higher than expected, it could be as high as 13 megatonnes — more than quadruple Ontario’s 2018 emissions.

Even in the worst-case scenario, the province’s emissions from electricity would still be less than half of what they were in 2005, before the province began phasing out its coal generation. But it’s still a reversal of a trend that both Liberals and Progressive Conservatives have boasted about — the Liberals to justify their energy policies, the PCs to justify their hostility to a federal carbon tax.

Young emphasized that technology can change and that the IESO’s planning assumptions are just that: projections based on the information available today. A revolution in electricity storage could make it possible to store the province’s cleaner power sources overnight for use during the day, but that’s still only in the realm of speculation — and the natural-gas infrastructure exists in the real world, today.

Ontario Power Generation — the Crown corporation that operates many of the province’s power plants, including Pickering and Darlington — recently bought four gas plants, two of them outright (two it already owned in part). All were nearly complete or already operational, so the purchase itself won’t change the province’s emissions prospects. Rather, OPG is simply looking to maintain its share of the electricity market after the Pickering shutdown.

“It will allow us to maintain our scale, with the upcoming end of Pickering’s commercial operations, so that we can continue our role as the driver of Ontario’s lower carbon future,” Neal Kelly, OPG’s director of media, issues, and management, told TVO.org via email. “Further, there is a growing need for flexible gas fired generation to support intermittent wind and solar generation.”

The shift to more gas-fired generation has been coming for a while, and critics say that Ontario has missed an opportunity to replace the lost Pickering capacity with something cleaner. MPP Mike Schreiner, leader of the Green party, has argued for years that Ontario should have pursued an agreement with Quebec to import clean hydroelectricity.

“To me, it’s a cost-effective solution, and it’s a zero-emissions solution,” Schreiner says. “Regardless of your position on sources of electricity, I think everyone could agree that waterpower from Quebec is going to be less expensive.”

Quebec is eager to sell Ontario its surplus hydro power, but not everyone agrees that importing power would be cheaper. A study published by the Ontario Chamber of Commerce (and commissioned by Ontario Power Generation) calls the claim a “myth” and states that upgrading electric-transmission wires between Ontario and Quebec would cost $1.2 billion and take 10 years, while some estimates suggest fully greening Ontario's grid would cost far more overall.

With Quebec imports seemingly a non-starter and major changes to Ontario’s nuclear fleet already underway, there’s only one path left for this province’s greenhouse-gas emissions: upwards.

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Hydro-Quebec Rate Freeze maintains current electricity rates, aligned with Bill 34, inflation indexing, and energy board oversight, delivering rebates to residential, commercial, and industrial customers and projecting nearly $1 billion in savings across Quebec.

Key Points

A Bill 34 policy holding power rates, adding 2020 rebates, and indexing 2021-2024 rates to inflation for Quebec customers.

✅ 2020-21 rates frozen; savings near $1B over five years.

✅ $500M rebate: residential, commercial, industrial shares.

✅ 2021-2024 rates index to inflation; five-year reviews after 2025.

Hydro-Quebec Distribution will not file a rate adjustment application with the province’s energy board this year, amid a class-action lawsuit alleging customers were overcharged.

In a statement released on Friday the Crown Corporation said it wants current electricity rates to be maintained for another year, as pandemic-driven demand pressures persist, starting April 1. That is consistent with the recently tabled Bill 34, and echoes Ontario legislation to lower electricity rates in its aims, which guarantees lower electricity rates for Quebecers.

The bill also provides a $500 million rebate in 2020, similar to a $535 million refund previously issued, half of which will go to residential customers while $190 million will go to commercial customers and another $60 million to industrial ones.

Hydro-Quebec said the 2020-21 rate freeze will generate savings of nearly $1 billion for its clients over the next five years, even as Manitoba Hydro scales back increases in a different market.

Bill 34, which was tabled in June, also proposes to set rates based on inflation for the years 2021 to 2024, contrasting with Ontario rate increases over the same period. After 2025 Hydro-Quebec would have to ask the energy board to set new rates every five years, as opposed to the current annual system, while BC Hydro is raising rates by comparison.

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Vogtle Unit 3 Initial Criticality marks the startup of a new U.S. nuclear reactor, initiating fission to produce heat, steam, and electricity, supporting clean energy goals, grid reliability, and carbon-free baseload power.

Key Points

Vogtle Unit 3 Initial Criticality is the first fission startup, launching power generation at a new U.S. reactor.

✅ First new U.S. reactor to reach criticality since 2016

✅ Generates carbon-free baseload power for the grid

✅ Faced cost overruns and delays during construction

For the first time in almost seven years, a new nuclear reactor has started up in the United States.

On Monday, Georgia Power announced that the Vogtle nuclear reactor Unit 3 has started a nuclear reaction inside the reactor as part of the first new reactors in decades now taking shape at the plant.

Technically, this is called “initial criticality.” It’s when the nuclear fission process starts splitting atoms and generating heat, Georgia Power said in a written announcement.

The heat generated in the nuclear reactor causes water to boil. The resulting steam spins a turbine that’s connected to a generator that creates electricity.

Vogtle’s Unit 3 reactor will be fully in service in May or June, Georgia Power said.

The last time a nuclear reactor reached the same milestone was almost seven years ago in May 2016 when the Tennessee Valley Authority started splitting atoms at the Watts Bar Unit 2 reactor in Tennessee, Scott Burnell, a spokesperson for the Nuclear Regulatory Commission, told CNBC.

“This is a truly exciting time as we prepare to bring online a new nuclear unit that will serve our state with clean and emission-free energy for the next 60 to 80 years,” Chris Womack, CEO of Georgia Power, said in a written statement. 

Including the newly turned-on Vogtle Unit 3 reactor, there are currently 93 nuclear reactors operating in the United States and, collectively, they generate 20% of the electricity in the country, although a South Carolina plant leak recently showed how outages can sideline a unit for weeks.

Nuclear reactors, which help combat global warming and support net-zero emissions goals, generate about half of the clean, carbon-free electricity generated in the U.S.

Most of the nuclear power reactors in the United States were constructed between 1970 and 1990, but construction slowed significantly after the accident at Three Mile Island near Middletown, Pennsylvania, on March 28, 1979, even as interest in next-gen nuclear power has grown in recent years. From 1979 through 1988, 67 nuclear reactor construction projects were canceled, according to the U.S. Energy Information Administration.

However, because nuclear energy is generated without releasing carbon dioxide emissions, which cause global warming, the increased sense of urgency in responding to climate change has given nuclear energy a chance at a renaissance as atomic energy heats up again globally.

The cost associated with building nuclear reactors is a major barrier to a potential resurgence in nuclear energy, however, even as nuclear generation costs have fallen to a ten-year low. And the new builds at Vogtle have become an epitome of that charge: The construction of the two Vogtle reactors has been plagued by cost overruns and delays.
 

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Little Haiti Garbage Truck Power Outage in Miami after mechanical arms snagged power lines, snapping power poles; FPL crews, police, and businesses faced traffic delays, safety risks, and rapid restoration efforts across the neighborhood.

Key Points

A Miami incident where a garbage truck snagged power lines, toppling poles and causing outages and traffic delays.

✅ Mechanical arms caught overhead lines; three power poles snapped

✅ FPL dispatched, police directed traffic; restoration prioritized

✅ Dozens of businesses affected; afternoon rush hour congestion

On January 16, 2025, a significant incident unfolded in Miami's Little Haiti neighborhood when a garbage truck collided with power lines, causing three power poles to collapse and resulting in widespread power outages and traffic disruptions.

Incident Details

Around 1:30 p.m., a garbage truck traveling west on Northeast 82nd Street toward Interstate 95 became entangled with overhead power lines. The truck's mechanical arms caught the lines, leading to the snapping of three power poles and plunging the area into darkness, a scenario echoed by urban incidents like a manhole fire that left thousands without power. Witnesses reported a loud boom followed by an immediate power outage. One local business owner described the event, stating, "There was a loud boom, and suddenly the power went out."

Impact on the Community

The incident caused significant disruptions in the Little Haiti area. At least a dozen businesses were affected by the power outage, and in wider Florida events restoration can take weeks depending on damage, leading to operational halts and potential financial losses. The timing of the crash, during the afternoon rush hour, exacerbated traffic congestion as commuters were forced to navigate through the area, and similar disruptions occur when strong winds knock out power, further complicating the situation.

Response and Recovery Efforts

In response to the incident, Miami police directed traffic to alleviate congestion and ensure public safety. Florida Power & Light (FPL) crews, known for their major outage response, were promptly dispatched to the scene to assess the damage and begin restoration efforts. The priority was to safely remove the damaged power poles and restore electricity to the affected area. FPL's swift action was crucial in minimizing the duration of the power outage and restoring normalcy to the community.

Safety Considerations

This incident underscores the importance of safety protocols for vehicles operating in areas with overhead power lines. Garbage trucks, due to their design and operational mechanisms, are particularly susceptible to such accidents, and in broader disasters some regions require a power grid rebuild to recover, highlighting the stakes. It is imperative for operators to be vigilant and adhere to safety guidelines to prevent similar occurrences.

Community Resilience

Despite the challenges posed by the incident, the Little Haiti community demonstrated resilience. Local businesses and residents cooperated with authorities, while utilities elsewhere have restored power to thousands after major events, and the prompt response from emergency services highlighted the community's strength in the face of adversity.

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Offshore Wind Cost Competitiveness is rising as larger turbines boost megawatt output, cut LCOE, and trim maintenance and installation time, enabling projects in New England to rival natural gas pricing while scaling reliably.

Key Points

It describes how larger offshore turbines lower LCOE and O&M, making U.S. projects price competitive with natural gas.

✅ Larger turbines boost MW output and reduce LCOE.

✅ Lower O&M and faster installation cut lifecycle costs.

✅ Competes with gas in New England bids, per BNEF.

Massive offshore wind turbines keep getting bigger, as projects like the biggest UK offshore wind farm come online, and that’s helping make the power cheaper — to the point where developers say new projects in U.S. waters can compete with natural gas.

The price “is going to be a real eye-opener,” said Bryan Martin, chairman of Deepwater Wind LLC, which won an auction in May to build a 400-megawatt wind farm southeast of Rhode Island.

Deepwater built the only U.S. offshore wind farm, a 30-megawatt project that was completed south of Block Island in 2016. The company’s bid was selected by Rhode Island the same day that Massachusetts picked Vineyard Wind to build an 800-megawatt wind farm in the same area, while international investors such as Japanese utilities in UK projects signal growing confidence.

#google#

Bigger turbines that make more electricity have cut the cost per megawatt by about half, a trend aided by higher-than-expected wind potential in many markets, said Tom Harries, a wind analyst at Bloomberg New Energy Finance. That also reduces maintenance expenses and installation time. All of this is helping offshore wind vie with conventional power plants.

“You could not build a thermal gas plant in New England for the price of the wind bids in Massachusetts and Rhode Island,” Martin said Friday at the U.S. Offshore Wind Conference in Boston. “It’s very cost-effective for consumers.”

The Massachusetts project could be about $100 to $120 a megawatt hour, according to a February estimate from Harries, though recent UK price spikes during low wind highlight volatility. The actual prices there and in Rhode Island weren’t disclosed.

For comparison, a new U.S. combine-cycle gas turbine ranges from $40 to $60 a megawatt-hour, and a new coal plant is $67 to $113, according to BNEF data.

A new power plant in land-constrained New England would probably be higher than that, and during winter peaks the region has seen record oil-fired generation in New England that underscores reliability concerns. More importantly, gas plants get a significant portion of their revenue from being able to guarantee that power is always available, something wind farms can’t do, said William Nelson, a New York-based analyst with BNEF. Looking only at the price at which offshore turbines can deliver electricity is a “narrow mindset,” he said.

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