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Muskrat Falls rate mitigation offsets Newfoundland Power's rate stabilization decrease as NL Hydro begins cost recovery; Public Utilities Board approval enables collections while Labrador-Island Link nears commissioning, stabilizing electricity rates despite megaproject delays, overruns.

Key Points

Muskrat Falls rate mitigation is NL Hydro's cost recovery via power rates to stabilize bills as commissioning nears.

✅ Offsets 6.4% decrease with a 6.1% rate increase

✅ About 6% now funds NL Hydro's rate mitigation

✅ Collections begin as Labrador-Island Link nears commissioning

With their July electricity bill, Newfoundland Power customers have begun paying for Muskrat Falls, though a lump-sum credit was also announced to offset costs and bills haven't significantly increased — yet.

In a July newsletter, Newfoundland Power said electricity bills were set to decrease by 6.4 per cent as part of the annual rate stabilization adjustment, which reflects the cost of electricity generation.

Instead, that decrease has been offset by a 6.1 increase in electricity rates so Newfoundland and Labrador Hydro can begin recovering the cost of Muskrat Falls, with a $5.2-billion federal package also underpinning the project, the $13-billion hydroelectric megaproject that is billions over budget and years behind schedule.

That means for residential customers, electricity rates will decrease to 12.346 cents per kilowatt, though the basic customer charge will go up slightly from $15.81 to $15.83. According to an N.L. Hydro spokesperson, about six per cent of electricity bills will now go toward what it calls a "rate mitigation fund." 

N.L. Hydro claims victory in Muskrat Falls arbitration dispute with Astaldi
Software troubles blamed for $260M Muskrat Falls cost increase, with N.L. power rates stable for now
The spokesperson said N.L. Hydro is expecting the rate increase to result in $43 million this year, according to a recent financial update from the energy corporation — a tiny fraction of the project's cost. 

N.L. Hydro asked the Public Utilities Board to approve the rate increase, a process similar to Nova Scotia's recent 14% approval by its regulator, in May. In a letter, Energy, Industry and Technology Minister Andrew Parsons supported the increase, though he asked N.L. Hydro to keep electricity rates "as close to current levels as possible. 

Province modifies order in council
Muskrat Falls is not yet fully online — largely due to software problems with the Labrador-Island Link transmission line — and an order in council dictated that ratepayers on the island of Newfoundland would not begin paying for the project until the project was fully commissioned. 

The provincial government modified that order in council so N.L. Hydro can begin collecting costs associated with Muskrat Falls once the project is "nearing" commissioning.

In June, N.L. Hydro said the project was expected to finally be completed by the end of the year.

In an interview with CBC News, Progressive Conservative interim leader David Brazil said the decision to begin recovering the cost of Muskrat Falls from consumers should have been delayed.

"There was an opportunity here for people to get some reprieve when it came to their electricity bills and this administration chose not to do that, not to help the people while they're struggling," he said.

In a statement, Parsons said reducing the rate was not an option, and would have resulted in increased borrowing costs for Muskrat Falls.

"Reducing the rate for one year to have it increase significantly the following year is not consistent with rate mitigation and also places an increased financial burden on taxpayers one year from now," Parsons said.

Decision 'reasonable': Consumer advocate
Brazil said his party didn't know the payments from Muskrat Falls would start in July, and criticized the government for not being more transparent.

A person wearing a blue shirt and black blazer stands outside on a lawn.
N.L. consumer advocate Dennis Browne says it makes sense to begin recouping the cost of Muskrat Falls. (Garrett Barry/CBC)
Newfoundland and Labrador consumer advocate Dennis Browne said the decision to begin collecting costs from consumers was "reasonable."

"We're into a financial hole due to Muskrat Falls, and what has happened is in order to stabilize rates, we have gone into rate stabilization efforts," he said.

In February, the provincial and federal governments signed a complex agreement to shield ratepayers aimed at softening the worst of the financial impact from Muskrat Falls. Browne noted even with the agreement, the provincial government will have to pay hundreds of millions in order to stabilize electricity rates.

"Muskrat Falls would cost us $0.23 a kilowatt, and that is out of the range of affordability for most people, and that's why we're into rate mitigation," he said. "This was part of a rate mitigation effort, and I accepted it as part of that."

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Ontario CDM Programs expand energy efficiency, demand response, and DER incentives via IESO's Save on Energy, cutting peak demand, lowering bills, and supporting electrification, retrofits, and LED lighting to meet Ontario's growing electricity needs.

Key Points

Ontario CDM Programs are IESO incentives that cut peak demand and energy use via demand response, retrofits and DERs.

✅ Delivered by IESO's Save on Energy to reduce peak demand

✅ Incentives for demand response, retrofits, LEDs, and DER solutions

✅ Help homes, businesses, and greenhouses lower bills and emissions

Ontario will be making available four new and expanded energy-efficiency programs, also known as Conservation and Demand Management (CDM) programs, to ensure a reliable, affordable, and clean electricity system, including ultra-low overnight pricing options to power the province, drive electrification and support strong economic growth. As there will be a need for additional electricity capacity in Ontario beginning in 2025, and continuing through the decade, CDM programs are among the fastest and most cost-effective ways of meeting electricity system needs.

Conservation and Demand Management

The Ontario government launched the 2021-2024 CDM Framework on January 1, 2021. The framework focuses on cost-effectively meeting the needs of Ontario’s electricity system, including by focusing on the achievement of provincial peak demand reductions and initiatives such as extended off-peak electricity rates, as well as on targeted approaches to address regional and/or local electricity system needs.

CDM programs are delivered by the Independent Electricity System Operator (IESO), which implemented staff lockdown measures during COVID-19, through the Save on Energy brand. These programs address electricity system needs and help consumers reduce their electricity consumption to lower their bills. CDM programs and incentives are available for homeowners, small businesses, large businesses, and contractors, and First Nations communities.

New and Expanded Programs

The four new and expanded CDM programs will include:

A new Residential Demand Response Program for homes with existing central air conditioning and smart thermostats to help deliver peak demand reductions. Households who meet the criteria could voluntarily enroll in this program and, alongside protections like disconnection moratoriums for residential customers, be paid an incentive in return for the IESO being able to reduce their cooling load on a select number of summer afternoons to reduce peak demand. There are an estimated 600,000 smart thermostats installed in Ontario.
Targeted support for greenhouses in Southwest Ontario, including incentives to install LED lighting, non-lighting measures or behind-the-meter distributed energy resources (DER), such as combined solar generation and battery storage.
Enhancements to the Save On Energy Retrofit Program for business, municipalities, institutional and industrial consumers to include custom energy-efficiency projects. Examples of potential projects could include chiller and other HVAC upgrades for a local arena, building automation and air handling systems for a hospital, or building envelope upgrades for a local business.
Enhancements to the Local Initiatives Program to reduce barriers to participation and to add flexibility for incentives for DER solutions.
It is the government’s intention that the new and expanded CDM programs will be available to eligible electricity customers beginning in Spring 2023.

The IESO estimates that the new program offers will deliver total provincial peak electricity demand savings of 285 megawatts (MW) and annual energy savings of 1.1 terawatt hours (TWh) by 2025, reflecting pandemic-era electricity usage shifts across Ontario. Savings will persist beyond 2025 with a total reduction in system costs by approximately $650 million over the lifetime of the measures, and will support economic recovery, as seen with electricity relief during COVID-19 measures, decarbonization and energy cost management for homes and businesses.

These enhancements will have a particular impact in Southwest Ontario, with regional peak demand savings of 225 MW, helping to alleviate electricity system constraints in the region and foster economic development, supported by stable electricity pricing for industrial and commercial companies in Ontario.

The overall savings from this CDM programming will result in an estimated three million tonnes of greenhouse gas emissions reductions over the lifetime of the energy-efficiency measures to help achieve Ontario’s climate targets and protect the environment for the future.

The IESO will be updating the CDM Framework Program Plan, which provides a detailed breakdown of program budgets and energy savings and peak demand targets expected to be achieved.

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Australia electricity grid transition is accelerating as renewables, wind, solar, and storage drive decentralised generation, emissions cuts, and NEM trade shifts, with South Australia becoming a net exporter post-Hazelwood closure and rooftop solar surging.

Key Points

Australia electricity shift to renewables, distributed generation and storage, cutting emissions, reshaping NEM flows.

✅ South Australia now exports power post-Hazelwood closure

✅ Rooftop solar is the fastest-growing NEM generation source

✅ Gas peaking and storage investments balance variable renewables

The politics may not change much, but Australia’s electricity grid is changing before our very eyes – slowly and inevitably becoming more renewable, more decentralised, and in step with Australia's energy transition that is challenging the pre-conceptions of many in the industry.

The latest national emissions audit from The Australia Institute, which includes an update on key electricity trends in the national electricity market, notes some interesting developments over the last three months.

The most surprising of those developments may be the South Australia achievement, which shows that since the closure of the Hazelwood brown coal generator in Victoria in March 2017, and as renewables outpacing brown coal in other markets, South Australia has become a net exporter of electricity, in net annualised terms.

Hugh Saddler, lead author of the study, notes that this is a big change for South Australia, which in 1999 and 2000, when it had only gas and local coal, used to import 30% of its electricity demand.

#google#

The fact that wholesale prices in South Australia were higher in other states – then, as they are now – has nothing to with wind and solar, but the fact that it has no low-cost conventional source and a peaky demand profile (then and now).

“The difference today is that the state is now taking advantage of its abundant resources of wind and solar radiation, and the new technologies which have made them the lowest cost sources of new generation, to supply much of its electricity requirements,” Saddler writes.

Other things to note about the flows between states is that Victoria was about equal on imports and exports with its three neighbouring states, despite the closure of Hazelwood. NSW continues to import around 10% of its needs from cheaper providers in Queensland.

Gas-fired generation had increased in the last year or two in South Australia as a result of the Northern closure, but is still below the levels of a decade ago.

But because it is expensive, this is likely to spur more investment in storage.

As for rooftop solar, Saddler notes that the share of residential solar in the grid is still relatively small but, despite excess solar risks flagged by distributors, it is the most steadily growing generation source in the NEM.

That line is expected to grow steadily. By 2040, or perhaps 2050, the share of distributed generation, which includes rooftop solar, battery storage and demand management, is expected to reach nearly half of all Australia’s grid demand.

Saddler, says, however, that the increase in large-scale solar over the last few months is a significant milestone in Australia’s transition towards clean electricity generation, mirroring trends in India's on-grid solar development seen in recent years. (See very top graph).

“Firstly, they are a concrete demonstration that the construction cost advantage, which wind enjoyed over solar until a year or two ago, is gone.

“From now on we can expect new capacity to be a mix of both technologies. Indeed, the Clean Energy Regulator states that it expects solar to account for half of all (new renewable) capacity by 2020, and the US is moving toward 30% from wind and solar as well.”

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EU Gas Price Cap Strategies aim to curb inflation during an energy crisis by capping wholesale gas and electricity generation costs, balancing supply and demand, mitigating subsidies, and safeguarding supply security amid Russia-Ukraine shocks.

Key Points

Temporary EU measures to cap gas and power prices, curb inflation, manage demand, and protect supply security.

✅ Flexible temporary price limits to secure gas supplies

✅ Framework cap on gas for electricity generation with demand checks

✅ Risk: subsidies, higher demand, and market distortions

The European Commission has outlined possible strategies to cap gas prices as the bloc faces a looming energy crisis this winter. 

Member states are divided over the emergency measures designed to pull down soaring inflation amid Russia's war in Ukraine. 

One proposal is a temporary "flexible" limit on gas prices to ensure that Europe can continue to secure enough gas, EU energy commissioner Kadri Simson said on Tuesday. 

Another option could be an EU-wide "framework" for a price cap on gas used to generate electricity, which would be combined with measures to ensure gas demand does not rise as a result, she said.

EU leaders are meeting on Friday to debate gas price cap strategies amid warnings that Europe's energy nightmare could worsen this winter.

Last week, France, Italy, Poland and 12 other EU countries urged the Commission to propose a broader price cap targeting all wholesale gas trade. 

But Germany -- Europe's biggest gas buyer -- and the Netherlands are among those opposing electricity market reforms within the bloc.

Russia has slashed gas deliveries to Europe since its February invasion of Ukraine, with Moscow blaming the cuts on Western sanctions imposed in response to the invasion, as the EU advances a plan to dump Russian energy across the bloc.

Since then, the EU has agreed on emergency laws to fill gas storage and windfall profit levies to raise money to help consumers with bills. 

Price cap critics
One energy analyst told Euronews that an energy price cap was an "unchartered territory" for the European Union. 

The EU's energy sector is largely liberalised and operates under the fundamental rules of supply and demand, making rolling back electricity prices complex in practice.

"My impression is that member states are looking at prices and quantities in isolation and that's difficult because of economics," said Elisabetta Cornago, a senior energy researcher at the Centre for European Reform.

"It's hard to picture such a level of market intervention This is uncharted territory."

The energy price cap would "quickly start costing billions" because it would force governments to continually subsidise the difference between the real market price and the artificially capped price, another expert said. 

"If you are successful and prices are low and you still get gas, consumers will increase their demand: low price means high demand. Especially now that winter is coming," said Bram Claeys, a senior advisor at the Regulatory Assistance Project. 

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California Wildfire Smoke Impact on Solar reduces photovoltaic output, as particulate pollution, soot, and haze dim sunlight and foul panels, cutting utility-scale generation and grid reliability across CAISO during peak demand and heatwaves.

Key Points

How smoke and soot cut solar irradiance and foul panels, slashing PV generation and straining CAISO grid operations.

✅ Smoke blocks sunlight; soot deposition reduces panel efficiency.

✅ CAISO reported ~30% drop versus July during peak smoke.

✅ Longer fire seasons threaten solar reliability and capacity planning.

Smoke from California’s unprecedented wildfires was so bad that it cut a significant chunk of solar power production in the state, even as U.S. solar generation rose in 2022 nationwide. Solar power generation dropped off by nearly a third in early September as wildfires darkened the skies with smoke, according to the US Energy Information Administration.

Those fires create thick smoke, laden with particles that block sunlight both when they’re in the air and when they settle onto solar panels. In the first two weeks of September, soot and smoke caused solar-powered electricity generation to fall 30 percent compared to the July average, according to the California Independent System Operator (CAISO), which oversees nearly all utility-scale solar energy in California, where wind and solar curtailments have been rising amid grid constraints. It was a 13.4 percent decrease from the same period last year, even though solar capacity in the state has grown about 5 percent since September 2019.

California depends on solar installations for nearly 20 percent of its electricity generation, and has more solar capacity than the next five US states trailing it combined as it works to manage its solar boom sustainably. It will need even more renewable power to meet its goal of 100 percent clean electricity generation by 2045, building on a recent near-100% renewable milestone that underscored the transition. The state’s emphasis on solar power is part of its long-term efforts to avoid more devastating effects of climate change. But in the short term, California’s renewables are already grappling with rising temperatures.

Two records were smashed early this September that contributed to the loss of solar power. California surpassed 2 million acres burned in a single fire season for the first time (1.7 million more acres have burned since then). And on September 15th, small particle pollution reached the highest levels recorded since 2000, according to the California Air Resources Board. Winds that stoked the flames also drove pollution from the largest fires in Northern California to Southern California, where there are more solar farms.

Smaller residential and commercial solar systems were affected, too, and solar panels during grid blackouts typically shut off for safety, although smoke was the primary issue here. “A lot of my systems were producing zero power,” Steve Pariani, founder of the solar installation company Solar Pro Energy Systems, told the San Mateo Daily Journal in September.

As the planet heats up, California’s fire seasons have grown longer, and blazes are tearing through more land than ever before, while grid operators are also seeing rising curtailments as they integrate more renewables. For both utilities and smaller solar efforts, wildfire smoke will continue to darken solar energy’s otherwise bright future, even as it becomes the No. 3 renewable source in the U.S. by generation.

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European Gas Prices hit pre-invasion lows as LNG inflows, EU storage gains, and softer oil markets ease the energy crisis, while recession risks, windfall taxes, and ExxonMobil's challenge shape demand and policy.

Key Points

European gas prices reflect supply, LNG inflows, storage, and policy, shaping energy costs for households and industry.

✅ Month-ahead hit €76.78/MWh, rebounding to €85.50/MWh.

✅ EU storage 83.2% filled; autumn peak exceeded 95%.

✅ Demand tempered by recession risks; LNG inflows offset Russian cuts.

European gas prices have dipped to a level last seen before Russia launched its invasion of Ukraine in February, after warmer weather across the continent eased concerns over shortages and as coal demand dropped across Europe during winter.

The month-ahead European gas future contract dropped as low as €76.78 per megawatt hour on Wednesday, the lowest level in 10 months, amid EU talks on gas price cap strategies that could shape markets, before closing higher at €83.70, according to Refinitiv, a data company.

The invasion roiled global energy markets, serving as a wake-up call to ditch fossil fuels for policymakers, and forced European countries, including industrial powerhouse Germany, to look for alternative suppliers to those funding the Kremlin. Europe had continued to rely on Russian gas even after its 2014 annexation of Crimea and support for separatists in eastern Ukraine.

On Tuesday 83.2% of EU gas storage was filled, data from industry body Gas Infrastructure Europe showed. The EU in May set a target of filling 80% of its gas storage capacity by the start of November to prepare for winter, and weighed emergency electricity measures to curb prices as needed. It hit that target in August, and by mid-November it had peaked at more than 95%.

Gas prices bounced further off the 10-month low on Thursday to reach €85.50 per megawatt hour.

Europe has several months of domestic heating demand ahead, and some industry bosses believe energy shortages could also be a problem next winter, with a worst energy nightmare still possible if supplies tighten. However, traders have also had to weigh the effects of recessions expected in several big European economies, which could dent energy demand.

UK gas prices have also dropped back from their highs earlier this year, and forecasts suggest UK energy bills to drop in April. The day-ahead gas price closed at 155p per therm on Wednesday, compared with 200p/therm at the start of 2022, and more than 500p/therm in August.

Europe’s response to the prospect of gas shortages also included campaigns to reduce energy use – a strategy belatedly adopted by the UK – and windfall taxes on energy companies to help raise revenues for governments, many of which have started expensive subsidies to cushion the impact of high energy prices for households and consumers. Energy companies have enjoyed huge profits at the expense of businesses and households this year, as EU inflation accelerated, but costs remained much the same.

However, the US oil company ExxonMobil on Wednesday launched a legal challenge against EU plans for a windfall tax on oil companies, according to filings by its German and Dutch subsidiaries at the European general court in Luxembourg. ExxonMobil argued that the windfall tax would be “counter-productive” because it said it would result in lower investment in fossil fuel extraction, and that the EU did not have the legal jurisdiction to impose it.

ExxonMobil’s move has prompted anger among European politicians. A message posted on the Twitter account of Paolo Gentiloni, the EU’s commissioner for the economy, on Thursday stated: “Fairness and solidarity, even for corporate giants. #Exxon.”

Oil prices are significantly lower than they were before the start of Russia’s invasion, and only marginally above where they were at the start of 2022. Brent crude oil futures traded at $100 a barrel on 28 February, but were at $81.84 on Thursday.

Oil prices dropped by 1.7% on Thursday. Prices had risen from 12-month lows in early December as traders hoped for increased demand from China after it relaxed its coronavirus restrictions. However, Covid-19 infection numbers are thought to have surged in the country, prompting the US to require travellers from China to show a negative test for the disease and tempering expectations for a rapid increase in oil demand.

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