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Canada Clean Electricity Regulations 2050 balance net-zero goals with grid reliability and affordability, setting emissions caps, enabling offset credits, and flexible provincial pathways, including support for non-grid facilities during the clean energy transition.

Key Points

A federal plan for a net-zero grid by 2050 with emissions caps, offsets, and flexible provincial compliance.

✅ Emissions cap targeting 181 Mt CO2 from the power sector by 2050

✅ Offset credits and annual limits enable compliance flexibility

✅ Support for remote, non-grid facilities and regional pathways

In December 2024, the Government of Canada announced a significant policy shift regarding its clean electricity objectives. The initial target to achieve a net-zero electricity grid by 2035 has been extended to 2050. This decision reflects the government's response to feedback from provinces and energy industry stakeholders, who expressed concerns about the feasibility of meeting the 2035 deadline.

Revised Clean Electricity Regulations

The newly finalized Clean Electricity Regulations (CER) outline the framework for Canada's transition to a net-zero electricity grid by 2050, advancing the goal of 100 per cent clean electricity nationwide.

• Emissions Reduction Targets: The regulations set a cap on emissions from the electricity sector, targeting a reduction of 181 megatonnes of CO₂ by 2050. This is a decrease from the previous goal of 342 megatonnes, reflecting a more gradual approach to emissions reduction.

• Flexibility Mechanisms: To accommodate the diverse energy landscapes across provinces, the CER introduces flexibility measures. These include annual emissions limits and the option to use offset credits, allowing provinces to tailor their strategies while adhering to national objectives.

• Support for Non-Grid Connected Facilities: Recognizing the unique challenges of remote and off-grid communities, the regulations provide accommodations for certain non-grid connected facilities, ensuring that all regions can contribute to the national clean electricity goals.

Implications for Canada's Energy Landscape

The extension of the net-zero electricity target to 2050 signifies a strategic recalibration of Canada's energy policy. This adjustment acknowledges the complexities involved in transitioning to a clean energy future, including:

• Grid Modernization: Upgrading the electrical grid to accommodate renewable energy sources and ensure reliability is a critical component of the transition, especially as Ontario's EV wave accelerates across the province.

• Economic Considerations: Balancing environmental objectives with economic impacts is essential. The government aims to create over 400,000 clean energy jobs, fostering economic growth while reducing emissions, supported by ambitious EV goals in the transport sector.

• Regional Variations: Provinces have diverse energy profiles and resources, and British Columbia's power supply challenges highlight planning constraints. The CER's flexibility mechanisms are designed to accommodate these differences, allowing for tailored approaches that respect regional contexts.

Public and Industry Reactions

The policy shift has elicited varied responses:

• Environmental Advocates: Some environmental groups express concern that the extended timeline may delay critical climate action, while debates over Quebec's push for EV dominance underscore policy trade-offs. They emphasize the need for more ambitious targets to address the escalating impacts of climate change.

• Industry Stakeholders: The energy sector generally welcomes the extended timeline, viewing it as a pragmatic approach that allows for a more measured transition, particularly amid criticism of the 2035 EV mandate in transportation policy. The flexibility provisions are particularly appreciated, as they provide the necessary leeway to adapt to evolving market and technological conditions.

Looking Forward

As Canada moves forward with the implementation of the Clean Electricity Regulations, the focus will be on:

• Monitoring Progress: Establishing robust mechanisms to track emissions reductions and ensure compliance with the new targets.

• Stakeholder Engagement: Continuing dialogue with provinces, industry, and communities to refine strategies and address emerging challenges, including coordination on EV sales regulations as complementary measures.

• Innovation and Investment: Encouraging the development and deployment of clean energy technologies through incentives and support programs.

The extension of Canada's net-zero electricity target to 2050 represents a strategic adjustment aimed at achieving a balance between environmental goals and practical implementation considerations. The Clean Electricity Regulations provide a framework that accommodates regional differences and industry concerns, setting the stage for a sustainable and economically viable energy future.

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Montreal Power Outage linked to Hydro-Que9bec infrastructure after an underground explosion and manhole fire in Rosemont–La Petite–Patrie, disrupting the STM Blue Line and forcing strategic, cold-weather grid restoration on Be9langer Street.

Key Points

Outage from an underground blast and manhole fire disrupted STM service; Hydro-Que9bec restored the grid in cold weather.

✅ Peak impact: 41,000 customers; 10,981 still without power by 7:00 p.m.

✅ STM Blue Line restored after afternoon shutdown; Be9langer Street reopened.

✅ Hydro-Que9bec pacing restoration to avoid grid overload in cold weather.

Hydro-Québec says a power outage affecting Montreal is connected to an underground explosion and a fire in a manhole in Rosemont—La Petite–Patrie. 

The fire started in underground pipes belonging to Hydro-Québec on Bélanger Street between Boyer and Saint-André streets, according to Montreal firefighters, who arrived on the scene at 12:18 p.m.

The electricity had to be cut so that firefighters could get into the manhole where the equipment was located.

At the peak of the shutdown, nearly 41,000 customers were without power across Montreal.  As of 7:00 p.m., 10,981 clients still had no power.

In similar storms, Toronto power outages have persisted for hundreds, underscoring restoration challenges.

Hydro-Québec spokesperson Louis-Olivier Batty said the utility is being strategic about how it restores power across the grid. 

Because of the cold, and patterns seen during freezing rain outages, it anticipates that people will crank up the heat as soon as they get their electricity back, and that could trigger an overload somewhere else on the network, Batty said.

The Metro's Blue line was down much of the afternoon, but the STM announced the line was back up and running just after 4:30 p.m.

Bélanger Street was blocked to traffic much of the afternoon, however, it has now been reopened.

Batty said once the smoke clears, Hydro-Québec workers will take a look at the equipment to see what failed. 

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UK Hydrogen Storage Caverns enable long-duration, low-carbon electricity balancing, storing surplus wind and solar power as green hydrogen in salt formations to enhance grid reliability, energy security, and net zero resilience by 2035 and 2050.

Key Points

They are salt caverns storing green hydrogen to balance wind and solar, stabilizing a low-carbon UK grid.

✅ Stores surplus wind and solar as green hydrogen in salt caverns

✅ Enables long-duration, low-carbon grid balancing and security

✅ Complements wind and solar; reduces dependence on flexible CCS

The U.K. government must kick-start the construction of large-scale hydrogen storage facilities if it is to meet its pledge that all electricity will come from low-carbon electricity sources by 2035 and reach legally binding net zero targets by 2050, according to a report by the Royal Society.

The report, "Large-scale electricity storage," published Sep. 8, examines a wide variety of ways to store surplus wind and solar generated electricity—including green hydrogen, advanced compressed air energy storage (ACAES), ammonia, and heat—which will be needed when Great Britain's electricity generation is dominated by volatile wind and solar power.

It concludes that large scale electricity storage is essential to mitigate variations in wind and sunshine, particularly long-term variations in the wind, and to keep the nation's lights on. Storing most of the surplus as hydrogen, in salt caverns, would be the cheapest way of doing this.

The report, based on 37 years of weather data, finds that in 2050 up to 100 Terawatt-hours (TWh) of storage will be needed, which would have to be capable of meeting around a quarter of the U.K.'s current annual electricity demand. This would be equivalent to more than 5,000 Dinorwig pumped hydroelectric dams. Storage on this scale, which would require up to 90 clusters of 10 caverns, is not possible with batteries or pumped hydro.

Storage requirements on this scale are not currently foreseen by the government, and the U.K.'s energy transition faces supply delays. Work on constructing these caverns should begin immediately if the government is to have any chance of meeting its net zero targets, the report states.

Sir Chris Llewellyn Smith FRS, lead author of the report, said, "The need for long-term storage has been seriously underestimated. Demand for electricity is expected to double by 2050 with the electrification of heat, transport, and industrial processing, as well as increases in the use of air conditioning, economic growth, and changes in population.

"It will mainly be met by wind and solar generation. They are the cheapest forms of low-carbon electricity generation, but are volatile—wind varies on a decadal timescale, so will have to be complemented by large scale supply from energy storage or other sources."

The only other large-scale low-carbon sources are nuclear power, gas with carbon capture and storage (CCS), and bioenergy without or with CCS (BECCS). While nuclear and gas with CCS are expected to play a role, they are expensive, especially if operated flexibly.

Sir Peter Bruce, vice president of the Royal Society, said, "Ensuring our future electricity supply remains reliable and resilient will be crucial for our future prosperity and well-being. An electricity system with significant wind and solar generation is likely to offer the lowest cost electricity but it is essential to have large-scale energy stores that can be accessed quickly to ensure Great Britain's energy security and sovereignty."

Combining hydrogen with ACAES, or other forms of storage that are more efficient than hydrogen, could lower the average cost of electricity overall, and would lower the required level of wind power and solar supply.

There are currently three hydrogen storage caverns in the U.K., which have been in use since 1972, and the British Geological Survey has identified the geology for ample storage capacity in Cheshire, Wessex and East Yorkshire. Appropriate, novel business models and market structures will be needed to encourage construction of the large number of additional caverns that will be needed, the report says.

Sir Chris observes that, although nuclear, hydro and other sources are likely to play a role, Britain could in principle be powered solely by wind power and solar, supported by hydrogen, and some small-scale storage provided, for example, by batteries, that can respond rapidly and to stabilize the grid. While the cost of electricity would be higher than in the last decade, we anticipate it would be much lower than in 2022, he adds.

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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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Japan Offshore Wind Investment signals Japanese utilities entering UK offshore wind, as J-Power and Kansai Electric buy into Innogy's Triton Knoll, leveraging North Sea expertise, 9.5MW turbines, and 15-year fixed-rate contracts.

Key Points

Japanese utilities buying UK offshore wind stakes to import expertise, as J-Power and Kansai join Innogy's Triton Knoll.

✅ $900M deal: J-Power 25%, Kansai Electric ~16% in Innogy unit

✅ Triton Knoll: 860MW, up to 90 9.5MW turbines, 15-year fixed PPA

✅ Goal: Transfer North Sea expertise to develop Japan offshore wind

Two of Japan's biggest power companies will buy around 40% of a German-owned developer of offshore wind farms in the U.K., seeking to learn from Britain's lead in this sector, as highlighted by a UK offshore wind milestone this week, and bring the know-how back home.

Tokyo-based Electric Power Development, better known as J-Power, will join Osaka regional utility Kansai Electric Power in investing in a unit of Germany's Innogy.

The deal, estimated to be worth around $900 million, will give J-Power a 25% stake and Kansai Electric a roughly 16% share. It will mark the first investment in an offshore wind project by Japanese power companies, as other markets shift strategies, with Poland backing wind over nuclear signaling broader momentum.

Innogy plans to start up the 860-megawatt Triton Knoll offshore wind project -- one of the biggest of its kind in the world -- in the North Sea in 2021. The vast installation will have up to 90 9.5MW turbines and sell its output to local utilities under a 15-year fixed-rate contract.

J-Power, which supplies mainly fossil-fuel-based electricity to Japanese regional utilities, will set up a subsidiary backed by the government-run Development Bank of Japan to participate in the Innogy project. Engineers will study firsthand construction and maintenance methods.

While land-based wind turbines are proliferating worldwide, offshore wind farms have progressed mainly in Europe, though U.S. offshore wind competitiveness is improving in key markets. Installed capacity totaled more than 18,000MW at the end of 2017, which at maximum capacity can produce as much power as 18 nuclear reactors.

Japan has hardly any offshore wind farms in commercial operation, and has little in the way of engineering know-how in this field or infrastructure for linking such installations to the land power grid, with a recent Japan grid blackout analysis underscoring these challenges. But there are plans for a total of 4,000MW of offshore wind power capacity, including projects under feasibility studies.

J-Power set up a renewable energy division in June to look for opportunities to expand into wind and geothermal energy in Japan, and efforts like a Japan hydrogen energy system are emerging to support decarbonization. Kansai Electric also seeks know-how for increasing its reliance on renewable energy, even as it hurries to restart idled nuclear reactors.

They are not the only Japanese investors is in this field. In Asia, trading house Marubeni will invest in a Taiwanese venture with plans for a 600MW offshore wind farm.

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Energy Pricing Factors span electricity generation, transmission, and distribution costs, plus natural gas supply-demand, renewables, seasonal peaks, and wholesale pricing effects across residential, commercial, and industrial customers, usage patterns, weather, and grid constraints.

Key Points

They are the costs and market forces driving electricity and natural gas prices, from generation to delivery and demand.

✅ Generation, transmission, distribution shape electricity rates

✅ Gas prices hinge on supply, storage, imports/exports

✅ Demand shifts: weather, economy, and fuel alternatives

There are a lot of factors that affect energy prices globally. What’s included in the price to heat homes and supply them with electricity may be a lot more than some people may think.

Electricity
Generating electricity is the largest component of its price, according to the U.S. Energy Information Administration (EIA). Generation accounts for 56% of the price of electricity, while distribution and transmission account for 31% and 13% respectively.

Homeowners and businesses pay more for electricity than industrial companies, and U.S. electricity prices have recently surged, highlighting broader inflationary pressures. This is because industrial companies can take electricity at higher voltages, reducing transmission costs for energy companies.

“Industrial consumers use more electricity and can receive it at higher voltages, so supplying electricity to these customers is more efficient and less expensive. The price of electricity to industrial customers is generally close to the wholesale price of electricity,” EIA explains.

NYSEG said based on the average use of 600 kilowatt-hours per month, its customers spent the most money on delivery and transition charges in 2020, 57% or about $42, and residential electricity bills increased 5% in 2022 after inflation, according to national data. They also spent on average 35% (~$26) on supply charges and 8% (~$6) on surcharges.

Electricity prices are usually higher in the summer. Why? Because energy companies use sources of electricity that cost more money. It used to be that renewable sources, like solar and wind, were the most expensive sources of energy but increased technological advances have changed this, according to the International Energy Agency’s 2021 World Energy Outlook.

“In most markets, solar PV or wind now represents the cheapest available source of new electricity generation. Clean energy technology is becoming a major new area for investment and employment – and a dynamic arena for international collaboration and competition,” the report said.

Natural gas
The price of natural gas is driven by supply and demand. If there is more supply, prices are generally lower. If there is not as much supply, prices are generally higher the EIA explains. On the other side of the equation, more demand can also increase the price and less demand can decrease the price.

High natural gas prices mean people turn their home thermostats down a few degrees to save money, so the EIA said reduced demand can encourage companies to produce more natural gas, which would in turn help lower the cost. Lower prices will sometimes cause companies to reduce their production, therefore causing the price to rise.

The three major supply factors that affect prices: the amount of natural gas produced, how much is stored, and the volume of gas imported and exported. The three major demand factors that affect price are: changes in winter/summer weather, economic growth, and the broader energy crisis dynamics, as well as how much other fuels are available and their price, said EIA.

To think the price of natural gas is higher when the economy is thriving may sound counterintuitive but that’s exactly what happens. The EIA said this is because of increases in demand.

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