Ottawa sets out to protect its hydro heritage


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Ottawa Hydro Substation Heritage Designation highlights Hydro Ottawa's 1920s architecture, Art Deco facades, and municipal utility history, protecting key voltage-reduction sites in Glebe, Carling-Merivale, Holland, King Edward, and Old Ottawa South.

 

Key Points

A city plan to protect Hydro Ottawa's 1920s substations for architecture, utility role, and civic electrical heritage.

✅ Protects five operating voltage-reduction sites citywide

✅ Recognizes Art Deco and early 20th century utility architecture

✅ Allows emergency demolition to ensure grid safety

 

The city of Ottawa is looking to designate five hydro substations built nearly a century ago as heritage structures, a move intended to protect the architectural history of Ottawa's earliest forays into the electricity business, even as Ottawa electricity consumption has shifted in recent years.

All five buildings are still used by Hydro Ottawa to reduce the voltage coming from transmission lines before the electricity is transmitted to homes and businesses, and when severe weather causes outages, Sudbury Hydro crews work to reconnect service across communities.

Electricity came to Ottawa in 1882 when two carbon lamps were installed on LeBreton Flats, heritage planner Anne Fitzpatrick told the city's built heritage subcommittee on Tuesday. It became a lucrative business, and soon a privately owned monopoly that drew public scrutiny similar to debates over retroactive charges in neighboring jurisdictions.

In 1905, city council held a special meeting to buy the electrical company, which led to a dramatic drop in electricity rates for residents, a contrast with recent discussions about peak hydro rates for self-isolating customers.

The substations are now owned by Hydro Ottawa, which agreed to the heritage designations on the condition it not be prevented from emergency demolitions if it needs to address incidents such as damaging storms in Ontario while it works to "preserve public safety and the continuity of critical hydro electrical services."

Built in 1922, the substation at the intersection of Glebe and Bronson avenues was the first to be built by the new municipal electrical department, long before modern battery storage projects became commonplace on Ontario's grid.

The largest of the substations being protected dates back to 1929 and is found at the corner of Carling Avenue and Merivale Road. It was built to accommodate a growing population in areas west of downtown including Hintonburg and Mechanicsville.

The substation on Holland Avenue near the Queensway is different from the others because it was built in 1924 to serve the Ottawa Electric Railway Company. The streetcar company operated from 1891 to 1959, and urban electrical infrastructure can face failures such as the Hydro-Québec manhole fire that left thousands without power.

This substation on King Edward Avenue was built in 1931 and designed by architect William Beattie, who also designed York Street Public School in Lowertown and the substation on Carling Avenue. 

The last substation to be built in a 'bold and decorative style' is at 39 Riverdale Ave. in Old Ottawa South, according to city staff. It was designed in an Art Deco style by prominent architect J. Albert Ewart, who was also behind the Civic Hospital and nearby Southminster Church on Bank Street.

 

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Duke Energy Florida to build its largest battery storage projects yet

Duke Energy Florida battery storage will add 22 MW across Trenton, Cape San Blas and Jennings, improving grid reliability, outage resilience, enabling peak shaving and deferring distribution upgrades to increase efficiency and customer value.

 

Key Points

Three lithium battery projects totaling 22 MW to improve Florida grid reliability, outage resilience and efficiency.

✅ 22 MW across Trenton, Cape San Blas and Jennings sites

✅ Enhances outage resilience and grid reliability

✅ Defers costly distribution upgrades and improves efficiency

 

Duke Energy Florida (DEF) has announced three battery energy storage projects, totaling 22 megawatts, that will improve overall reliability and support critical services during power outages.

Duke Energy, the nation's largest electric utility, unveils its new logo. (PRNewsFoto/Duke Energy) (PRNewsfoto/Duke Energy)

Collectively, the storage facilities will enhance grid operations, increase efficiencies and improve overall reliability for surrounding communities, with virtual power plant programs offering a model for coordinating distributed resources.

They will also provide important backup generation during power outages, a service that is becoming increasingly important with the number and intensity of storms that have recently impacted the state.

As the grid manager and operator, DEF can maximize the versatility of battery energy storage systems (BESS) to include multiple customer and electric system benefits such as balancing energy demand, managing intermittent resources, increasing energy security and deferring traditional power grid upgrades.

These benefits help reduce costs for customers and increase operational efficiencies.

The 11-megawatt (MW) Trenton lithium-based battery facility will be located 30 miles west of Gainesville in Gilchrist County. The energy storage project will continue to improve power reliability using newer technologies.

The 5.5-MW Cape San Blas lithium-based battery facility will be located approximately 40 miles southeast of Panama City in Gulf County. The project will provide additional power capacity to meet our customers' rising energy demand in the area. This project is an economical alternative to replacing distribution equipment necessary to accommodate local load growth.

The 5.5-MW Jennings lithium-based battery facility will be located 1.5 miles south of the Florida-Georgia border in Hamilton County. The project will continue to improve power reliability through energy storage as an alternative solution to installing new and more costly distribution equipment.

Currently the company plans to complete all three projects by the end of 2020.

"These battery projects provide electric system benefits that will help improve local reliability for our customers and provide significant energy services to the power grid," said Catherine Stempien, Duke Energy Florida state president. "Duke Energy Florida will continue to identify opportunities in battery storage technology which will deliver efficiency improvements to our customers."

 

Additional renewables projects

As part of DEF's commitment to renewables, the company is investing an estimated $1 billion to construct or acquire a total of 700 MW of cost-effective solar power facilities and 50 MW of battery storage through 2022.

Duke Energy is leading the industry deployment of battery technology, with SDG&E's Emerald Storage project underscoring broader adoption across the sector today. Last fall, the company and University of South Florida St. Petersburg unveiled a Tesla battery storage system that is connected to a 100-kilowatt (kW) solar array – the first of its kind in Florida.

This solar-battery microgrid system manages the energy captured by the solar array, situated on top of the university's parking garage, and similar low-income housing microgrid financing efforts are expanding access. The solar array was constructed three years ago through a $1 million grant from Duke Energy. The microgrid provides a backup power source during a power outage for the parking garage elevator, lights and electric vehicle charging stations. Click here to learn more.

In addition to expanding its battery storage technology and solar investments, DEF is investing in transportation electrification to support the growing U.S. adoption of electric vehicles (EV), including EV charging infrastructure, 530 EV charging stations and a modernized power grid to deliver the diverse and reliable energy solutions customers want and need.

 

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Hydro-Quebec adopts a corporate structure designed to optimize the energy transition

Hydro-Québec Unified Corporate Structure advances the energy transition through integrated planning, strategy, infrastructure delivery, and customer operations, aligning generation, transmission, and distribution while ensuring non-discriminatory grid access and agile governance across assets and behind-the-meter technologies.

 

Key Points

A cross-functional model aligning strategy, planning, and operations to accelerate Quebec's low-carbon transition.

✅ Four groups: strategy, planning, infrastructure, operations.

✅ Ensures non-discriminatory transmission access compliance.

✅ No staff reductions; staged implementation from Feb 28.

 

As Hydro-Que9bec prepares to play a key role in the transition to a low-carbon economy, the complexity of the work to be done in the coming decade requires that it develop a global vision of its operations and assets, from the drop of water entering its turbines to the behind-the-meter technologies marketed by its subsidiary Hilo. This has prompted the company to implement a new corporate structure that will maximize cooperation and agility, including employee-led pandemic support that builds community trust, making it possible to bring about the energy transition efficiently with a view to supporting the realization of Quebecers’ collective aspirations.

Toward a single, unified Hydro

Hydro-Québec’s core mission revolves around four major functions that make up the company’s value chain, alongside policy choices like peak-rate relief during emergencies. These functions consist of:

  1. Developing corporate strategies based on current and future challenges and business opportunities
  2. Planning energy needs and effectively allocating financial capital, factoring in pandemic-related revenue impacts on demand and investment timing
  3. Designing and building the energy system’s multiple components
  4. Operating assets in an integrated fashion and providing the best customer experience by addressing customer choice and flexibility expectations across segments.

Accordingly, Hydro-Québec will henceforth comprise four groups respectively in charge of strategy and development; integrated energy needs planning; infrastructure and the energy system; and operations and customer experience, including billing accuracy concerns that can influence satisfaction. To enable the company to carry out its mission, these groups will be able to count on the support of other groups responsible for corporate functions.

Across Canada, leadership changes at other utilities highlight the need to rebuild ties with governments and investors, as seen with Hydro One's new CEO in Ontario.

“For over 20 years, Hydro-Québec has been operating in a vertical structure based on its main activities, namely power generation, transmission and distribution. This approach must now give way to one that provides a cross-functional perspective allowing us to take informed decisions in light of all our needs, as well as those of our customers and the society we have the privilege to serve,” explained Hydro-Québec’s President and Chief Executive Officer, Sophie Brochu.

In terms of gender parity, the management team continues to include several men and women, thus ensuring a diversity of viewpoints.

Hydro-Québec’s new structure complies with the regulatory requirements of the North American power markets, in particular with regard to the need to provide third parties with non-discriminatory access to the company’s transmission system. The frameworks in place ensure that certain functions remain separate and help coordinate responses to operational events such as urban distribution outages that challenge continuity of service.

These changes, which will be implemented gradually as of Monday, February 28, do not aim to achieve any staff reductions.

 

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Manitoba Government Extends Pause on New Cryptocurrency Connections

Manitoba Crypto Mining Electricity Pause signals a moratorium to manage grid strain, Manitoba Hydro capacity, infrastructure costs, and electricity rates, while policymakers evaluate sustainable energy demand, and planning for data centers and blockchain operations.

 

Key Points

A temporary halt on mining power hookups in Manitoba to assess grid impacts, protect rates, and plan sustainable use.

✅ Applies only to new service requests; existing sites unaffected

✅ Addresses grid strain, infrastructure costs, electricity rates

✅ Enables review with Manitoba Hydro for sustainable policy

 

The Manitoba government has temporarily suspended approving new electricity service connections for cryptocurrency mining operations, a step similar to BC Hydro's suspension seen in a neighboring province.


The Original Pause

The pause was initially imposed in November 2022 due to concerns that the rapid influx of cryptocurrency mining operations could place significant strain on the province's electrical grid. Manitoba Hydro, the province's primary electric utility, which has also faced legal scrutiny in the Sycamore Energy lawsuit, warned that unregulated expansion of the industry could necessitate billions of dollars in infrastructure investments, potentially driving up electricity rates for Manitobans.


The Extended Pause Offers Time for Review

The extension of the pause is meant to provide the government and Manitoba Hydro with more time to assess the situation thoroughly and develop a long-term solution addressing the challenges and opportunities presented by cryptocurrency mining, including evaluating emerging options such as modular nuclear reactors that other jurisdictions are studying. The government has stated its commitment to ensuring that the long-term impacts of the industry are understood and don't unintentionally harm other electricity customers.


What Does the Pause Mean?

The pause does not affect existing cryptocurrency operations but prevents the establishment of new ones.  It applies specifically to requests for electricity service that haven't yet resulted in agreements to construct infrastructure or supply electricity, and it comes amid regional policy shifts like Alberta ending its renewable moratorium that also affect grid planning.


Concerns About Energy Demands

Cryptocurrency mining involves running high-powered computers around the clock to solve complex mathematical problems. This process is incredibly energy-intensive. Globally, the energy consumption of cryptocurrency networks has drawn scrutiny for its environmental impact, with examples such as Iceland's mining power use illustrating the scale. In Manitoba, concern focuses on potentially straining the electrical grid and making it difficult for Manitoba Hydro to plan for future growth.


Other Jurisdictions Taking Similar Steps

Manitoba is not alone in its cautionary approach to cryptocurrency mining. Several other regions and utilities have implemented restrictions or are exploring limitations on how cryptocurrency miners can access electricity, including moves by Russia to ban mining amid power deficits. This reflects a growing awareness among policymakers about the potentially destabilizing impact this industry could have on power grids and electricity markets.


Finding a Sustainable Path Forward

Manitoba Hydro has stated that it is open to working with cryptocurrency operations but emphasizes the need to do so in a way that protects existing ratepayers and ensures a stable and reliable electricity system for all Manitobans, while recognizing market uncertainties highlighted by Alberta wind project challenges in a neighboring province. The government's extension of the pause signifies its intention to find a responsible path forward, balancing the potential for economic development with the necessity of safeguarding the province's power supply.

 

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Group to create Canadian cyber standards for electricity sector IoT devices

Canadian Industrial IoT Cybersecurity Standards aim to unify device security for utilities, smart grids, SCADA, and OT systems, aligning with NERC CIP, enabling certification, trust marks, compliance testing, and safer energy sector deployments.

 

Key Points

National standards to secure industrial IoT for utilities and grids, enabling certification and NERC CIP alignment.

✅ Aligns with NERC CIP and NIST frameworks for energy sector security

✅ Defines certification, testing tools, and a trusted device repository

✅ Enhances OT, SCADA, and smart grid resilience against cyber threats

 

The Canadian energy sector has been buying Internet-connected sensors for monitoring a range of activities in generating plants, distribution networks facing harsh weather risks and home smart meters for several years. However, so far industrial IoT device makers have been creating their own security standards for devices, leaving energy producers and utilities at their mercy.

The industry hopes to change that by creating national cybersecurity standards for industrial IoT devices, with the goal of improving its ability to predict, prevent, respond to and recover from cyber threats, such as emerging ransomware attacks across the grid.

To help, the federal government today announced an $818,000 grant support a CIO Strategy Council project oversee the setting of standards.

In an interview council executive director Keith Jansa said the money will help a three-year effort that will include holding a set of cross-country meetings with industry, government, academics and interest groups to create the standards, tools to be able to test devices against the standards and the development of product repository of IoT safe devices companies can consult before making purchases.

“The challenge is there are a number of these devices that will be coming online over the next few years,” Jansa said. “IoT devices are designed for convenience and not for security, so how do you ensure that a technology an electricity utility secures is in fact safeguarded against cyber threats? Currently, there is no associated trust mark or certification that gives confidence associated with these devices.”

He also said the council will work with the North American Electric Reliability Corporation (NERC), which sets North American-wide utility safety procedural standards and informs efforts on protecting the power grid across jurisdictions. The industrial IoT standards will be product standards.

According to Robert Wong, vice-president and CIO of Toronto Hydro, all the big provincial utilities are subject to adhering to NERC CIP standards which have requirements for both cyber and physical security. Ontario is different from most provinces in that it has local distribution companies — like Toronto Hydro — which buy electricity in bulk and resell it to customers.  These LDCs don’t own or operate critical infrastructure and therefore don’t have to follow the NERC CIP standards.

Regional reforms, such as regulatory changes in Atlantic Canada, aim to bring greener power options to the grid.

Electricity is considered around the world as one of a country’s critical national infrastructure. Threats to the grid can be used for ransom or by a country for political pressure. Ukraine had its power network knocked offline in 2015 and 2016 by what were believed to be Russian-linked attackers operating against utilities.

All the big provincial utilities operate “critical infrastructure” and are subject to adhering to NERC CIP (critical infrastructure protection) standards, which have requirements for both cyber and physical security, as similar compromises at U.S. electric utilities have highlighted recently.  There are audited on a regular basis for compliance and can face hefty fines if they fail to meet the requirements.  The LDCs in Ontario don’t own or operate “critical infrastructure” and therefore are not required to adopt NERC CIP standards (at least for now).

The CIO Strategy Council is a forum for chief information officers that is helping set standards in a number of areas. In January it announced a partnership with the Internet Society’s Canada Chapter to create standards of practice for IoT security for consumer devices. As part of the federal government’s updated national cybersecurity strategy it is also developing a national cybersecurity standard for small and medium-sized businesses. That strategy would allow SMBs to advertise to customers that they meet minimum security requirements.

“The security of Canadians and our critical infrastructure is paramount,” federal minister of natural resources Seamus O’Regan said in a statement with today’s announcement. “Cyber attacks are becoming more common and dangerous. That’s why we are supporting this innovative project to protect the Canadian electricity sector.”

The announcement was welcomed by Robert Wong, Toronto Hydro’s vice-president and CIO. “Any additional investment towards strengthening the safeguards against cyberattacks to Canada’s critical infrastructure is definitely good news.  From the perspective of the electricity sector, the convergence of IT and OT (operational technology) has been happening for some time now as the traditional electricity grid has been transforming into a Smart Grid with the introduction of smart meters, SCADA systems, electronic sensors and monitors, smart relays, intelligent automated switching capabilities, distributed energy resources, and storage technologies (batteries, flywheels, compressed air, etc.).

“In my experience, many OT device and system manufacturers and vendors are still lagging the traditional IT vendors in incorporating Security by Design philosophies and effective security features into their products.  This, in turn, creates greater risks and challenges for utilities to protecting their critical infrastructures and ensuring a reliable supply of electricity to its customers.”

The Ontario Energy Board, which regulates the industry in the province, has led an initiative for all utilities to adopt the National Institute of Standards and Technology (NIST) Cybersecurity Framework, along with the ES-C2M2 maturity and Privacy By Design models, he noted.  Toronto Hydro has been managing its cybersecurity practice in adherence to these standards, as the city addresses growing electricity needs as well, he said.

“Other jurisdictions, such as Israel, have invested heavily on a national level in developing its cybersecurity capabilities and are seen as global leaders.  I am confident that given the availability of talent, capabilities and resources in Canada (especially around the GTA) if we get strong support and leadership at a federal level we can also emerge as a leader in this area as well.”

 

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Electricity exports to New York from Quebec will happen as early as 2025: Hydro-Quebec

Hertel-New York Interconnection delivers Hydro-Quebec renewable energy via a cross-border transmission line to New York City by 2025, supplying 1,250 MW through underground and underwater routes under a 25-year contract.

 

Key Points

A cross-border line delivering 1,250 MW of Hydro-Quebec hydropower to New York City via underground routes.

✅ 1,250 MW clean power to NYC by 2025

✅ 56.1 km underground, 1.6 km underwater in Quebec

✅ 25-year contract; Mohawk partnership revenue

 

Hydro-Quebec announced Thursday it has chosen the route for the Hertel-New York interconnection line, which will begin construction in the spring of 2023 in Quebec.

The project will deliver 1,250 megawatts of Quebec hydroelectricity to New York City starting in 2025, even as a recent electricity shortage report warns about rising demand at home.

It's a 25-year contract for Hydro-Quebec, the largest export contract for the province-owned company, and comes as hydrogen production investments gain traction in Eastern Canada.

The Crown corporation has not disclosed potential revenues from the project, but Premier François Legault mentioned on social media last September that a deal in principle worth more than $20 billion over 25 years was in the works.

The route includes a 56.1-kilometre underground and a 1.6-kilometre underwater section, similar to the Lake Erie Connector project planned under Lake Erie.

Eight municipalities in the Montérégie region will be affected: La Prairie, Saint-Philippe, Saint-Jacques-le-Mineur, Saint-Édouard, Saint-Patrice-de-Sherrington, Saint-Cyprien-de-Napierville, Saint-Bernard-de-Lacolle and Lacolle.

Across the country, new renewables such as wind projects in Yukon are receiving federal support, reflecting broader grid decarbonization.

The last part of the route will run along Fairbanks Creek to the Richelieu River, where it will connect with the American network.

Further south, there will be a 545-kilometre link between the Canada-U.S. border and New York City, while a separate Maine transmission approval advances a New England pathway for Quebec power.

Hydro-Quebec is holding two consultations on the project, on Dec. 8 in Lacolle and Dec. 9 in Saint-Jacques-le-Mineur.

Elsewhere in Atlantic Canada, EV-to-grid integration pilots are underway to test how vehicles can support the power system.

Once the route is in service, the Quebec line will be subject to a partnership between Hydro-Quebec and the Mohawk Council of Kahnawake, which will benefit from economic remunerations for 40 years.

To enhance reliability, grid-scale battery storage projects are also expanding in Ontario.

 

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Annual U.S. coal-fired electricity generation will increase for the first time since 2014

U.S. coal-fired generation 2021 rose as higher natural gas prices, stable coal costs, and a recovering power sector shifted the generation mix; capacity factors rebounded despite low coal stocks and ongoing plant retirements.

 

Key Points

Coal output rose 22% on high gas prices and higher capacity factors; a 5% decline is expected in 2022.

✅ Natural gas delivered cost averaged $4.93/MMBtu, more than double 2020

✅ Coal capacity factor rose to ~51% from 40% in 2020

✅ 2022 coal generation forecast to fall about 5%

 

We expect 22% more U.S. coal-fired generation in 2021 than in 2020, according to our latest Short-Term Energy Outlook (STEO). The U.S. electric power sector has been generating more electricity from coal-fired power plants this year as a result of significantly higher natural gas prices and relatively stable coal prices, even as non-fossil sources reached 40% of total generation. This year, 2021, will yield the first year-over-year increase in coal generation in the United States since 2014, highlighted by a January power generation jump earlier in the year.

Coal and natural gas have been the two largest sources of electricity generation in the United States. In many areas of the country, these two fuels compete to supply electricity based on their relative costs and sensitivity to policies and gas prices as well. U.S. natural gas prices have been more volatile than coal prices, so the cost of natural gas often determines the relative share of generation provided by natural gas and coal.

Because natural gas-fired power plants convert fuel to electricity more efficiently than coal-fired plants, record natural gas generation has at times underscored that advantage, and natural gas-fired generation can have an economic advantage even if natural gas prices are slightly higher than coal prices. Between 2015 and 2020, the cost of natural gas delivered to electric generators remained relatively low and stable. This year, however, natural gas prices have been much higher than in recent years. The year-to-date delivered cost of natural gas to U.S. power plants has averaged $4.93 per million British thermal units (Btu), more than double last year’s price.

The overall decline in electricity demand in 2020 and record-low natural gas prices led coal plants to significantly reduce the percentage of time that they generated power. In 2020, the utilization rate (known as the capacity factor) of U.S. coal-fired generators averaged 40%. Before 2010, coal capacity factors routinely averaged 70% or more. This year’s higher natural gas prices have increased the average coal capacity factor to about 51%, which is almost the 2018 average, a year when wind and solar reached 10% nationally.

Although rising natural gas prices have resulted in more U.S. coal-fired generation than last year, this increase in coal generation will most likely not continue as solar and wind expand in the generation mix. The electric power sector has retired about 30% of its generating capacity at coal plants since 2010, and no new coal-fired capacity has come online in the United States since 2013. In addition, coal stocks at U.S. power plants are relatively low, and production at operating coal mines has not been increasing as rapidly as the recent increase in coal demand. For 2022, we forecast that U.S. coal-fired generation will decline about 5% in response to continuing retirements of generating capacity at coal power plants and slightly lower natural gas prices.

 

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