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Canada AI Data Center Grid Integration aligns AI demand with renewable energy, energy storage, and grid reliability. It emphasizes transmission upgrades, liquid cooling efficiency, and policy incentives to balance economic growth with sustainable power.

Key Points

Linking AI data centers to Canada's grid with renewables, storage, and efficiency to ensure reliable, sustainable power.

✅ Diversify supply with wind, solar, hydro, and firm low-carbon resources

✅ Deploy grid-scale batteries to balance peaks and enhance reliability

✅ Upgrade transmission, distribution, and adopt liquid cooling efficiency

Artificial intelligence (AI) is revolutionizing various sectors, driving demand for data centers that support AI applications. In Canada, this surge in data center development presents both economic opportunities and challenges for the electricity grid, where utilities using AI to adapt to evolving demand dynamics. Integrating AI-focused data centers into Canada's electricity infrastructure requires strategic planning to balance economic growth with sustainable energy practices.​

Economic and Technological Incentives

Canada has been at the forefront of AI research for over three decades, establishing itself as a global leader in the field. The federal government has invested significantly in AI initiatives, with over $2 billion allocated in 2024 to maintain Canada's competitive edge and to align with a net-zero grid by 2050 target nationwide. Provincial governments are also actively courting data center investments, recognizing the economic and technological benefits these facilities bring. Data centers not only create jobs and stimulate local economies but also enhance technological infrastructure, supporting advancements in AI and related fields.​

Challenges to the Electricity Grid

However, the energy demands of AI data centers pose significant challenges to Canada's electricity grid, mirroring the power challenge for utilities seen in the U.S., as demand rises. The North American Electric Reliability Corporation (NERC) has raised concerns about the growing electricity consumption driven by AI, noting that the current power generation capacity may struggle to meet this increasing demand, while grids are increasingly exposed to harsh weather conditions that threaten reliability as well. This situation could lead to reliability issues, including potential blackouts during peak demand periods, jeopardizing both economic activities and the progress of AI initiatives.​

Strategic Integration Approaches

To effectively integrate AI data centers into Canada's electricity grids, a multifaceted approach is essential:

1. Diversifying Energy Sources: Relying solely on traditional energy sources may not suffice to meet the heightened demands of AI data centers. Incorporating renewable energy sources, such as wind, solar, and hydroelectric power, can provide sustainable alternatives. For instance, Alberta has emerged as a proactive player in supporting AI-enabled data centers, with the TransAlta data centre agreement expected to advance this momentum, leveraging its renewable energy potential to attract such investments.
    

2. Implementing Energy Storage Solutions: Integrating large-scale battery storage systems can help manage the intermittent nature of renewable energy. These systems store excess energy generated during low-demand periods, releasing it during peak times to stabilize the grid. In some communities, AI-driven grid upgrades complement storage deployments to optimize operations, which supports data center needs and community reliability.
    

3. Enhancing Grid Infrastructure: Upgrading transmission and distribution networks is crucial to handle the increased load from AI data centers. Strategic investments in grid infrastructure can prevent bottlenecks and ensure efficient energy delivery, including exploration of macrogrids in Canada to improve regional transfers, supporting both existing and new data center operations.​
    

4. Adopting Energy-Efficient Data Center Designs: Designing data centers with energy efficiency in mind can significantly reduce their power consumption. Innovations such as liquid cooling systems are being explored to manage the heat generated by high-density AI workloads, offering more efficient alternatives to traditional air cooling methods.

5. Establishing Collaborative Policies: Collaboration among government entities, utility providers, and data center operators is vital to align energy policies with technological advancements. Developing regulatory frameworks that incentivize sustainable practices can guide the growth of AI data centers in harmony with grid capabilities.​
    

Integrating AI data centers into Canada's electricity grids presents both significant opportunities and challenges. By adopting a comprehensive strategy that includes diversifying energy sources, implementing advanced energy storage, enhancing grid infrastructure, promoting energy-efficient designs, and fostering collaborative policies, Canada can harness the benefits of AI while ensuring a reliable and sustainable energy future. This balanced approach will position Canada as a leader in both AI innovation and sustainable energy practices.

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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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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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Canadian electricity transmission enables grid resilience, long-distance power trade, and decarbonization by integrating renewables, hydroelectric storage, and HVDC links, providing backup during extreme weather and lowering costs to reach net-zero, clean energy targets.

Key Points

An interprovincial high-voltage grid that shares clean power to deliver reliable, low-cost decarbonization.

✅ Enables resilience by sharing power across weather zones

✅ Integrates renewables with hydro storage via HVDC links

✅ Lowers decarbonization costs through interprovincial trade

As the recent disaster in Texas showed, climate change requires electricity utilities to prepare for extreme events. This “global weirding” is leaving Canadian electricity grids increasingly exposed to harsh weather that leads to more intense storms, higher wind speeds, heatwaves and droughts that can threaten the performance of electricity systems.

The electricity sector must adapt to this changing climate while also playing a central role in mitigating climate change. Greenhouse gas emissions can be reduced a number of ways, but the electricity sector is expected to play a central role in decarbonization, including powering a net-zero grid by 2050 across Canada. Zero-emissions electricity can be used to electrify transportation, heating and industry and help achieve emissions reduction in these sectors.

Enhancing long-distance transmission is viewed as a cost-effective way to enable a clean and reliable power grid, and to lower the cost of meeting our climate targets. Now is the time to strengthen transmission links in Canada, with concepts like a western Canadian electricity grid gaining traction.

Insurance for climate extremes
An early lesson from the Texas power outages is that extreme conditions can lead to failures across all forms of power supply. The state lost the capacity to generate electricity from natural gas, coal, nuclear and wind simultaneously. But it also lacked cross-border transmission to other electricity systems that could have bolstered supply.

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Long-distance transmission offers the opportunity to escape the correlative clutch of extreme weather, by accessing energy and spare capacity in areas not beset by the same weather patterns. For example, while Texas was in its deep freeze, relatively balmy conditions in California meant there was a surplus of electricity generation capability in that region — but no means to get it to Texas. Building new transmission lines and connections across broader regions, including projects like a hydropower line to New York that expand access, can act as an insurance policy, providing a back-up for regions hit by the crippling effects of climate change.

A transmission tower crumpled under the weight of ice.
The 1998 Quebec ice storm left 3.5 million Quebecers and a million Ontarians, as well as thousands in in New Brunswick, without power. CP Photo/Robert Galbraith
Transmission is also vulnerable to climate disruptions, such as crippling ice storms that leave wires temporarily inoperable. This may mean using stronger poles when building transmission, or burying major high-voltage transmission links, or deploying superconducting cables to reduce losses.

In any event, more transmission links between regions can improve resilience by co-ordinating supply across larger regions. Well-connected grids that are larger than the areas disrupted by weather systems can be more resilient to climate extremes.

Lowering the cost of clean power
Adding more transmission can also play a role in mitigating climate change. Numerous studies have found that building a larger transmission grid allows for greater shares of renewables onto the grid, ultimately lowering the overall cost of electricity.

In a recent study, two of us looked at the role transmission could play in lowering greenhouse gas emissions in Canada’s electricity sector. We found the cost of reducing greenhouse gas emissions is lower when new or enhanced transmission links can be built between provinces.

Average cost increase to electricity in Canada at different levels of decarbonization, with new transmission (black) and without new transmission (red). New transmission lowers the cost of reducing greenhouse gas emissions. (Authors), Author provided
Much of the value of transmission in these scenarios comes from linking high-quality wind and solar resources with flexible zero-emission generation that can produce electricity on demand. In Canada, our system is dominated by hydroelectricity, but most of this hydro capacity is located in five provinces: British Columbia, Manitoba, Ontario, Québec and Newfoundland and Labrador.

In the west, Alberta and Saskatchewan are great locations for building low-cost wind and solar farms. Enhanced interprovincial transmission would allow Alberta and Saskatchewan to build more variable wind and solar, with the assurance that they could receive backup power from B.C. and Manitoba when the wind isn’t blowing and the sun isn’t shining.

When wind and solar are plentiful, the flow of low cost energy can reverse to allow B.C. and Manitoba the opportunity to better manage their hydro reservoir levels. Provinces can only benefit from trading with each other if we have the infrastructure to make that trade possible.

A recent working paper examined the role that new transmission links could play in decarbonizing the B.C. and Alberta electricity systems. We again found that enabling greater electricity trade between B.C. and Alberta can reduce the cost of deep cuts to greenhouse gas emissions by billions of dollars a year. Although we focused on the value of the Site C project, in the context of B.C.'s clean energy shift, the analysis showed that new transmission would offer benefits of much greater value than a single hydroelectric project.

The value of enabling new transmission links between Alberta and B.C. as greenhouse gas emissions reductions are pursued. (Authors), Author provided
Getting transmission built
With the benefits that enhanced electricity transmission links can provide, one might think new projects would be a slam dunk. But there are barriers to getting projects built.

First, electricity grids in Canada are managed at the provincial level, most often by Crown corporations. Decisions by the Crowns are influenced not simply by economics, but also by political considerations. If a transmission project enables greater imports of electricity to Saskatchewan from Manitoba, it raises a flag about lost economic development opportunity within Saskatchewan. Successful transmission agreements need to ensure a two-way flow of benefits.

Second, transmission can be expensive. On this front, the Canadian government could open up the purse strings to fund new transmission links between provinces. It has already shown a willingness to do so.

Lastly, transmission lines are long linear projects, not unlike pipelines. Siting transmission lines can be contentious, even when they are delivering zero-emissions electricity. Using infrastructure corridors, such as existing railway right of ways or the proposed Canadian Northern Corridor, could help better facilitate co-operation between regions and reduce the risks of siting transmission lines.

If Canada can address these barriers to transmission, we should find ourselves in an advantageous position, where we are more resilient to climate extremes and have achieved a lower-cost, zero-emissions electricity grid.

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BC-Alberta Electricity Restrictions spotlight interprovincial energy tensions, limiting power exports and affecting grid reliability, energy sharing, and climate goals, while raising questions about federal-provincial coordination, smart grids, and storage investments.

Key Points

Policies limiting Alberta's power exports to provinces like BC, prioritizing local demand and affecting grid reliability.

✅ Prioritizes Alberta load over interprovincial power exports

✅ Risks to BC peak demand support and outage resilience

✅ Pressures for federal-provincial coordination and smart-grid investment

In a move that underscores the complexities of Canada's interprovincial energy relationships, the government of British Columbia (B.C.) has formally expressed concerns over recent electricity restrictions imposed by Alberta after it suspended electricity purchase talks with B.C., amid ongoing regional coordination challenges.

Background: Alberta's Electricity Restrictions

Alberta, traditionally reliant on coal and natural gas for electricity generation, has been undergoing a transition towards more sustainable energy sources as it pursues a path to clean electricity in the province.

In response, Alberta introduced restrictions on electricity exports, aiming to prioritize local consumption and stabilize its energy market and has proposed electricity market changes to address structural issues.

B.C.'s Position: Ensuring Energy Reliability and Cooperation

British Columbia, with its diverse energy portfolio and commitment to sustainability, has historically relied on the ability to import electricity from Alberta, especially during periods of high demand or unforeseen shortfalls. The recent restrictions threaten this reliability, prompting B.C.'s government to take action amid an electricity market reshuffle now underway.

B.C. officials have articulated that access to Alberta's electricity is crucial, particularly during outages or times when local generation does not meet demand. The ability to share electricity among provinces ensures a stable and resilient energy system, benefiting consumers and supporting economic activities, including critical minerals operations, that depend on consistent power supply.

Moreover, B.C. has expressed concerns that Alberta's restrictions could set a precedent that might affect future interprovincial energy agreements. Such a precedent could complicate collaborative efforts aimed at achieving national energy goals, including sustainability targets and infrastructure development.

Broader Implications: National Energy Strategy and Climate Goals

The dispute between B.C. and Alberta over electricity exports highlights the absence of a cohesive national energy strategy, as external pressures, including electricity exports at risk, add complexity. While provinces have jurisdiction over their energy resources, the interconnected nature of Canada's power grids necessitates coordinated policies that balance local priorities with national interests.

This situation also underscores the challenges Canada faces in meeting its climate objectives. Transitioning to renewable energy sources requires not only technological innovation but also collaborative policies that ensure energy reliability and affordability across provincial boundaries, as rising electricity prices in Alberta demonstrate.

Potential Path Forward: Dialogue and Negotiation

Addressing the concerns arising from Alberta's electricity restrictions requires a nuanced approach that considers the interests of all stakeholders. Open dialogue between provincial governments is essential to identify solutions that uphold the principles of energy reliability, economic cooperation, and environmental sustainability.

One potential avenue is the establishment of a federal-provincial task force dedicated to energy coordination. Such a body could facilitate discussions on resource sharing, infrastructure investments, and policy harmonization, aiming to prevent conflicts and promote mutual benefits.

Additionally, exploring technological solutions, such as smart grids and energy storage systems, could enhance the flexibility and resilience of interprovincial energy exchanges. Investments in these technologies may reduce the dependency on traditional export mechanisms, offering more dynamic and responsive energy management strategies.

The tensions between British Columbia and Alberta over electricity restrictions serve as a microcosm of the broader challenges facing Canada's energy sector. Balancing provincial autonomy with national interests, ensuring equitable access to energy resources, and achieving climate goals require collaborative efforts and innovative solutions. As the situation develops, stakeholders across the political, economic, and environmental spectrums will need to engage constructively, fostering a Canadian energy landscape that is resilient, sustainable, and inclusive.

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ERCOT Winter Capacity RFP seeks up to 3,000 MW through generation and demand response to bolster Texas grid reliability during peak load, leveraging Reliability Must-Run, incentive factors, and EEA risk mitigation for the 2023-24 season.

Key Points

An ERCOT initiative to procure 3,000 MW of generation and demand response to reduce EEA risk and improve reliability.

✅ Targets 3,000 MW from generation and demand response

✅ Uses RMR-style contracts with flexible incentive factors

✅ Aims to lower EEA probability below 10% this winter

The Electric Reliability Council of Texas (ERCOT) issued a request for proposals to stakeholders to procure up to 3,000 MW of generation or demand response capacity to meet load and reserve requirements during the winter 2023-24 peak load season (Dec. 1, 2023, through Feb. 29, 2024), amid ongoing Texas power grid challenges across the region.

ERCOT cited “several factors, including significant peak load growth since last winter, recent and proposed retirements of dispatchable Generation Resources, and recent extreme winter weather events, including Winter Storm Elliott in December 2022, Winter Storm Uri in February 2021, and the 2018 and 2011 winter storms, each of which resulted in abnormally high demand during winter weather.” It now seeks additional capacity under its “authority to prevent an anticipated Emergency Condition,” reflecting nationwide blackout risks identified by grid experts.

In its notice regarding the RFP, ERCOT identified a number of mothballed and recently decommissioned generation resources that may be eligible to offer capacity under the RFP. It further stated that offers must comport with the format of its “Reliability Must-Run” agreement but could include a proposed “Incentive Factor” that reflects the revenues the unit owners determine would be necessary to bring the unit back to operation. It added that the Incentive Factor is not necessarily limited to 10%. Providers of eligible demand response can submit offers based on similar principles that are not necessarily constrained by cost. The notice identifies potential acceptable sources of demand response, describes certain parameters for the kinds of demand response that are permitted to respond to the RFP, and outlines the time periods during which ERCOT must be able to deploy the demand response resources to improve electricity reliability across the system.

To meet the Dec. 1, 2023, service start date, ERCOT developed an aggressive timeline to solicit and evaluate proposals through the RFP. Responses to the RFP are due Nov. 6, 2023. ERCOT’s schedule provides that it will notify market participants that obtain awards on Nov. 23, 2023. Expect contracts to be executed by Nov. 30, 2023.

Unlike Regional Transmission Organizations in the Northeastern United States, ERCOT does not have a capacity market. Instead, ERCOT relies on a high price cap of $5,000 per MWh for its energy market (decreased from the $9,000 per MWh cap in effect during Winter Storm Uri) and an Operating Reserve Demand Curve adder that pays additional funds to generators supplying power and ancillary services, an area recently scrutinized for improper payments when supply conditions are tight. In the wake of Winter Storm Uri, some calls were made to have ERCOT adopt a capacity market for reliability reasons, and a number of legal battles continue to play out in the wake of Winter Storm Uri. (See recent McGuireWoods legal alert “Winter Storm Uri Power Dispute Reaches the Supreme Court of Texas.”) Though a capacity market was not adopted, the Texas Legislature approved a $7.2 billion loan program, widely described as an electricity market bailout for generators, to build up to 10,000 MW of dispatchable generation. The legislature also approved a version of the Public Utility Commission of Texas’ proposal to establish a “Performance Credit Mechanism,” but with a cost cap of $1 billion.

The loss of life and economic impacts of Winter Storm Uri in 2021, along with the energy crunches and calls for conservation this past summer, are driving changes to ERCOT’s “energy-only” market, including electricity market reforms under consideration. Texas policymakers are providing multiple financial incentives to promote investment in dispatchable on-demand generation, and voters will consider funding to modernize generation measures this year to make the Texas grid more reliable and able to deal with power demand from a growing economy and increased demand for electricity driven by weather. In the meantime, ERCOT’s plan to procure 3,000 MW through this RFP process is a stopgap measure intended to bolster reliability for the upcoming winter season and lower the probability of load shed in the event of severe winter weather.

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