Britain to shift to smart grid, meter systems

CO2 Tax for UK Offshore Energy Efficiency can accelerate adoption of aero-derivative gas turbines, flare gas recovery, and combined cycle power, reducing emissions on platforms like Equinor's Mariner and supporting net zero goals.

Key Points

A carbon price pushing operators to adopt efficient turbines, flare recovery, and combined cycle to cut emissions.

✅ Aero-derivative turbines beat industrial units on efficiency

✅ Flare gas recovery cuts routine flaring and fuel waste

✅ Combined cycle raises efficiency and lowers emissions

By Tom Baxter

The recent Energy Voice article from the Equinor chairman concerning the Mariner project heralding a ‘significant point of reference’ for growth highlighted the energy efficiency achievements associated with the platform.

I view energy efficiency as a key enabler to net zero, and alongside this the UK must start large-scale storage to meet system needs; it is a topic I have been involved with for many years.

As part of my energy efficiency work, I investigated Norwegian practices and compared them with the UK.

There were many differences, here are three;

1. Power for offshore installations is usually supplied from gas turbines burning fuel from the oil and gas processing plant, and even as the UK's offshore wind supply accelerates, installations convert that to electricity or couple the gas turbine to a machine such as a gas compressor.

There are two main generic types of gas turbine – aero-derivative and industrial. As the name implies aero-derivatives are aviation engines used in a static environment. Aero-derivative turbines are designed to be energy efficient as that is very import for the aviation industry.

Not so with industrial type gas turbines; they are typically 5-10% less efficient than a comparable aero-derivative.

Industrial machines do have some advantages – they can be cheaper, require less frequent maintenance, they have a wide fuel composition tolerance and they can be procured within a shorter time frame.

My comparison showed that aero-derivative machines prevailed in Norway because of the energy efficiency advantages – not the case in the UK where there are many more offshore industrial gas turbines.

Tom Baxter is visiting professor of chemical engineering at Strathclyde University and a retired technical director at Genesis Oil and Gas Consultants

2. Offshore gas flaring is probably the most obvious source of inefficient use of energy with consequent greenhouse gas emissions.

On UK installations gas is always flared due to the design of the oil and gas processing plant.

Though not a large quantity of gas, a continuous flow of gas is routinely sent to flare from some of the process plant.

In addition the flare requires pilot flames to be maintained burning at all times and, while Europe explores electricity storage in gas pipes, a purge of hydrocarbon gas is introduced into the pipes to prevent unsafe air ingress that could lead to an explosive mixture.

On many Norwegian installations the flare system is designed differently. Flare gas recovery systems are deployed which results in no flaring during continuous operations.

Flare gas recovery systems improve energy efficiency but they are costly and add additional operational complexity.

3. Returning to gas turbines, all UK offshore gas turbines are open cycle – gas is burned to produce energy and the very hot exhaust gases are vented to the atmosphere. Around 60 -70% of the energy is lost in the exhaust gases.

Some UK fields use this hot gas as a heat source for some of the oil and gas treatment operations hence improving energy efficiency.

There is another option for gas turbines that will significantly improve energy efficiency – combined cycle, and in parallel plans for nuclear power under the green industrial revolution aim to decarbonise supply.

Here the exhaust gases from an open cycle machine are taken to a separate turbine. This additional turbine utilises exhaust heat to produce steam with the steam used to drive a second turbine to generate supplementary electricity. It is the system used in most UK power stations, even as UK low-carbon generation stalled in 2019 across the grid.

Open cycle gas turbines are around 30 – 40% efficient whereas combined cycle turbines are typically 50 – 60%. Clearly deploying a combined cycle will result in a huge greenhouse gas saving.

I have worked on the development of many UK oil and gas fields and combined cycle has rarely been considered.

The reason being is that, despite the clear energy saving, they are too costly and complex to justify deploying offshore.

However that is not the case in Norway where combined cycle is used on Oseberg, Snorre and Eldfisk.

What makes the improved Norwegian energy efficiency practices different from the UK – the answer is clear; the Norwegian CO2 tax.

A tax that makes CO2 a significant part of offshore operating costs.

The consequence being that deploying energy efficient technology is much easier to justify in Norway when compared to the UK.

Do we need a CO2 tax in the UK to meet net zero – I am convinced we do. I am in good company. BP, Shell, ExxonMobil and Total are supporting a carbon tax.

Not without justification there has been much criticism of Labour’s recent oil tax plans, alongside proposals for state-owned electricity generation that aim to reshape the power market.

To my mind Labour’s laudable aims to tackle the Climate Emergency would be much better served by supporting a CO2 tax that complements the UK's coal-free energy record by strengthening renewable investment.

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New England Solar Interconnection Costs highlight distributed generation strains, transmission charges, distribution upgrades, and DAF fees as National Grid maps hosting capacity, driving queue delays and FERC disputes in Rhode Island and Massachusetts.

Key Points

Rising upfront grid upgrade and DAF charges for distributed solar in RI and MA, including some transmission costs.

✅ Upfront grid upgrades shifted to project developers

✅ DAF and transmission charges increase per MW costs

✅ Queue delays tied to hosting capacity and cluster studies

Solar developers in Rhode Island and Massachusetts say soaring charges to interconnect with the electric grid are threatening the viability of projects. 

As more large-scale solar projects line up for connections, developers are being charged upfront for the full cost of the infrastructure upgrades required, a long-common practice that they say is now becoming untenable amid debates over a new solar customer charge in Nova Scotia. 

“It is a huge issue that reflects an under-invested grid that is not ready for the volume of distributed generation that we’re seeing and that we need, particularly solar,” said Jeremy McDiarmid, vice president for policy and government affairs at the Northeast Clean Energy Council, a nonprofit business organization. 

Connecting solar and wind systems to the grid often requires upgrades to the distribution system to prevent problems, such as voltage fluctuations and reliability risks highlighted by Australian distributors in their networks. Costs can vary considerably from place to place, depending on the amount of distributed generation coming online and the level of capacity planning by regulators, said David Feldman, a senior financial analyst at the National Renewable Energy Laboratory.

“Certainly the Northeast often has more distribution challenges than much of the rest of the country just because it’s more populous and often the infrastructure is older,” he said. “But it’s not unique to the Northeast — in the Midwest, for example, there’s a significant amount of wind projects in the queues and significant delays.”

In Rhode Island and Massachusetts, where strong incentive programs are driving solar development, the level of solar coming online is “exposing the under-investment in the distribution system that is causing these massive costs that National Grid is assigning to particular projects or particular groups of projects,” McDiarmid said. “It is going to be a limiting factor for how much clean energy we can develop and bring online.”

Frank Epps, chief executive officer at Energy Development Partners, has been developing solar projects in Rhode Island since 2010. In that time, he said, interconnection charges on his projects have grown from about $80,000-$120,000 per megawatt to more than $400,000 per megawatt. He attributed the increase to a lack of investment in the distribution network by National Grid over the last decade.

He and other developers say the utility is now adding further to their costs by passing along not just the cost of improving the distribution system — the equivalent of the city street of the grid that brings power directly to customers — but also costs for modifying the transmission system — the interstate highway that moves bulk power over long distances to substations. 

Solar developers who are only requesting to hook into the distribution system, and not applying for transmission service, say they should not be charged for those additional upgrades under state interconnection rules unless they are properly authorized under the federal law that governs the transmission system. 

A Rhode Island solar and wind developer filed a complaint with the Federal Energy Regulatory Commission in February over transmission system improvement charges for its four proposed solar projects. Green Development said National Grid subsidiaries Narragansett Electric and New England Power Company want to charge the company more than $500,000 a year in operating and maintenance expenses assessed as so-called direct assignment facility charges. 

“This amount nearly doubles the interconnection costs associated with the projects,” which total 38.4 megawatts in North Smithfield, the company says in its complaint. “Crucially, these charges are linked to recovering costs associated with providing transmission service — even though no such transmission service is being provided to Green Development.”

But Ted Kresse, a spokesperson for National Grid, said the direct assignment facility, or DAF, construct has been in place for decades and has been applied to any customer affecting the need for transmission upgrades.

“It is the result of the high penetration and continued high volume of distributed generation interconnections that has recently prompted the need for transmission upgrades, and subsequently the pass-through of the associated DAF charges,” he said. 

Several complaints before the Rhode Island Public Utilities Commission object to these DAF and other transmission charges.

One petition for dispute resolution concerns four solar projects totaling 40 MW being developed by Energy Development Partners in a former gravel pit in North Kingstown. Brown University has agreed to purchase the power. 

The developer signed interconnection service agreements with Narragansett Electric in 2019 requiring payment of $21.6 million for costs associated with connecting the projects at a new Wickford Junction substation. Last summer, Narragansett sought to replace those agreements with new ones that reclassified a portion of the costs as transmission-level costs, through New England Power, National Grid’s transmission subsidiary.

That shift would result in additional operational and maintenance charges of $835,000 per year for the estimated 35-year life of the projects, the complaint says.

“This came as a complete shock to us,” Epps said. “We’re not just paying for the maintenance of a new substation. We are paying a share of the total cost that the system owner has to own and operate the transmission system. So all of the sudden, it makes it even tougher for distributed energy resources to be viable.”

In its response to the petition, National Grid argues that the charges are justified because the solar projects will require transmission-level upgrades at the new substation. The company argues that the developer should be responsible for the costs rather than ratepayers, “who are already supporting renewable energy development through their electric rates.”

Seth Handy, one of the lawyers representing Green Development in the FERC complaint, argues that putting transmission system costs on distribution assets is unfair because the distributed resources are “actually reducing the need to move electricity long distances. We’ve been fighting these fights a long time over the underestimating of the value of distributed energy in reducing system costs.”

Handy is also representing the Episcopal Diocese of Rhode Island before the state Supreme Court in its appeal of an April 2020 public utilities commission order upholding similar charges for a proposed 2.2-megawatt solar project at the diocese’s conference center and camp in Glocester. 

Todd Bianco, principal policy associate at the utilities commission, said neither he nor the chairperson can comment on the pending dockets contesting these charges. But he noted that some of these issues are under discussion in another docket examining National Grid’s standards for connecting distributed generation. Among the proposals being considered is the appointment of an independent ombudsperson to resolve interconnection disputes. 

Separately, legislation pending before the Rhode Island General Assembly would remove responsibility for administering the interconnection of renewable energy from utilities, and put it under the authority of the Rhode Island Infrastructure Bank, a financing agency.

Handy, who recently testified in support of the bill, said he believes National Grid has too many conflicting interests to administer interconnecting charges in a timely, transparent and fair fashion, and pointed to utility moves such as changes to solar compensation in other states as examples. In particular, he noted the company’s interests in expanding natural gas infrastructure. 

“There are all kinds of economic interests that they have that conflict with our state policy to provide lower-cost renewable energy and more secure energy solutions,” Handy said.

In testimony submitted to the House Committee on Corporations opposing the legislation, National Grid said such powers are well beyond the purpose and scope of the infrastructure bank. And it cited figures showing Rhode Island is third in the country for the most installed solar per square mile (behind New Jersey and Massachusetts).

Nadav Enbar, program manager at the Electric Power Research Institute, a nonprofit research organization for the utility industry, said interconnection delays and higher costs are becoming more common due to “the incredible uptake” in distributed renewable energy, particularly solar.

That’s impacting hosting capacity, the room available to connect all resources to a circuit without causing adverse harm to reliability and safety. 

“As hosting capacity is being reduced, it’s causing an increasing number of situations where utilities need to study their systems to guarantee interconnection without compromising their systems,” he said. “And that is the reason why you’re starting to see some delays, and it has translated into some greater costs because of the need for upgrades to infrastructure.”

The cost depends on the age or absence of infrastructure, projected load growth, the number of renewable energy projects in the queue, and other factors, he said. As utilities come under increasing pressure to meet state renewable goals, and as some states pilot incentives like a distributed energy rebate in Illinois to drive utility innovation, some (including National Grid) are beginning to provide hosting capacity maps that provide detailed information to developers and policymakers about the amount of distributed energy that can be accommodated at various locations on the grid, he said. 

In addition, the coming availability of high-tech “smart inverters” should help ease some of these problems because they provide the grid with more flexibility when it comes to connecting and communicating with distributed energy resources, Enbar said. 

In Massachusetts, the Department of Public Utilities has opened a docket to explore ways to better plan for and share the cost of upgrading distribution infrastructure to accommodate solar and other renewable energy sources as part of a grid overhaul for renewables nationwide. National Grid has been conducting “cluster studies” there that attempt to analyze the transmission impacts of a group of solar projects and the corresponding interconnection cost to each developer.

Kresse, of National Grid, said the company favors cost-sharing methodologies under consideration that would “provide a pathway to spread cost over the total enabled capacity from the upgrade, as opposed to spreading the cost over only those customers in the queue today.” 

Solar developers want regulators to take an even broader approach that factors in how the deployment of renewables and the resulting infrastructure upgrades benefit not just the interconnecting generator, but all customers. 

“Right now, if your project is the one that causes a multimillion-dollar upgrade, you are assigned that cost even though that upgrade is going to benefit a lot of other projects, as well as make the grid stronger,” said McDiarmid, of the clean energy council. “What we’re asking for is a way of allocating those costs among a variety of developers, as well as to the grid itself, meaning ratepayers. There’s a societal benefit to increasing the modernization of the grid, and improving the resilience of the grid.”

In the meantime, BlueHub Capital, a Boston-based solar developer focused on serving affordable housing developments, recently learned from National Grid that, as a part of one of the area studies, it will be required to pay $5.8 million in transmission and distribution upgrades to interconnect a 2-megawatt solar-plus-storage project that leverages cheaper batteries to enhance resilience, approved for a brownfield site in Gardner, Massachusetts. 

According to testimony submitted to the department, the sum is supposed to be paid within the next year, even though the project will have to wait to be interconnected until April 2027, when a new transmission line is completed. In addition, BlueHub will be responsible for DAF charges totaling $3.4 million over the 20-year life of the project. 

“We’re being asked to pay a fortune to provide solar that the state wants,” said DeWitt Jones, BlueHub’s president. “It’s so expensive that the upgrades are driving everyone out of the interconnection queue. The costs stay the same, but they fall on fewer projects. We need a process of grid design and modernization to guide this.”

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BC Hydro COVID-19 Relief offers electricity bill credits for laid-off workers and small business support, announced by Premier John Horgan, while FortisBC customers face deferrals and billing arrangements across Kelowna, Okanagan, and West Kootenay.

Key Points

BC Hydro COVID-19 Relief gives bill credits to laid-off residents; FortisBC offers deferrals and payment plans.

✅ Credit equals 3x average monthly bill for laid-off BC Hydro users

✅ Small businesses on BC Hydro get three months bill forgiveness

✅ FortisBC waives late fees, no disconnections, offers deferrals

On April 1, B.C. Premier John Horgan announced relief for BC Hydro customers who are facing bills after being laid-off during the economic shutdown due to the COVID-19 epidemic, while the utility also explores time-of-use rates to manage demand.

“Giving people relief on their power bills lets them focus on the essentials, while helping businesses and encouraging critical industry to keep operating,” he said.

BC Hydro residential customers in the province who have been laid off due to the pandemic will see a credit for three times their average monthly bill and, similar to Ontario's pandemic relief fund, small businesses forced to close will have power bills forgiven for three months.

But a large region of the province which gets its power from FortisBC will not have the same bail out.

FortisBC is the electricity provider to the tens of thousands who live and work in the Silmikameen Valley on Highway 3, the city of Kelowna, the Okanagan Valley south from Penticton, the Boundary region along the U.S. border. as well as West Kootenay communities.

“We want to make sure our customers are not worried about their FortisBC bill,” spokesperson Nicole Brown said.

FortisBC customers will still be on the hook for bills despite measures being taken to keep the lights on, even as winter disconnection pressures have been reported elsewhere.

Recent storm response by BC Hydro also highlights how crews have kept electricity service reliable during recent atypical events.

“We’ve adjusted our billing practices so we can do more,” she said. “We’ve discontinued our late fees for the time being and no customer will be disconnected for any financial reason.”

Brown said they will work one-on-one with customers to help find a billing arrangement that best suits their needs, aligning with disconnection moratoriums seen in other jurisdictions.

Those arrangement, she said, could include a “deferral, an equal payment plan or other billing options,” similar to FortisAlberta's precautions announced in Alberta.

Global News inquired with the Premier’s office why FortisBC customers were left out of Wednesday’s announcement and were deferred to the Ministry of Energy, Mines and Petroleum Resources.

The Ministry referred us back to FortisBC on the issue and offered no other comment, even as peak rates for self-isolating customers remained unchanged in parts of Ontario.

“We’re examining all options of how we can further help our customers and look forward to learning more about the program that BC Hydro is offering,” Brown said.

Disappointed FortisBC customers took to social media to vent about the disparity.

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Saamis Solar Park advances Medicine Hat's renewable energy strategy, as DP Energy secures AUC approval for North America's largest urban solar, repurposing contaminated land; capacity phased from 325 MW toward an initial 75 MW.

Key Points

A 325 MW solar project in Medicine Hat, Alberta, repurposing contaminated land; phased to 75 MW under city ownership.

✅ City acquisition scales capacity to 75 MW in phased build

✅ AUC approval enables construction and grid integration

✅ Reuses phosphogypsum-impacted land near fertilizer plant

DP Energy, an Irish renewable energy developer, has finalized the sale of the Saamis Solar Park—a 325 megawatt (MW) solar project—to the City of Medicine Hat in Alberta, Canada. This transaction marks the development of North America's largest urban solar initiative, while mirroring other Canadian clean-energy deals such as Canadian Solar project sales that signal market depth.

Project Development and Approval

DP Energy secured development rights for the Saamis Solar Park in 2017 and obtained a development permit in 2021. In 2024, the Alberta Utilities Commission (AUC) granted approval for construction and operation, reflecting Alberta's solar growth trends in recent years, paving the way for the project's advancement.

Strategic Acquisition by Medicine Hat

The City of Medicine Hat's acquisition of the Saamis Solar Park aligns with its commitment to enhancing renewable energy infrastructure. Initially, the project was slated for a 325 MW capacity, which would significantly bolster the city's energy supply. However, the city has proposed scaling the project to a 75 MW capacity, focusing on a phased development approach, and doing so amid challenges with solar expansion in Alberta that influence siting and timing. This adjustment aims to align the project's scale with the city's current energy needs and strategic objectives.

Utilization of Contaminated Land

An innovative aspect of the Saamis Solar Park is its location on a 1,600-acre site previously affected by industrial activity. The land, near Medicine Hat's fertilizer plant, was previously compromised by phosphogypsum—a byproduct of fertilizer production. DP Energy's decision to develop the solar park on this site exemplifies a productive reuse of contaminated land, transforming it into a source of clean energy.

Benefits to Medicine Hat

The development of the Saamis Solar Park is poised to deliver multiple benefits to Medicine Hat:

• Energy Supply Enhancement: The project will augment the city's energy grid, much like municipal solar projects that provide local power, providing a substantial portion of its electricity needs.

• Economic Advantages: The city anticipates financial savings by reducing carbon tax liabilities, as lower-cost solar contracts have shown competitiveness, through the generation of renewable energy.

• Environmental Impact: By investing in renewable energy, Medicine Hat aims to reduce its carbon footprint and contribute to global sustainability efforts.

DP Energy's Ongoing Commitment

Despite the sale, DP Energy maintains a strong presence in Canada, where Indigenous-led generation is expanding, with a diverse portfolio of renewable energy projects, including solar, onshore wind, storage, and offshore wind initiatives. The company continues to focus on sustainable development practices, striving to minimize environmental impact while maximizing energy production efficiency.

The transfer of the Saamis Solar Park to the City of Medicine Hat represents a significant milestone in renewable energy development. It showcases effective land reutilization, strategic urban planning, and a shared commitment to sustainable energy solutions, aligning with federal green electricity procurement that reinforces market demand. This project not only enhances the city's energy infrastructure but also sets a precedent for integrating large-scale renewable energy projects within urban environments.

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Enbridge Alberta CCS Project targets carbon capture and storage in Alberta, capturing emissions from industrial emitters to advance net-zero goals, leveraging carbon pricing, regulatory support, and a hub model despite a key partner's exit.

Key Points

A proposed Alberta carbon capture hub by Enbridge to store industrial emissions and support net-zero targets.

✅ Seeks emitters across power, oil and gas, and heavy industry

✅ Backed by carbon pricing, regulation, and net-zero mandates

✅ Faces high capex, storage risk, and anchor-tenant uncertainty

Enbridge Inc., a Canadian energy giant, is digging its heels in on its proposed carbon capture and storage (CCS) project in Alberta. This comes despite the recent withdrawal of Capital Power, a major potential emitter that was expected to utilize the CCS technology. Enbridge maintains the project remains viable, but questions linger about its future viability without a cornerstone anchor.

The CCS project, envisioned as a major carbon capture hub in Alberta, aimed to capture emissions from industrial facilities and permanently store them underground. This technology has the potential to play a significant role in reducing greenhouse gas emissions and mitigating the effects of climate change, alongside grid solutions like bridging the Alberta-B.C. electricity gap that can complement decarbonization efforts.

Capital Power's decision to shelve its $2.4 billion Genesee Generating Station project, which was designed to integrate with the CCS hub, threw a wrench into Enbridge's plans. The Genesee project was expected to be a key source of emissions for capture and storage, and its status is being weighed as Ottawa advances the federal coal plan to phase out unabated coal.

Enbridge, however, remains optimistic. The company cites ongoing discussions with other potential emitters interested in utilizing the CCS technology, amid new funding signals such as the U.S. DOE's $110M for CCUS that highlight momentum. They believe the project holds significant value despite Capital Power's departure.

"We are confident in the long-term viability of the project and continue to actively engage with potential customers," said Enbridge spokesperson Rachel Giroux. "Carbon capture and storage is a critical technology for achieving net-zero emissions, and we believe there is a strong business case for our CCS project."

Enbridge's confidence hinges on several factors. Firstly, they believe there is a growing appetite for CCS technology amongst industrial facilities facing increasing pressure to reduce their carbon footprint. Regulations and carbon pricing mechanisms, including new U.S. EPA power plant rules that test CCS readiness, could further incentivize companies to adopt CCS solutions.

Secondly, Enbridge highlights the potential for capturing emissions from not just power plants but also from other industrial sectors like oil and gas production and clean hydrogen projects in Canada, where reforming processes can generate CO2. This broader application could significantly increase the captured carbon volume and strengthen the project's economic viability.

However, skepticism remains. Critics point to the high upfront costs associated with CCS development and the nascent stage of the technology. They argue that without a guaranteed stream of captured emissions, the project might not be financially sound. Additionally, the long-term safety and effectiveness of large-scale carbon storage solutions remain under scrutiny.

The success of Enbridge's CCS project hinges on attracting new emitters. Replacing Capital Power's contribution will be a significant challenge. Enbridge will need to demonstrate the project's economic viability and navigate the complex regulatory landscape surrounding CCS technology.

The Alberta government's position on CCS is crucial. While the government has expressed support for the technology, the level of financial and regulatory incentives offered will significantly impact investor confidence, especially as the IEA net-zero outlook underscores Canada's need for much more electricity. A clear and stable policy framework will be essential for attracting emitters to the project.

The future of Enbridge's CCS project remains uncertain. Capital Power's withdrawal is a setback, but Enbridge's continued commitment suggests they believe the technology holds promise. Whether they can find enough emitters to justify the project's development will be a critical test. The outcome will have significant implications for the future of CCS technology in Alberta and Canada's broader efforts to achieve net-zero emissions, including Canada-Germany clean energy cooperation that seeks to scale low-carbon fuels.

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Ontario Pumped Storage advances as Ontario's largest energy storage project, delivering clean electricity, long-duration capacity, and grid reliability for peak demand, led by TC Energy and Saugeen Ojibway Nation, with IESO review underway.

Key Points

A long-duration storage project in Meaford storing clean power for peak demand, supporting Ontario's emission-free grid.

✅ Stores clean electricity to power 1M homes for 11 hours

✅ Partnership: TC Energy and Saugeen Ojibway Nation

✅ Pending IESO review and OEB regulation decisions

In a bid to accelerate the province's ambitions for clean economic growth, TC Energy Corporation has announced significant progress in the development of the Ontario Pumped Storage Project. The Government of Ontario in Canada has unveiled a plan to address growing energy needs as a sustainable road map aimed at achieving an emission-free electricity sector, and as part of this plan, the Ministry of Energy is set to undertake a final evaluation of the proposed Ontario Pumped Storage Project. A decision is expected to be reached by the end of the year.

Ontario Pumped Storage is a collaborative effort between TC Energy and the Saugeen Ojibway Nation. The project is designed to be Ontario's largest energy storage initiative, capable of storing clean electricity to power one million homes for 11 hours. As the province strives to transition to a cleaner electricity grid by embracing clean power across sectors, long duration storage solutions like Ontario Pumped Storage will play a pivotal role in providing reliable, emission-free power during peak demand periods.

The success of the Project hinges on the approval of TC Energy's board of directors and a fruitful partnership agreement with the Saugeen Ojibway Nation. TC Energy is aiming for a final investment decision in 2024, as Ontario confronts an electricity shortfall in the coming years, with the anticipated in-service date being in the early 2030s, pending regulatory and corporate approvals.

“Ontario Pumped Storage will be a critical component of Ontario’s growing clean economy and will deliver significant benefits and savings to consumers,” said Corey Hessen, Executive Vice-President and President, TC Energy, Power and Energy Solutions. “Ontario continues to attract major investments that will have large power needs — many of which are seeking zero-emission energy before they invest. We are pleased the government is advancing efforts to recognize the significant role that long duration storage plays — firming resources, including new gas plants under provincial consideration, will become increasingly valuable in supporting a future emission-free electricity system.” 

The Municipality of Meaford also expressed its support for the project, recognizing the positive impact it could have on the local economy and the overall electricity system of Ontario. Additionally, various stakeholders, including LiUNA OPDC, LiUNA Local 183, and the Ontario Chamber of Commerce, lauded the potential for job creation, training opportunities, and resilient energy infrastructure as Ontario seeks new wind and solar power to ease a coming electricity supply crunch.

The timeline for Ontario Pumped Storage's progress includes a final analysis by the Independent Electricity System Operator (IESO) to confirm its role in Ontario's electricity system and in balancing demand and emissions during the transition, to be completed by 30 September 2023. Concurrently, the Ministry of Energy will engage in consultations on the potential regulation of the Project via the Ontario Energy Board, while debates over clean, affordable electricity intensify ahead of the Ontario election, with a final determination scheduled for 30 November 2023.

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