IPPSA Intelligence

Alberta Electric System Operator 

The 2025 Annual Market Statistics report and Financial Transmission Rights session materials offer insights into market trends and risk hedging, with feedback deadlines in late March. ENGIE’s cancellation of its Buffalo Trail North Wind Project transmission access triggers a formal AUC revocation of the Needs Identification Document, reshaping regional renewable interconnection prospects. 

Administrative amendments to ISO Section 501.3 and multi‐stage Reliability Standards Sync‐Up consultations for medium and high‐complexity standards are open for feedback through mid‐May, complemented by an April workshop to refine alignment priorities. 

A WECC survey invites stakeholder input on reliability discussions until March 20. In tariff design, AESO will release a longlist of Internal Demand Rate options mid‐March, soliciting detailed proposals before a first workshop in early April. 

These initiatives may recalibrate compliance protocols, rate structures, and investment strategies for generators, utilities, and large consumers. Market participants should review published reports, submit timely comments on rule amendments and standard synchronization, and prepare rate design proposals to influence evolving tariff frameworks. 

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AUC rejects Synapse's 1.4 GW Olds gas-fired plant application

Regulatory review in Alberta led the Utilities Commission to close Synapse Real Estate Corp.’s 1.4-gigawatt natural gas-fired power plant proposal for an Olds data centre owing to significant informational and procedural shortcomings. The Commission highlighted errors, omissions and inconsistencies across technical documents, incomplete environmental field studies, a noise impact assessment that omitted scenarios with multiple backup generators, and absence of a reclamation security plan for a facility slated to operate over a century.

Synapse’s public consultation program was deemed inadequate: materials failed to disclose plans for 600 diesel generators and a formal record of community concerns and mitigation measures was missing. While the Commission did not assess the project’s merits, it recommended a fresh, complete filing rather than piecemeal fixes. The Town of Olds expressed support for responsible development and endorsed the regulator’s thorough process. In response, Synapse launched an online “We Are Listening” portal covering noise, emissions and water impacts, with further details promised.

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Big Marble Farms to export 12 MW of cogeneration power to Medicine Hat

Big Marble Farms' new interconnection lets the greenhouse sell surplus power from its 12 MW natural-gas combined heat-and-power system to the City of Medicine Hat, formalized at a March 12, 2026 ribbon-cutting. The farm expanded generation after outgrowing grid capacity—its facility can draw up to 28 MW during winter lighting peaks—so on-site cogeneration supplies heat and electricity while capturing waste heat for greenhouse heating.

A 2024 Alberta law enabling self-support and electricity export unlocked the deal, followed by years of municipal bylaw updates and physical interconnection work. Allowing exports reduces start–stop cycling, improving equipment life and thermal efficiency, and creates a market for seasonal or off-peak surplus.

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Alberta Proposes Second High‑Voltage Intertie with B.C. and a National Multi‑Use Energy Corridor

Alberta plans a second high-voltage transmission intertie with northern British Columbia and is exploring extensions toward Yukon and the Northwest Territories as part of a broader push to deepen interprovincial electricity links. The proposal aims to pair B.C.’s dispatchable hydro “battery” with Alberta’s growing wind, solar and flexible gas fleet to smooth renewable variability, shift power across time zones, and increase trade and reliability. Alberta’s existing B.C. link has a theoretical 1,200 MW capacity but is practically limited to about 400 MW; a second line would add redundancy and usable capacity.

Stronger northern transmission could power mining and industrial development, reduce diesel use in remote communities, and qualify for federal nation‑building support. Estimated capital costs range from roughly $2 billion to $3 billion, prompting discussions on cost‑sharing with B.C. and Ottawa. Officials envision a multi‑use national corridor that bundles transmission, pipelines and transport infrastructure to reduce permitting frictions.

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AltaLink proposes rebuilding Canmore–Banff 138 kV line

AltaLink proposes rebuilding the 54L 138 kV transmission line between Canmore and Banff because the 1941 infrastructure has reached end of life and supplies Banff, Sunshine Ski Area and Lake Louise. Planned measures include a temporary supply line during construction, potential relocation of about 1 km in Canmore to accommodate development, undergrounding two segments near Harvie Heights and Elk Run Boulevard, and removal of hazardous trees to reduce outages and fire risk.

Parks Canada directed a detailed impact assessment (draft under review) and AltaLink will submit a facility application to the Alberta Utilities Commission, triggering a public AUC review; construction could begin in 2027 if approved.

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Federal Indigenous Loan Guarantee Funds First Nations' 20% Stake in Ontario Transmission Line

Canada’s federal Indigenous Loan Guarantee Program (CILGP) is financing a 20% equity stake for Aamjiwnaang and Kettle and Stony Point First Nations in the 49-km Chatham-Lakeshore transmission line in Ontario, a roughly $237-million project that adds about 400 MW and provides a low‑risk 50‑year revenue stream without tapping community funds. It follows CILGP’s initial deal last year enabling 36 B.C. First Nations to take 12.5% of an Enbridge pipeline, Ottawa has doubled program capital to $10 billion, signalling more transactions ahead.

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Alberta Joins Interprovincial Partnership to Strengthen Transmission Interties

Alberta’s decision to join a first‑of‑its‑kind interprovincial-territorial Partnership Agreement on Transmission Interties establishes a cooperative framework to reduce barriers between power grids, modernize transmission, and expand electricity trade across Canada while preserving provincial control. Participating jurisdictions—BC, Saskatchewan, Manitoba, Ontario, New Brunswick, Nova Scotia, PEI, Yukon and Northwest Territories—agree to meet at least twice yearly during an initial eight‑year term to improve planning, information‑sharing, and coordination on intertie projects.

The partnership emphasizes Indigenous engagement as meaningful partners, seeks federal support to lower regulatory hurdles, and aims to attract investment, boost jobs, and enhance resilience and flexibility to manage peak demand and emergencies. Alberta, already a net exporter since 2024 with existing interties to BC, Saskatchewan and the privately owned Montana–Alberta line, stands to deepen trade and reliability benefits.

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Calgary mayor suggests Enmax run city water, proposes selling Versant Power to fund infrastructure

Calgary’s mayor has proposed exploring whether Enmax, the city-owned electricity utility, could take over municipal water services and suggested selling Enmax’s U.S. utility, Versant Power, to help fund urgent water infrastructure such as the Bearspaw feeder main replacement. The idea echoes Edmonton’s Epcor model and follows a review panel recommendation to create a standalone municipal water corporation after the Bearspaw failure.

Enmax says water aligns with its growth strategy and welcomed discussions but resisted being compelled to divest Versant, which it views as a long-term, stabilizing asset acquired for about $1.8 billion. Councillors are divided: some support using Enmax to avoid costs and tax or rate shocks from creating a new company and favor exploring a Versant sale to raise cash; others prefer keeping water under direct city administration or retaining Versant’s revenue stream.

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Alberta–Montana electricity dispute eases

Months of cross-border tension over whether Alberta’s electricity rules and rapid supply changes unfairly block Montana power have shifted toward pragmatic engagement. Alberta’s coal phase-out and rapid build-out of thousands of megawatts of wind and solar transformed it from a net importer into an exporter, altering flows and prompting U.S. scrutiny and Montana political complaints. Direct talks between Alberta utilities minister Nathan Neudorf and Montana state senator Daniel Zolnikov moved discussions forward after initial friction, with both calling negotiations productive.

Policy and technical responses include a Canada-wide intertie initiative led by Ontario to coordinate transmission expansion, and a large Alberta system-operator procurement for services such as fast frequency response to stabilize a variable grid. Analysts warn Alberta has been too isolated and needs more interconnections and adaptation time; Montana’s Zolnikov now sees procurement and interprovincial cooperation as a potential “win‑win.”

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Calgary water restrictions: why AI data centres aren’t the main cause

Calgary’s recent water restrictions were driven by failure of the Bearspaw south feeder main, not current AI data centres, which municipal meter data and the Canada Energy Regulator show are relatively small water users. Residents consume >60% of city water and businesses ~30%; data centres aren’t among top consumers. The city set a 500-million-litre daily benchmark to avoid treatment-plant overload, low pressure, boil-water advisories and firefighting risk; initial days’ consumption hovered just below that. Larger proposed AI projects face provincial Water Act review; several high‑profile proposals have been rejected or remain under scrutiny.

Siting constraints matter: southern Alberta basins (Bow, Oldman, South Saskatchewan) are mostly closed to new surface‑water allocations, pushing developers toward the Red Deer basin or northern basins (Peace River, Athabasca) with greater water and cooler temperatures. Cooling technology advances can reduce direct water use, but power choices matter—on‑site gas plants require cooling water too, raising the total footprint.

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Integrating Natural Gas and Electricity: A Strategy for New Brunswick’s Affordable, Reliable Energy

New Brunswick faces an energy affordability and reliability challenge that requires integrated planning across electricity and natural gas systems. Rising heating costs, unpredictable winters, aging generation assets and NB Power’s performance gaps have exposed the limits of single-solution approaches. Coordinated utility strategies can deliver greater resilience: electricity and natural gas are complementary, with gas providing a cost-effective, flexible backbone during winter peaks when electric grids are strained. Households heating with natural gas save roughly 30% compared with electric-only heating, highlighting tangible savings for families.

Regions nearby already pursue joint gas-electric planning, leveraging existing pipelines and distribution to smooth demand, reduce price volatility and lower emissions when used alongside cleaner power generation. Policy choices matter: treating natural gas as essential infrastructure and enabling inter-utility partnerships would improve reliability, affordability and emergency preparedness.

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IPPSA's Mandate

IPPSA's mission is to convene industry, providing information, resources, and a forum for knowledge sharing, and to create opportunities for dialogue, collaboration, and education. This newsletter is meant to inform members but not advocate for specific outcomes. We always appreciate your feedback at info@ippsa.com.