IPPSA Intelligence

AESO

Alberta’s electricity grid is moving toward greater flexibility and resilience with approved transmission access for the Marguerite Lake compressed-air energy storage project and an upgrade of the Cadomin substation to meet local demand growth. The commissioning of large-scale storage promises to buffer renewable variability while reinforcing distribution networks enhances reliability.

New Generator Unit Owner’s Contribution rates for 2026 took effect on January 1, introducing revised cost allocations in the Central planning region that will influence generator economics and investment decisions.

A revised consultation timeline for the Optimal Transmission Planning ISO Rule pushes the draft rule posting to April and Q&A sessions to the second quarter, delaying stakeholder input on future transmission investment frameworks.

Meanwhile, compliance and reliability reporting are advancing with the release of the Q4 2025 Alberta Reliability Standards compliance report and the introduction of Milestone 3’s updated standards package, aligning provincial requirements with North American Electric Reliability Corporation and FERC directives.

Stakeholders face several upcoming deadlines for feedback on cost studies, participation in market readiness surveys, and a session on Financial Transmission Rights.

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AUC Approves NU E Power's Lethbridge Two and Three Solar Projects

NU E Power Corp is set to boost renewable energy capacity near Lethbridge with its Lethbridge Two and Lethbridge Three solar fields, following Alberta Utilities Commission approval. These projects will add a combined 167 MW of solar power, building on the operational Lethbridge One facility. The larger Lethbridge Three installation is designed to meet long-term power offtake agreements, support data centres and industrial demand, and integrate battery energy storage to enhance grid flexibility and unlock additional value per megawatt.

Both projects aim for construction within the year but hinge on securing development permits and rezoning approvals from local authorities. The inclusion of battery storage promises improved dispatchability, enabling the projects to serve long-duration demands and stabilize intermittent solar output.

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ATCO and FortisAlberta Propose Higher Franchise Fees in Brooks

ATCO Gas and Pipelines Ltd and FortisAlberta have filed applications with the Alberta Utilities Commission to raise municipal franchise fees in the City of Brooks effective April 1, reflecting growing pressure on municipalities to secure infrastructure revenue amid rising utility costs. ATCO proposes increasing its natural gas fee from 19.5 to 22.5 percent, which would add roughly $10.58 to an average residential monthly bill, while FortisAlberta seeks to boost its electricity fee from 14.75 to 17 percent, equating to about $13.55 per month.

Combined, the adjustments could raise customers’ bills by around $24.13 monthly. These franchise fees, capped at 35 percent for natural gas and 20 percent for electricity distribution tariffs, compensate municipalities for use of public land and maintenance of utility infrastructure. Consumers have until January 29 to submit comments or objections—submissions will form part of the public record in the AUC’s decision-making process.

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Jasper Divided Over ATCO’s New Overhead Power Poles

ATCO recently installed taller overhead poles in Jasper, prompting residents to push for undergrounding after the 2024 wildfire destroyed homes and a 2022 blaze damaged 18 transmission poles. ATCO says decisions balance reliability, affordability and resiliency: it has completed selective undergrounding (Marmot Basin, Pyramid Lake, a main distribution feed behind town) but maintains some overhead lines where rocky terrain and technical constraints make burying long transmission spans infeasible.

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Alberta’s Nuclear Engagement Panel to Hold Townhalls

Alberta is launching a province-wide public engagement process to assess nuclear energy as a response to growing electricity demand, with the Nuclear Engagement and Advisory Panel hosting in-person townhalls and targeted meetings with Indigenous communities, municipalities and regional stakeholders.

Sessions scheduled across January–February 2026 (Peace River, Fort McMurray, Bonnyville, plus Calgary and Edmonton dates with venues to be confirmed) are intended to inform a final report to the Minister of Affordability and Utilities by March 31, 2026, which will underpin a prospective nuclear energy roadmap.

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Tying a West Coast Pipeline to CCUS, Industrial Carbon Pricing, Nuclear Strategy and Indigenous Engagement

Fasken writes that the Canada–Alberta MOU ties a proposed West Coast oil pipeline to large-scale carbon capture, utilization and storage (CCUS), industrial carbon pricing, a future nuclear strategy for Alberta, and Indigenous participation and financing, creating a strong market signal while bundling multiple risks.

Non‑binding but milestone-driven, the deal sets dates for agreements on carbon pricing, methane equivalency and impact‑assessment cooperation by April 1, 2026; pipeline application readiness and data‑centre incentives by July 1, 2026; and a nuclear generation strategy by January 1, 2027, overseen by an implementation committee.

Excluding British Columbia and Indigenous groups from initial talks generated immediate political friction, raising legal, reputational and reconciliation challenges despite referenced tools to finance Indigenous equity.

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SkyFire Energy Acquires Hakai Energy Solutions

SkyFire Energy’s acquisition of Hakai Energy Solutions expands Calgary‑based SkyFire into Vancouver, Vancouver Island, coastal and remote British Columbia, combining SkyFire’s EPC and O&M platform with Hakai’s experience in grid‑tied and off‑grid solar, microgrids, residential battery storage and commercial/utility-scale operations.

The merger creates roughly 200 employees, boosting local capacity to pursue distributed-energy projects that enhance resilience in communities dependent on isolated grids. The deal underscores sector consolidation as firms scale to meet rising demand for integrated solar, storage and microgrid solutions driven by electrification and climate resilience priorities.

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Clean Prosperity's Roadmap for the Federal–Alberta Interprovincial Transmission MOU

Federal and Alberta governments’ memorandum of understanding on interprovincial transmission offers a strategic chance to bolster grid reliability, lower consumer costs and accelerate decarbonization, but the Clean Prosperity report argues the MOU lacks a defined implementation path.

Authors stress three priorities: formal collaboration among western provinces, utilities, system operators and Indigenous communities to streamline coordination while keeping federal involvement targeted; stronger transmission planning to quantify costs and benefits of new interties; and rapid funding mobilization using tools such as the Canada Infrastructure Bank and tweaks to the Clean Electricity Investment Tax Credit to make intertie projects financeable. The report warns rising demand and affordability pressures make timely, detailed plans essential.

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Alberta’s Bills 8 and 12: Data-centre levy, 'bring-your-own-power' rules and new grid integration framework for AI investment

Alberta enacted Bills 8 and 12 on December 11, 2025 to manage rapid data‑centre growth while protecting grid reliability and electricity affordability. Bill 8 amends the Electric Utilities Act to give the minister broad regulation‑making powers to define data‑centre classes, regulate grid connections, load management and exemptions, and prioritize projects that “bring their own power” by encouraging self‑generation or new capacity agreements; developers will generally bear transmission upgrade costs and generators tied to data centres may face redundancy requirements.

Bill 12 imposes a levy on large grid‑connected data centres drawing 75 MW or more based on the value of computing equipment: a 2% rate for grid‑dependent sites, reduced proportionally by the share of power from new capacity or self‑generation, with a 1% rate possible when the grid is only redundancy and no calendar‑year grid draw occurs; off‑grid arrangements are exempt and the levy is a credit against Alberta corporate income tax.

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B.C. a Net Electricity Importer for Third Year

British Columbia has shifted into a multi-year pattern of net electricity imports, driven by drought-related hydro shortfalls and growing demand, raising questions about planning, costs and reliability. EFI reports B.C. imported 5,591 GWh in 2025 and BC Hydro imported 13,600 GWh in fiscal 2024; the 2025 imports exceed the expected annual output of Site C (≈5,100 GWh). Imported-power costs were nearly $1.4 billion in fiscal 2024 and topped $2 billion across 2023–24 and 2024–25.

Government officials cite multi-year drought and market trading benefits, experts warn of structural demand growth—electrification, industrial loads and a 7,291 MW connection queue—and argue current policy and planning understate future needs. The North American Electric Reliability Corporation forecasts rising energy risks in 2026 as demand grows and some gas plants retire, amplifying reliability concerns.

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Economic report: Bruce C nuclear expansion project

An independent economic analysis commissioned for the Nuclear Innovation Institute forecasts that the proposed Bruce C nuclear project could add roughly $217 billion to Ontario’s GDP and nearly $238 billion to Canada’s GDP over an estimated 80‑year life. About $61 billion is expected during site preparation and construction, with more than $176 billion tied to long‑term operations. The region could see average annual regional GDP gains near $2.3 billion.

Bruce C would add up to 4,800 MW of nuclear capacity, bringing Bruce Power’s total to about 12,000 MW and potentially making it the world’s largest nuclear facility by capacity.

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BC Hydro’s 2025 Call Spurs Wave of Clean-Energy Proposals

British Columbia’s electricity planning appears to be entering a new phase after a strong response to BC Hydro’s 2025 call for power produced a suite of clean‑energy proposals. The submissions, highlighted by government and BC Hydro communications, signal renewed investor appetite for low‑carbon generation and associated grid projects and are framed as the start of a “new era” of clean‑energy investment in the province.

The announcement sits alongside procurement materials—RFEOIs, call pages and Q&A—underscoring an open, process-driven approach to sourcing capacity. If advanced, the proposed projects could add generation and storage capacity, enhance system reliability, and help meet growing demand while advancing decarbonization goals

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Microsoft CEO Warns AI Must Prove Its Worth or Risk Losing Support

At the 2026 World Economic Forum in Davos, Microsoft CEO Satya Nadella issued a cautionary message about the burgeoning energy demands of artificial intelligence. Nadella said the AI industry must deliver clear, real-world benefits to justify the vast amounts of electricity and other scarce resources consumed by large-scale AI systems. Without demonstrable societal value, he argued, AI could lose its “social permission” to consume energy at the current scale, risking public backlash and regulatory pushback.

Nadella’s remarks reflect growing concern over AI’s environmental and grid impacts as data centers proliferate and energy use climbs. He emphasized that widespread adoption and meaningful outcomes across industries, not just investment in infrastructure, are key to sustaining public trust and long-term viability.

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General Fusion Considers Going Public

B.C.-based General Fusion is exploring a move to public markets, potentially through a SPAC deal and Nasdaq listing, as it seeks new capital to advance its nuclear fusion technology. The company, which develops magnetized target fusion, has recently raised fresh funding following earlier financial pressures and layoffs. A public listing would give General Fusion access to larger pools of capital as global interest in fusion energy accelerates, though commercialization remains years away and carries significant technical and financial risk.

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Should the Ford government just privatize Ontario Power Generation?

A recent Globe and Mail opinion piece critiques Ontario Premier Doug Ford’s strong push for nuclear energy, including expanding Ontario Power Generation’s role in new builds and refurbishments, as central to the province’s energy strategy. The piece argues that while nuclear power—already supplying a large share of Ontario’s electricity mix and helping keep carbon emissions low—is important for reliability and decarbonization, the scale, cost and risk of planned expansions raise questions about affordability for ratepayers and the balance of the province’s long-term energy mix.

The commentary highlights Ford’s advocacy of both small modular reactors (SMRs) and potential large new nuclear capacity, amplified by cross-border cooperation such as a memorandum of understanding with New York to leverage OPG’s nuclear expertise and create economic opportunities. However, critics argue that nuclear projects carry substantial cost and timeline risks, and that diversified investments should remain part of Ontario’s strategy to meet future demand reliably and affordably.

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