IPPSA Intelligence

Alberta Electric System Operator

AESO’s latest stakeholder bulletin outlines pivotal grid planning milestones, tariff changes, and engagement opportunities through December 19, 2025. Project developers can now submit System Access Service Requests for Cluster 3 via a new online form, with connections required by April 30, 2031, while Cluster 2 stage two dates have been refreshed.

A consolidated SASR guide streamlines Independent and Cluster Assessment processes and updated fee guidelines will govern new assessments after April 30, 2026. Woodcroft Substation’s upgrade will enter the Abbreviated Needs Approval Process around November 6, prompting early stakeholder inquiries. Regulatory alignment advances as the Alberta Utilities Commission ratifies AESO’s Section 7 amendment, syncing Generating Unit Owner Contribution schedules with tariff requirements and mitigating timing conflicts for generator payments.

Engagement channels remain robust: sessions on connection process amendments, 2026 budget development, allowable dispatch variance, market power mitigation, and reliability standards allow participants to shape rules and compliance standards.

Deadlines for feedback on frameworks, incumbency treatment, and reliability standards sync‑up ensure timely input. These updates refine connection timelines, cost planning and compliance, helping market participants align project schedules with regulatory obligations and budget considerations while influencing grid reliability and tariff policy. 

References:

1. AESO Stakeholder Newsletter — Cluster 3 Intake, Section 7 (GUOC) Approval, Woodcroft ANAP, Fee Updates & Key Reliability Deadlines

Alberta Utilities Commission

Alberta’s energy infrastructure landscape is now undergoing transformation under the oversight of the Alberta Utilities Commission (AUC), which regulates projects in solar, wind, battery storage, transmission and gas generation. Active approvals include the Berland River Transmission Connection Project advancing transmission capacity. Solar initiatives such as the Blue Heron project remain under review, while wind developments like the Oyen Wind Power Project—including plant and substation permits—also await regulatory decisions.

Battery storage proposals and gas-fired generation applications reflect an approach to grid stability and peaking power. Some renewables face delays: the Legal Solar PV and Big Rock Solar projects are in abeyance, reflecting technical, environmental or market uncertainties. The Spruce Grove South Solar PV Plant has been withdrawn, illustrating the challenges developers encounter. The portfolio of pending and approved projects underscores a gradual pivot toward renewables, balanced with traditional generation to ensure reliable supply.

References:

1. Alberta Energy Infrastructure Under Review: AUC Updates on Solar, Wind, Battery Storage, Transmission and Gas-Fired Projects

Alberta’s Fall 2025 Throne Speech: Defending Sovereignty, Pursuing Fiscal Discipline and $8.6B

Delivered Oct. 23, 2025, the throne speech frames Alberta’s next legislative session around provincial autonomy, fiscal discipline and economic resilience. The government pledges to defend constitutional jurisdiction while pursuing responsible resource development through partnerships with Indigenous governments, industry and other jurisdictions, and to maintain diplomatic, respectful U.S. relations. Fiscal priorities focus on shielding Alberta from energy-price swings, U.S. tariffs and external shocks, guided by legislated spending rules and a long‑term aim to grow the Alberta Heritage Savings Trust Fund to over $250 billion by 2050.

On the Alberta Power Market side, the speech claimed that past federal policies “undermined the integrity of the power grid Albertans rely on,” framing electricity reliability as a provincial concern. It also pledged to “decrease and slow the rise of electricity…costs through the implementation of the province’s reformed electricity market.”

References:

1. Alberta’s Fall 2025 Throne Speech: Defending Sovereignty, Pursuing Fiscal Discipline and $8.6B for Schools

High winds push Alberta to $0/MWh

High wind output in Alberta on Oct. 18–19, 2025 drove the wholesale pool price to zero for several hours, triggering substantial exports to British Columbia and Montana while Saskatchewan’s intertie remained offline. Morning wind generation reached nearly 57% capacity and solar contribution climbed after sunrise. Despite abundant power, a sudden trip of the Genesee Repower 1 unit (~466 MW) nearly exhausted dispatched contingency reserves (DCR), leaving only about 7 MW available against a requirement exceeding 474 MW. Fast-acting batteries provided roughly 118 MW but could not fully restore reserves.

The Alberta Electric System Operator did not issue a grid alert and the incident did not appear in public logs. This episode illustrates the challenge of integrating high shares of variable renewables with sufficient back‑up capacity when large generators unexpectedly disconnect. Zero or near‑zero prices spurred cross-border flows, reshaping regional market dynamics and intertie management. NERC guidance recommends maintaining reserves of roughly 4% of demand, highlighting the need to meet industry standards.

References:

1. Oct. 18–19, 2025: High winds push Alberta to $0/MWh, spur large exports and a brief contingency‑reserve crisis after Genesee trip

Alberta’s Data Centre Push

The Logic points to Alberta’s plan to host AI data centres could more than double current peak demand of 12,000 MW by adding roughly 20,000 MW of proposed projects. Only 4,000 MW of that total has been earmarked for self-generation so far, leaving most developers reliant on the public grid. To address the potential strain, the government is fast-tracking bring-your-own-power proposals but details remain scarce.

Longer-term framework work is underway to clarify rules on self-supply, off-site partnerships and grid reliability with guidance from NERC. Experts emphasize demand flexibility, efficiency improvements and shifting loads to off-peak hours as lower-cost, lower-risk alternatives to costly infrastructure expansion. The Pembina Institute estimates such measures could save about $1 billion annually. Coordinated action among government, regulators, AESO and developers will be essential to align generation, transmission, market rules and demand-side programs for sustainable expansion of Alberta’s electricity system.

References:

1. Alberta’s AI data‑centre push could match entire grid capacity — 33 projects, ~20,000 MW of demand

Alberta’s Legal Path to Greater Autonomy?

A new paper from the Macdonald-Laurier Institute argues that constitutional and legal avenues exist for a province to incrementally assume greater authority over pensions, policing, immigration and taxation — powers Quebec has exercised — to reclaim control from Ottawa over areas that affect energy and environmental regulation. Framed as institution-building rather than separatism, the strategy emphasizes gradual capacity- and trust-building so Alberta can responsibly manage programs now influenced by federal conditional transfers and environmental legislation.

Transferring treaty relationships from Ottawa to Alberta is raised as a consequential option that would reshape Indigenous governance and resource approvals. If pursued, these moves could change who sets environmental rules for pipelines and energy projects, alter fiscal flows and regulatory certainty for industry, and recalibrate federal–provincial bargaining. Political viability hinges on public confidence, legal challenges, and federal response; the brief notes Albertans currently lack the institutional trust Quebec developed over decades.

References:

1. Alberta’s Legal Path to Greater Autonomy: Implications for Resource, Environmental and Indigenous Policy

B.C. overhauls electricity rules

British Columbia is shifting electricity allocation away from first‑come, first‑served toward prioritizing projects judged to deliver the greatest local benefit, favouring natural‑resource and manufacturing developments while subjecting AI, large data centres and hydrogen‑for‑export proposals to competitive bidding. The province will reserve 300 MW for AI and 100 MW for data centres every two years. The temporary ban on cryptocurrency power connections will be made permanent.

The government is fast‑tracking the North Coast Transmission Line—about 450 kilometres—with the first two phases now estimated at $6 billion (up from $3 billion in 2023) and construction slated to start next year. Officials project roughly 9,700 direct full‑time construction jobs and about $10 billion per year in GDP once operational, with mining groups forecasting larger near‑term economic activity. The B.C. government has directed the utilities regulator to issue the required certificate of public convenience and necessity, bypassing ordinary public hearings, and is engaging Ottawa on federal support; the full plan envisions extension to the Yukon and ties to sovereignty and defence.

References:

1. B.C. overhauls electricity rules: prioritizes resource and manufacturing projects, makes crypto ban permanent and fast‑tracks $6B North Coast Transmission Line

NERC CEO Sounds the Alarm to Congress

North American Electric Reliability Corporation (NERC) President & CEO Jim Robb warned federal regulators that although the U.S. power grid’s reliability is still very high, the underlying risks to that reliability are mounting rapidly, calling the situation nothing but a five‑alarm fire. He pointed to several trouble‑spots: shrinking resource adequacy and weakening reliability services, extreme weather, deep interdependencies (especially with natural gas and telecommunications), delays in siting and permitting infrastructure, policy constraints around resource and fuel development, and a growing “toxic soup” of physical and cyber security threats.

A particular concern: the rapid load growth from data centers and artificial intelligence, which could drive U.S. electricity use from about 4.4 % in 2023 to as much as 12 % by 2028, stressing supply, generation, and transmission. Regulators and grid operators say the pace of infrastructure build‑out is too slow, and they’re calling for faster permitting, better tools to manage uncertainty, and more robust “shock absorbers” built into the system so it can handle unexpected swings in demand or resource performance.

References:

1. NERC president warns of ‘five‑alarm fire’ for grid reliability

Alberta and Saskatchewan Debate Reactors, Costs and Grid/Environmental Trade‑offs

Western Canada is actively re-evaluating nuclear power as Alberta and Saskatchewan pursue different paths: Saskatchewan has declared nuclear a policy direction, created SaskNuclear and sought federal cost‑sharing, while Alberta is taking a technology‑neutral, market‑oriented approach with advisory engagement and private developers advancing proposals. Proponents range from SaskPower’s selection of the BWRX‑300 SMR and identified sites to Energy Alberta/Monark’s ambitious 4,800 MW Peace River plan, Capital Power’s partnership with OPG, and startups like Nucleon Energy exploring ARC‑100‑style reactors.

Timelines stretch into the 2030s–2040s and costs remain highly uncertain — recent projects show large overruns (e.g., Darlington SMR now ~C$20.9 billion for 1,200 MW) and SMR savings have yet to materialize. Technical and environmental constraints in the Prairies — limited cooling water, spent‑fuel disposal logistics tied to a proposed Northern Ontario deep geological repository, and Indigenous consultation requirements — add complexity. 

References:

1. Western Canada Weighs Nuclear Power: Alberta and Saskatchewan Debate Reactors, Costs and Grid/Environmental Trade‑offs

Stats Canada Preliminary 2024 Canada Thermal Electricity

Stats Canada released their preliminary results which showed that Canada’s thermal electricity mix shifted in 2024 as total thermal generation rose 2.2% to 225.0 million MWh, driven chiefly by a 14.1% surge in natural gas (+13.9 million MWh) amid reduced hydro generation and rising demand. Coal generation fell 30.9% (-6.7 million MWh), concentrated in Alberta where coal slid 78.2% as policies and new gas capacity replace coal. Nuclear output declined 3.9% (-3.3 million MWh) with major outages—most notably New Brunswick’s Point Lepreau offline April–December (-62.8%)—prompting sharp increases in fossil backfills: New Brunswick’s coal rose 81.5% and petroleum use climbed 16.9%.

Ontario’s gas generation jumped 27.7% (+5.9 million MWh) while its nuclear edged down during refurbishments. Quebec and other provinces increased petroleum‑fired output to compensate for lower hydro. Natural gas, coal and uranium still accounted for 92.4% of thermal generation. Revised 2021–2023 data and methodological integration into Statistics Canada’s IBSP accompany the release.

References:

1. Preliminary 2024 Canada Thermal Electricity: Natural Gas Surges, Coal Plummets and Nuclear Outages Reshape Provincial Fuel Mix

Saskatoon Hosts CNA West

Saskatchewan’s hosting of the CNA West conference in Saskatoon signalled growing momentum for nuclear expansion in western Canada, driven particularly by interest in small modular reactors (SMRs), uranium industry strengths and coordinated policy support.

Provincial announcements timed with the event — a Saskatchewan First Energy and Security Strategy naming nuclear central to the province’s future and a $6.3‑million SaskPower investment over six years to create four nuclear research chairs — underscored government backing and research funding for commercialization.

References:

1. Saskatoon Hosts CNA West: SMRs, Saskatchewan’s Energy Strategy and New Nuclear Research Chairs

Westinghouse and Energy Alberta sign MoU to explore AP1000 nuclear deployment 

Westinghouse and Energy Alberta signed a memorandum of understanding to explore deploying Westinghouse’s AP1000 modular Generation III+ reactor at Energy Alberta’s proposed Peace River Nuclear Power Project. The MoU frames joint technical, commercial and stakeholder work to assess a greenfield development that could reach 4,800 MW — roughly 25% of Alberta’s current generation — with Westinghouse suggesting AP1000 units could begin supplying low‑carbon baseload electricity by the mid‑2030s.

The partners emphasize construction and operations economic benefits, citing CAD 28.7 billion in construction GDP and CAD 8.1 billion annual GDP during operations, alongside skilled‑trade jobs, manufacturing opportunities and potential export prospects for local suppliers. Regulatory steps are underway: Energy Alberta filed an Initial Project Description and a federal impact assessment has been triggered, while Indigenous Nations and communities are being engaged. 

References:

1. Westinghouse and Energy Alberta sign MoU to explore AP1000 nuclear deployment at Peace River, up to 4,800 MW

Dam Busters – Part 1: The Preference Cascade

The Pandreco article “Dam Busters – Part 1: The Preference Cascade” argues that public opinion on the energy transition is undergoing a dramatic shift — a “preference cascade” in which once‑taboo skepticism about rapid decarbonization and reliance on renewables is breaking into the mainstream. The author likens this shift to a dam cracking under pressure: after years of social and political conformity around Net Zero goals, economic realities such as high costs, energy insecurity, and industrial strain are causing growing numbers of people, policymakers, and experts to voice doubts about the feasibility of a wind-and-solar-dominated future.

This reversal, the piece suggests, mirrors economist Timur Kuran’s concept of preference falsification — where hidden dissent becomes public once enough people begin to speak out — leading to rapid change in accepted norms and policies.

References:

1. Dam Busters – Part 1: The Preference Cascade

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.