IPPSA Intelligence

Alberta Electric System Operator (AESO)

Stakeholders in Alberta’s electricity market face a busy October schedule of deadlines, sessions and consultations centered on market design, transmission planning, tariff amendments and reliability rules.

Cost claims for participation in the Restructured Energy Market engagement must be submitted by October 1, coinciding with an updated Annual Market Statistics release covering data through August. Feedback due dates include October 2 and 20 for REM ISO rules and October 31 for the Optimal Transmission Planning framework posted on AESO Engage, with clarification questions open until October 9.

Key workshops on incumbency treatment, Generating Unit Owner’s Contribution refunds, ancillary services cost allocation and tariff redesign occur throughout October, while October 23–24 sessions will cover the Transmission Reinforcement Payment and connection-process amendments, including an application to amend Section 7 of the ISO tariff to align GUOC timelines with connection procedures.

An AESO response to a July 31 frequency and speed governing rule proposal highlights ongoing efforts to ensure system reliability. Together, these initiatives will shape future transmission investment, market rules and connection costs. Generators, developers, utilities and consultants must actively engage, register for sessions and submit timely feedback to influence evolving policies and safeguard compliance in Alberta’s electricity landscape. Timely input maximizes benefits.

References:

1. AESO Stakeholder Updates — October Deadlines, OTP Framework, GUOC Tariff Filing & Frequency-Rule Update

Alberta Utilities Commission

Alberta’s energy landscape is shaped by a diverse mix of renewable and traditional generation projects currently under review by the Alberta Utilities Commission. Applications span solar power plants from Big Rock, Blue Heron, Eastervale, Lawful PV and multiple Oyen and Little Smoky sites, wind initiatives such as the Oyen Wind Power Project, gas-fired generation at Flipi, battery storage from Laramide and new transmission developments including the Berland River and Edmonton Reinforcement projects.

Stakeholders face intricate approval processes that can delay progress, but they also benefit from transparent public comment opportunities and structured oversight. Economically, these investments promise local jobs, infrastructure upgrades and potential energy cost stabilization. The current portfolio highlights strategic balancing of innovation, policy compliance and market demands, indicating Alberta’s drive toward an adaptable and resilient energy future. Growing regulatory transparency and stakeholder engagement signal evolving governance models, fostering investor confidence and community support.

References:

1. AUC Project Update: Statuses of Alberta’s Solar, Wind, Battery Storage and Gas Applications

Pace Canada appeals AUC cost awards, stalling 25.9 MW Brooks solar project

Rapid growth in solar and wind energy in Alberta is colliding with regulatory and legal challenges that threaten small-scale renewable projects. Pace Canada’s planned 25.9 MW solar farm near Brooks has received AUC approval but remains on hold after regulators ordered the developer to pay over CA$238,950 to a citizen group that opposed an earlier project. When the AUC denied Pace’s internal appeal, the company sought review at the Alberta Court of Appeal, arguing that unrestricted cost awards create unpredictable financial exposure and could deter future investments. The decision also raises the prospect of upfront security deposits for new projects. 

More broadly, this case could reset boundaries for public intervenor costs, influencing how regulators balance meaningful community participation with project viability. If the court narrows cost awards, small developers might gain financial clarity; if it upholds broad entitlements, renewable projects could face slower deployment, higher financing burdens and a chill on innovation. 

References:

1. Pace Canada appeals AUC cost awards, stalling 25.9 MW Brooks solar project

Power‑Market Modernization, Grid Investment Needs and Energy‑Infrastructure Winners

Alberta is poised to become a data-centre growth hub, a development that could gradually tighten provincial electricity supply versus demand as large new loads come online. Meetings between analysts and Alberta officials, including the AESO, and the completion of an electricity‑market modernization design have increased market visibility and may unlock investment in generation, transmission and connection infrastructure. Identified beneficiaries include TransAlta and Capital Power, which could win contracts or benefit from higher wholesale prices; Pembina Pipeline via joint-venture infrastructure activity; and Canadian Utilities for grid connections.

The modernization reduces regulatory uncertainty and helps align government, system operator and industry planning, but timing and scale remain uncertain pending firm contracts and transmission build plans. Broader implications include upward pressure on wholesale prices, a need for additional or reallocated generation capacity, and more transmission build‑outs — all with economic upside for energy‑infrastructure owners but heightened operational and permitting demands.

References:

1. Alberta's Data‑Centre Buildout: Power‑Market Modernization, Grid Investment Needs and Energy‑Infrastructure Winners

Dow Delays Fort Saskatchewan Path2Zero Ethane Cracker and Net‑Zero CCS Project 1–2 Years

Dow will delay its Path2Zero expansion at Fort Saskatchewan by roughly one to two years, citing an uncertain market environment and pushing a planned 2027 start later, CEO Jim Fitterling said. Announced in November 2023, the project had already prompted more than US$1 billion of spending and a roughly US$1 billion reduction in 2025 capital expenditure after an April indefinite pause.

The base expansion was C$8.9 billion to boost ethane cracking and polyethylene output; integrated emissions infrastructure — converting cracker off‑gas to hydrogen for furnaces and linking other streams to Alberta carbon‑capture storage — adds C$2–3 billion, taking all‑in costs above C$11 billion. Dow will continue some engineering and construction but is re‑evaluating pace and spend and will update stakeholders by year‑end. The delay eases near‑term incremental ethane demand in Alberta, complicates planning for pipelines and suppliers, and reduces visibility for regional petrochemical investment.

References:

1. Dow Delays Fort Saskatchewan Path2Zero Ethane Cracker and Net‑Zero CCS Project 1–2 Years, Trims Near‑Term Capital

Capstone Commissions 192 MW Wild Rose 2 Wind Farm

Capstone Infrastructure has commissioned the 192 MW Wild Rose 2 wind farm in Cypress County, Alberta, boosting its renewable operating capacity to over 1 GW and advancing regional decarbonization through public–private collaboration and long-term contracts. Construction produced approximately 475 jobs and stimulated local economic activity, while federal support via Natural Resources Canada’s Smart Electrification and Renewable Energy Pathways Program helped finance the project.

Commercial offtake includes a 15-year, 105 MW PPA with Pembina Pipeline Corporation and a Renewable Attribute Purchase Agreement exceeding 20 years for 78 MW with the City of Edmonton — the largest long-term municipal renewable commitment in Canada — providing stable revenue streams that de-risk investment and signal durable demand for contracted renewable energy. 

References:

1. Capstone Commissions 192 MW Wild Rose 2 Wind Farm in Alberta, Boosting Renewable Capacity Past 1 GW with Long-Term PPAs and Major Emissions Reductions

Capital Power brings 170 MW of utility‑scale battery storage online in Ontario

Capital Power commissioned two utility-scale battery energy storage systems in Ontario — York BESS (120 MW) and Goreway BESS (50 MW) — reaching commercial operations on Sept. 22, 2025, near the Township of King and Brampton/GTA. Combined capacity of 170 MW is contracted with the Ontario IESO through the Expedited Long-Term 1 RFP, with contracts running to 2047 and expected contracted annual EBITDA of roughly $35 million for more than 20 years.

The facilities enhance grid flexibility and reliability, smooth renewable integration, and help meet rising electricity demand while reducing reliance on fossil-fuel peaking plants. Capital Power delivered the projects in about 12 months, on time and under budget, with approximately 183,000 person-hours and a strong safety record, and engaged the City of Brampton, the Township of King, Indigenous Nations and local residents during development. 

References:

1. Capital Power brings 170 MW of utility‑scale battery storage online in Ontario, securing IESO contracts to 2047

Alberta’s 2% AI Data Centre Levy

Alberta’s AI data‑centre levy framework imposes a 2% computer‑hardware levy on grid‑connected data centres drawing 75 MW or more, effective December 31, 2026, designed as a hardware charge because equipment isn’t taxed via sales or property tax. The 75 MW threshold mirrors AESO’s “large load” treatment and links fiscal policy to grid planning; AESO has set an interim cap of 1,200 MW of new large connections through 2028 amid more than 16,000 MW of applications. The levy is fully creditable against Alberta corporate income tax, rendering it tax‑neutral for profitable operators but a real cash cost for unprofitable entrants.

Land and buildings for qualifying centres will be assessed as designated industrial property at municipal rates, though municipalities can offer property‑tax incentives or deferrals. The levy applies only to grid‑tied facilities, so some developers may explore self‑supply or onsite generation, yet grid ties remain attractive for reliability and market participation. The measure seeks early revenue while preserving competitiveness; developers, investors and planners should factor the levy, possible payment‑in‑lieu or deferral programs, AESO limits, and municipal incentives into project economics and timing and monitor regulatory updates closely.

References:

1. Alberta’s 2% AI Data Centre Levy: 75 MW Threshold, AESO Caps, Tax Offsets and Investment Impacts

Meta’s $10B Louisiana Data Center Spurs $3B Electricity Buildout

Meta’s massive Holly Ridge data center in Richland Parish, Louisiana has triggered roughly $3 billion of new electricity infrastructure: Entergy will build three gas-fired plants totaling 2,262 MW and a $550 million transmission line. Meta will pay about half of plant construction over 15 years but won’t shoulder operations and maintenance; transmission costs are expected to be socialized across grid customers.

Confidentiality agreements hid contract specifics from the public and limited regulators’ ability to probe, prompting consumer and environmental advocates to warn that if Meta withdraws or fails to renew, remaining plant costs could fall to ratepayers. Regulators approved the plan after limited concessions; opinions split among commissioners. The deal highlights a broader policy dilemma as states vary in responses—some imposing data-center rate structures, studies, or emergency controls, others offering expedited approvals or tax exemptions—raising questions about who bears long-term fiscal and reliability risk.

References:

1. Meta’s $10B Louisiana Data Center Spurs $3B Electricity Buildout — Who Pays, How Regulators Approved It, and Risks to Ratepayers

Can B.C. Electrify Its LNG Expansion?

British Columbia’s push to electrify multiple proposed and existing LNG terminals highlights a sharp mismatch between ambition and grid reality. Combined electricity demand from projects such as LNG Canada (Phase 2), Tilbury, Ksi Lisims, Cedar and Woodfibre could exceed 6,600 GWh/year—more than Site C’s roughly 5,100 GWh annual output. B.C. Hydro has shifted from exporter to importer amid drought and rising domestic use, buying thousands of GWh at high cost and warning supply must grow up to 15% in five years.

Even with Site C and new wind procurement, significant new generation plus long, costly transmission builds would be needed to reach remote sites; experts say full electrification for all projects is unlikely. The government softened a 2030 “net‑zero” requirement to “net‑zero‑ready,” eased wind reviews and launched calls for power to accelerate supply. 

References:

1. Can B.C. Electrify Its LNG Expansion? Power, Transmission and Climate Challenges

UK–US Nuclear Pact and Major Mine Cuts Tighten Uranium Market

Nuclear energy has regained prominence as governments seek low‑carbon, reliable baseload power amid rising electricity demand, including from AI data centers. A new UK–US “Atlantic Partnership for Advanced Nuclear Energy” aims to accelerate deployment of advanced reactors—including proposals for up to 12 small modular reactors in northeast England and U.S. projects targeting homes and large data centers—promising job creation and roughly $54 billion of economic activity.

Major producers have trimmed supply: Cameco reduced its 2025 forecast after McArthur River delays and Kazatomprom announced a 10% production cut, while the U.S. is expanding its strategic uranium stockpile. Those moves, combined with policy support, have tightened near‑term fundamentals and helped U.S. uranium futures climb above US$76 per pound. The developments point to stronger medium‑ to long‑term uranium demand driven by decarbonization and energy security, plus near‑term upward price pressure from supply constraints and stockpiling. 

References:

1. UK–US Nuclear Pact and Major Mine Cuts Tighten Uranium Market, Sparking Price Rally and ETF Inflows

Nova Scotia greenlights offshore wind bidding in four lease areas

Nova Scotia has authorized the Canada‑Nova Scotia Offshore Energy Regulator to begin prequalification and a competitive bidding process for four newly designated offshore wind lease areas—Middle Bank, Sable Island Bank, Sydney Bight and French Bank—covering about 1,981,000 hectares, marking a shift from planning to procurement for Canada’s nascent commercial offshore wind sector.

The sites were selected after federal scoping narrowed eight potential areas to five for consultation and eventually four lease zones. The federal government frames the Wind West Atlantic Energy concept as a nation‑building priority, with the Major Projects Office positioned to coordinate approvals and accelerate project delivery.

References:

1. Nova Scotia greenlights offshore wind bidding in four lease areas, advancing Wind West Atlantic Energy plans

Consequences of Aging U.S. Power infrastructure

U.S. consumers experienced significantly more power outages in 2024, averaging 10.6 hours of downtime per customer, up from 7.7 the previous year (a 38 % jump). The visualization reveals stark variation by state: Florida (29.4 hours), Maine (51.7 hours), and South Carolina (57.8 hours) rank among the worst, while the District of Columbia (1.6 hours), Massachusetts (1.7 hours), and Arizona (1.8 hours) saw relatively little outage time.

The piece argues that these disparities reflect weaknesses in the aging U.S. power infrastructure, whose decades-old transmission and distribution systems struggle under rising demand and increasingly frequent extreme weather events.

References:

1. Consequences of Aging U.S. Power infrastructure

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.