IPPSA Intelligence

AESO

Alberta’s electricity operator is advancing measures to bolster grid flexibility and plan an optimally designed transmission system. Draft requirements for Fast Frequency Response procurement reflect a drive to secure rapid-response services as system inertia declines, with market-sounding sessions inviting stakeholder input.

Publishing the Optimal Transmission Planning framework signals a shift from a congestion-free standard to one that prioritizes economic efficiency and strategic reinforcements. Technical updates to the Project Data Update Package checklist and PSS/E dynamic model test bench enhance modelling of inverter-based resources, facilitating more accurate integration of solar and other renewables.

Connection approvals for the Oyen 2 Solar project and an abbreviated needs identification for the Fort Saskatchewan Path2Zero expansion underscore continued developer activity in renewable generation and industrial decarbonization. Concurrent consultations on high-complexity reliability standards and a 2026 audit schedule aim to align compliance requirements with evolving risks.

Parallel ISO tariff redesign efforts, including stakeholder feedback on transmission reinforcement payment and supply system access service, promise refined cost-allocation mechanisms. These coordinated initiatives carry implications for project costs, timelines and regulatory compliance, offering clearer participation rules, improved modelling expectations and stronger incentives for a cleaner, more resilient grid. Key stakeholder feedback deadlines occur between February and May across multiple initiatives.

References:

Canada’s National Electricity Strategy

Canada is preparing a national electricity strategy to modernize and better connect provincial and territorial grids, target a net‑zero electricity system by 2050, and remove market barriers to interprovincial trade. Rising electrification, electric vehicles, heating, industry growth tied to critical minerals and batteries, plus expanding data centres and AI workloads, could double or triple demand by 2050 and create a projected need for roughly 150 GW of additional firm capacity (about 115 GW non‑emitting baseload and 35 GW flexible supply).

The current mix is largely non‑emitting—hydro ~55.4%, nuclear ~13.9%, wind ~7.5%—though natural‑gas use has increased. Provinces are pursuing varied paths: BC procuring renewable GWh, Ontario investing in nuclear and SMRs, Alberta negotiating nuclear plans and new interties with BC and Saskatchewan.

Ottawa’s draft clean‑electricity rules would cap most fossil generators at 30 tCO2e/GWh by 2035, while offering jurisdictional flexibility (e.g., Alberta’s conditional suspension tied to industrial carbon pricing). Industry and experts emphasize major interprovincial transmission to share renewables and hydro storage value; federal tax credits and funding likely to favor interties.

References:

Alberta to Release Budget 2026 on Feb. 26, Emphasizing Fiscal Discipline

Alberta’s government set Budget 2026 for release on Feb. 26, 2026, framing it as a disciplined response to a tougher fiscal environment driven by declining resource revenue, lower-than-expected oil prices, trade friction and global uncertainty, and growth-related demand for programs and services. Officials say the budget will “live within Alberta’s means,” prioritizing careful spending, targeted revenue measures where necessary, protection of essential services and safeguarding the province’s long-term fiscal position.

President of Treasury Board and Minister of Finance Nate Horner emphasized that tough choices now are required to keep Alberta strong for future generations. Short-term implications point to fiscal restraint, potential spending controls and targeted revenue adjustments; sectors dependent on resource revenue may face outsized impacts. Municipalities, service providers, businesses and residents should expect decisions balancing service protection with spending discipline.

References:

Medicine Hat approves $131.5M Saamis Solar Park

Medicine Hat has approved a $131.5 million municipal investment to build the Saamis Solar Park, a city‑owned solar farm starting at 75 MW that could expand to 325 MW. The city bought DP Energy’s original proposal for $7 million and will finance phase one from its Energy Transition Reserve plus new debt, seeking federal grants that could cover up to 30% subject to Alberta’s approval.

Construction is conditional on signing a confidential energy‑sales agreement and receiving Alberta Utilities Commission approval; officials say operation could begin by 2028 if prerequisites are met. Staff frame Saamis as a commercial investment rather than an environmental subsidy, aiming to diversify generation as local gas fields decline and to stabilize volatile export revenues that fell from $134 million in 2023 to $12 million the following year. Phase one is projected to generate roughly $7 million annually in credits against TIER emissions fees and may help extend the life of municipal gas turbines.

References:

BC’s Power Predicament: U.S. Import Reliance Outpaces Site C

British Columbia faces growing electricity stress: three years as a net importer, 2025 imports (~5,591 GWh) exceed Site C’s expected annual output (~5,100 GWh), and import bills topped $2 billion over two fiscal years. Hydro forecasts demand rising 15%+ by 2030 while a 7,291 MW connection queue—mostly industrial—stresses capacity. Fourteen independent producer proposals totaling ~9,100 GWh (mainly wind) could roughly replace Site C’s energy but are intermittent, unpriced, and years from full operation (2031–33 earliest).

Policy tensions amplify supply risk: EV mandates and limits on natural‑gas heating increase electrification-driven demand while restrictions on gas generation constrain firm backup, prompting debate over using gas as a bridge or reassessing other options. Dependence on U.S. imports raises geopolitical and trade vulnerability if exports are curtailed. BC’s competitive allocation rules for AI/data centres, and its tighter stance versus Alberta/Saskatchewan on gas-fired power, will influence siting and competitiveness.

References:

IEA Electricity 2026 Report — Global Trends and Sector Outlook

The International Energy Agency’s Electricity 2026 report finds that global electricity demand is entering a new era of rapid growth, with consumption forecast to expand significantly through 2030 as electrification accelerates across industry, transport (especially EVs), buildings and digital infrastructure like data centres—outpacing overall economic growth. Renewables (notably solar and wind), nuclear and natural gas are expected to supply the bulk of this increase, while grids face mounting pressure from rising connection queues and the need for flexibility, storage and enhanced transmission to integrate diverse generation resources and evolving demand patterns.

For Canada’s electricity sector, the IEA’s findings reinforce several key themes: strong demand growth from electrification and digital loads will require expanded capacity and flexible resources; grid expansion and modernization—both within provinces and interprovincially—will be critical to avoid bottlenecks similar to those highlighted globally; and the rapid rise of renewables and storage underscores the need for supportive policies and investment frameworks to harness Canada’s abundant clean potential while managing reliability. Canada’s potential for low-carbon exports, cross-border interties, and integration of nuclear (including SMRs) aligns with the global shift toward diversified, decarbonizing power mixes. However, success will depend on overcoming infrastructure constraints, enhancing grid planning, and ensuring price competitiveness as electricity markets evolve in response to the global “age of electricity.”

References:

Proposed 800-km Yukon–B.C. Grid Connection

A proposed 800-kilometre high-voltage transmission line to connect Yukon’s isolated grid to British Columbia promises major economic and energy shifts. Project backers estimate up to $7.6 billion in annual economic activity, as many as 36,000 jobs, and the ability to electrify six diesel-dependent communities, reducing diesel use and costs. The line is being studied in a pre-feasibility phase with funding from the Yukon Development Corporation and Canada’s Critical Mineral Infrastructure Fund.

It also underpins ambitions for up to 19 proposed mines, potentially making large-scale mineral development and export more viable.

References:

Manitoba Hydro's 2025 Integrated Resource Plan

Manitoba Hydro's 2025 integrated resource plan targets adding 1,760 MW over the next decade through a mix of supply-side projects and demand reductions to avoid winter shortages. Near-term steps include three natural-gas turbines in Brandon delivering 750 MW by 2030 and 25 MW of hydro upgrades by 2029 to shore up winter peak capacity.

Longer-term additions rely on Indigenous-led private wind developments that could yield 600 MW under ideal conditions but are accredited at 120 MW for planning, with full build-out taking about nine years to 2035. A 5-MW battery pilot is slated by 2034. Demand-side measures aim to cut peak load by 860 MW, making energy savings a cornerstone of reliability. A recent NERC assessment notes existing U.S. power-sharing contracts postpone mid-winter shortfalls for roughly four years but those agreements expire in 2030, creating a material risk. 

References:

IPPSA's Mandate

IPPSA's Mission is to convene power producers and stakeholders, creating 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.