IPPSA Intelligence

Alberta Electric System Operator

Recent AESO proposals aim to align electricity market rules with real-time transmission constraints by ensuring that the system marginal price (SMP) accurately captures the cost of redeploying the marginal asset during constrained operations. Key amendments to ISO rules involve Section 302.1 (Real-Time Transmission Constraint Management), Section 201.6 (Pricing), Section 103.4 (Power Pool Financial Settlement) and Section 202.7 (Market Suspension or Limited Market Operation), along with necessary administrative edits for consistency.

By reflecting constrained dispatch in pricing and settlements, these changes intend to sharpen market signals under network congestion, thereby influencing bidding strategies, hedging instruments such as Financial Transmission Rights (FTRs), and revenue outcomes for participants.

Stakeholder engagement is structured around several upcoming sessions and deadlines: expressions of interest and scorecard evaluations are due by February 17, FTR discussions occur February 25–26, a Reliability Standard Synchronous Generation update follows on March 5, and comments on the Reliability Standards Sync Up project close May 1.

The proposed rule modifications carry economic and operational significance by clarifying dispatch and pricing mechanisms, reducing dispatch uncertainty, and reinforcing transparent settlement processes under constrained system conditions, ensuring stakeholder alignment and fostering consensus.

References:

Alberta Utilities Commission

The AUC is overseeing multiple energy infrastructure proposals spanning power generation, transmission, storage and pipeline projects. Among initiatives under review is the Beacon AI Centers–Indus thermal power plant transmission line, while the Big Rock Solar project, encompassing a photovoltaic plant, energy storage facility and substation, remains in abeyance pending further assessment.

In contrast, the Oyen 1 and Oyen 2 solar developments have secured approval for both generation and distribution components. These applications illustrate a transparent regulatory framework that categorizes projects by status—under review, in abeyance and approved—offering stakeholders clear visibility into each proposal’s progression. 

Industry participants, policymakers and the public benefit from this clarity, as it informs decision-making, highlights bottlenecks and shapes future policy direction. Continued regulatory engagement will be pivotal in meeting Alberta’s evolving energy demands and achieving long-term sustainability goals.

References:

Proposed $10B Synapse data centre prompts community concern and regulatory review

Synapse Data Centre Inc. has proposed a $10 billion, 1 GW, 2 million-sq. ft. data centre paired with a 1.4 GW natural gas-fired power plant. Rezoning of 300 acres from future urban to light industrial was approved and a development permit applied for. The Alberta Utilities Commission participant involvement sessions have concluded and a formal AUC application is planned. Construction could take 18–24 months, with municipal and provincial approvals expected by March and September. T

The project promises about 2,000 construction and 1,000 permanent jobs, with PwC-estimated spin-offs of up to 7,000 roles. An on-site gas plant will operate off-grid, sourcing local gas to avoid grid impacts. Synapse claims optimized noise and emissions, closed-circuit cooling to slash water use, and landscaping buffers to minimize visual effects. Public sessions drew strong interest but also concerns over noise, emissions, water, housing, services and infrastructure capacity, tax contributions and company experience.

References:

Proposed 1,600‑acre Villeneuve solar and 100MW battery project

Proposed a 1,600‑acre solar-plus-storage project near Villeneuve, Alberta would deploy about 373,000 panels and a 100 MW battery sized for roughly four hours, aiming to power roughly 60,000 homes and offset about 145,000 tonnes of CO2 annually. The $300 million development emphasizes agrivoltaics—panels covering ~35% of land with spacing for crops and livestock—and uses single-axis trackers, screw‑pile foundations and adjustable tilt for glare control and snow shedding.

Developers forecast 300–500 construction jobs and 15–20 permanent positions, a 40‑year operating life and a decommissioning bond; panels would be recyclable or resold. Transmission routing by AltaLink presents multiple corridor options and has provoked resident concerns about visual impact, tree removal and loss of farmland; the developer proposes screening and further consultations. 

References:

Datacenters Drive 2026 Energy Investment

RBC writes that tising electricity demand—driven largely by datacenter buildouts and broader electrification—is setting up a multi‑year infrastructure expansion where an “all‑of‑the‑above” mix of natural gas, renewables and nuclear will be needed. Datacenters could account for roughly 75% of power demand growth through 2030, creating value for utilities with regulated footprints, visible long‑duration load growth and brownfield expansion opportunities.

Affordability and tariff design are politically sensitive, forcing regulators and utilities to balance investor protections (minimum volumes, termination clauses) with ratepayer fairness. Regional nuance matters: Europe is adapting post‑Russia import dynamics and boosting storage, Canada’s provincial procurement supports projects, and Australia/New Zealand face fiscal and economic limits that constrain private appetite.

References:

KALiNA and Crusoe to Co‑Locate AI Data Centres with 170 MW Power‑CCS Plants in Alberta

KALiNA Power and Crusoe plan co‑located AI data centres paired with KALiNA’s modular 170 MW combined‑cycle “Power‑CCS” plants in Alberta, under a multi‑year framework of separate project development agreements and 15‑year power purchase agreements. The model uses co‑location and long‑term PPAs to provide stable cashflows for financing potentially up to about 1.7 GW of capacity across multiple sites. The combined‑cycle plants are designed to capture roughly 95% of CO2 with sequestration into authorised deep aquifers, aligning plant siting with transmission, gas pipelines, fibre and sequestration hubs.

AESO system access service requests and environmental desktop studies are advanced for initial sites, with further permitting, PDAs and financing needed before final investment decisions.

References:

Alberta–Montana Electricity Dispute

Alberta’s shift from coal to wind and solar is reshaping grid dynamics and triggering a cross-border trade dispute with Montana after Alberta adopted market rules that sometimes curtail imports during local renewable-driven surpluses. Premier Danielle Smith defends the changes as neutral, necessary grid management applied equally to all suppliers; Montana politicians and firms, including senators Steve Daines and Tim Sheehy and a Berkshire Hathaway unit, allege discrimination and filed complaints with regulators and U.S. trade officials. USTR Jamieson Greer has raised the matter in the CUSMA review.

Economists characterize the clash largely as a technical integration problem: intermittent generation creates surplus/deficit patterns that demand transmission upgrades and coordination. Jack Mintz recommends roughly $500 million in cross‑border transmission investment, potentially with negotiated cost‑sharing, to ensure fair access and stability.

References:

Maxim Power reserves GE Vernova 7HA.02 turbine slot for 400 MW Prairie Lights project; plans up to CAD 60M spending in 2026

Maxim Power has reserved a manufacturing slot with GE Vernova for a 7HA.02 heavy‑duty gas turbine aimed at its permitted 400 MW Prairie Lights project near Grande Prairie, Alberta, targeting delivery by 2030. The reservation requires a non‑refundable deposit in 2026 that would be credited if a definitive purchase agreement is executed; the reservation secures timing but not final price or sale. Maxim plans up to CAD 60 million of project spending in 2026 and reports roughly CAD 84 million of available liquidity, including about CAD 59 million unrestricted cash, intending to fund near‑term work from cash on hand and operating cash flow.

An amendment to existing permits is required but expected to be routine because the 7HA.02 is an updated model of the approved turbine. The move anchors procurement and helps de‑risk schedule and permitting, aligning with provincial and federal emphasis on reliable, dispatchable generation.

References:

Nova Scotia Power appoints new CEO amid cyberattack fallout, regulatory probes and contested rate hikes

Nova Scotia Power is replacing CEO Peter Gregg with Vivek Sood on March 1 as the utility confronts fallout from a March 2025 cyberattack, proposed residential rate increases and multiple regulatory probes. Gregg will move to Emera as vice‑president of strategy and policy; the board highlighted Sood’s business experience and local ties. The breach exposed data for about 280,000 customers, disrupted meter communications and billing, and forced estimated usage for many accounts; the company reported roughly 75% of smart meters working by January 2026 with full restoration expected the following month.

The Nova Scotia Energy Board will hold hearings on technical aspects and on billing, data storage and identity protection, while the Office of the Privacy Commissioner and a proposed class action pursue investigations alleging governance failures and inaccurate billing. Nova Scotia Power seeks approximately an 8% residential rate increase (3.8% retroactive to Jan. 1, 2026; 4.1% on Jan. 1, 2027), which provincial officials and opposition parties urge regulators to reject amid affordability concerns.

References:

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.