IPPSA Intelligence

Alberta Electric System Operator

Alberta’s electricity system is entering a busy phase of regulatory updates and market reforms centered on the Retail Electricity Market implementation, adequacy reporting and ISO rule amendments.

Key stakeholder deadlines cluster in early to mid-May with feedback due May 1 on connection-process amendments and the TRP, a virtual session on market-based Fast Frequency Response on May 14, two reliability-standards sync-up submissions by May 15, proposed ‘inflexible block’ rule amendments due May 19 and contact-information updates for REM transition by May 22.

A virtual information session to support market readiness is set for May 20. Meanwhile, the quarterly Long-term Adequacy Metrics will be published May 1, offering data on generation projects, reserve margins and supply cushions to guide resource planning and investment decisions.

Proposed ISO rule changes, particularly the revised ‘inflexible block’ definition and evolving reliability standards, could reshape unit dispatch obligations and market behavior. Stakeholder engagement channels include consultation sessions and coordinated feedback requests designed to streamline input and accelerate implementation.

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MSA Annual Report to the Minister

The MSA’s 2025 report focuses on its surveillance, reporting, enforcement and compliance activities in Alberta’s electricity and retail natural gas markets. In 2025, the MSA restructured its public reporting into separate streams for the wholesale market, retail market, and enforcement/regulatory activities, launched a public Data Portal with 11 data products, and provided comments on AESO initiatives including Fast Frequency Response Plus, proposed REM ISO rules, and the Reliability Standards Sync Up Project.

On enforcement, the report says the MSA’s Enforcement Committee disposed of six matters in 2025, while the MSA addressed 586 ISO rules matters, issuing 145 Notices of Specified Penalty totaling $1.142 million, and handled ARS compliance matters totaling more than $1.54 million in penalties across Operations & Planning and Critical Infrastructure Protection standards. The report also highlights selected matters, including an investigation into battery assets providing spinning reserve, a Rate of Last Resort exit-fee investigation that resulted in no enforcement action, a Direct Energy settlement involving customer information sharing, and two specified penalties issued to the AESO related to Interim Unit Commitment Directives under ISO Rule 206.2.

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AUC Approves TransAlta's 460 MW Natural Gas Plant Near Rimbey

Approval by Alberta’s energy regulator of a 460 MW natural gas-fired plant southwest of Rimbey signals renewed interest in dispatchable power to support supply needs and attract large industrial users such as data centres. Construction is slated for late 2027 with commissioning by 2030. The project will tie into an existing 16-inch gas pipeline and a new transmission line will link it to the provincial grid.

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Medicine Hat's Saamis Solar Moves Forward

The City of Medicine Hat is advancing the Saamis Solar project under four strict preconditions — a satisfactory long-term power sales contract, Alberta Utilities Commission siting approval, council approval of a debenture bylaw, and confirmed access to maximum tax credits via a special purpose vehicle — before committing to the initial 75 MW phase.

Budgeted at $131.5 million with $65.75 million in approved borrowing, financing mixes Energy Transition Reserve funds, debt repaid over 25 years (interest capped at 10%), and tax incentives expected to cover 15–30% of construction costs; municipal rules mean taxes, fees or rates could be used for repayment. Construction spending is slated for 2027 with operation in 2028 after roughly two years of build and an anticipated 30–35 year operational life.

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B.C. Accelerates 'Look West' Strategy

British Columbia’s Look West push frames roughly $88–89 billion in proposed major projects and a target of $200 billion in private investment by 2035, promising tens of thousands of construction and permanent jobs.

Regulatory changes designate the BC Energy Regulator as primary for renewables and major transmission, unlocking projects including BC Hydro’s North Coast Transmission Line—construction slated to start this summer—and about 10 wind/solar projects (~5,000 GWh, ~$6 billion). LNG and pipeline advances (Cedar LNG, Enbridge Sunrise, potential FIDs totaling ~ $50 billion) could raise exports to 19.4 Mt/year by decade’s end and 47.9 Mt with later projects.

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Federal Clean Electricity Plan Delayed

Federal plans to reshape Canada’s electricity and nuclear policies are taking shape but remain unsettled: the promised clean electricity strategy is overdue, with Prime Minister Mark Carney saying only that “it’s coming,” while the spring economic update signals an imminent, separate national nuclear energy strategy.

The government will issue a discussion paper to consult provinces and territories on grid modernization, and Energy Minister Tim Hodgson frames the nuclear plan as a “renaissance” aimed at de-risking investments, enabling public-private financing, advancing Indigenous partnerships and prioritizing economically and strategically sensible projects.

The federal agreement with Alberta includes collaboration on adding nuclear to Alberta’s grid by 2050.

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Alberta AI data centres with onsite gas power sidestep formal impact assessments, sparking concerns

Alberta’s rapid push to host large AI data-centre campuses—like Synapse near Olds, the Woodland Cree-led Mihta Askiy and Wonder Valley—has exposed regulatory gaps as some projects tied to major onsite natural-gas generation have avoided formal environmental impact assessments. Provincial law (EPEA) doesn’t explicitly define data centres, and natural-gas plants aren’t listed as mandatory EIA triggers, leaving assessment decisions discretionary.

The federal Impact Assessment Agency issued a “no further assessment” for Mihta Askiy, and provincial officials told Synapse no provincial EIA was required, though proponents must still obtain permits and technical air, land and water studies.

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Capital Power Q1 2026

Capital Power reported Q1 2026 results and actions that strengthen contracted revenue visibility and support its diversified generation strategy. Q1 financials showed AFFO of $154 million, operating cash flow of $312 million, adjusted EBITDA of $404 million and net income of $15 million; a dividend of $0.6910 per common share was declared and Kevin MacIntosh became CFO effective March 16, 2026.

2026 targets include sustaining capex of $290–$330 million (Q1 spend $107 million), AFFO of $890–$1,010 million and adjusted EBITDA of $1,565–$1,765 million. Management emphasized long-term contracting with creditworthy counterparties, active trading risk management and portfolio diversification across natural gas, renewables and battery storage, noting improving Alberta fundamentals and attractive PJM prospects.

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TransAlta’s new CEO Joel Hunter targets Alberta AI data-centre boom

Joel Hunter becomes CEO of TransAlta as the company targets Alberta’s expanding AI/data-centre market, leveraging surplus power, gas resources and the 12,000-acre Keephills site under an MOU with Brookfield and CPP Investments. Alberta’s federal-provincial MOU and provincial policy framework aim to attract sovereign cloud and AI investment by aligning new generation with net-zero electricity goals to 2050, while pausing federal Clean Electricity Regulations pending carbon-pricing talks.

TransAlta plans an initial 230 MW PPA at Keephills with phased potential to 1,000 MW, timing tied to customer demand and definitive agreements for 2027–28. AESO’s proposals to allocate up to 1,200 MW of surplus grid power to data centres and to enable developer-generator partnerships reflect market redesign intended to unlock dedicated supply.

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AltaLink launches provincially funded 113-km Dynamic Line Rating pilot

AltaLink will deploy Dynamic Line Rating (DLR) across a 113-kilometre southern Alberta transmission corridor, backed by more than $1.8 million from Emissions Reduction Alberta/TIER, as a faster, lower-cost alternative to building new lines. DLR replaces conservative static ratings with real-time capacity calculations using conductor sensors and weather stations—especially wind and temperature—to raise usable transfer capability typically 15–30%, and in some conditions up to 45%.

The 2026 demonstration aims to validate hardware, data flow and control algorithms and inform wider rollout. Alberta faces sustained load growth (~1.2% annually) and more than 16,000 MW of connection requests driven by data centres and electrification; DLR is positioned as a “non-wires” solution to ease congestion, defer costly transmission projects and lower ratepayer capital outlays. 

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Manitoba bills let Hydro curtail crypto miners and charge data centres to protect the power grid by Brandon Sun

Manitoba is moving to curb energy-intensive tech by empowering Manitoba Hydro to manage large electricity users through two bills: Bill 20 permits temporary curtailment of cryptocurrency miners to protect grid stability, and Bill 39 allows Hydro to charge crypto operations and data centres up to twice standard rates.

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PJM Reopens Interconnection Queue After Freeze, Draws 800+ Applications

PJM Interconnection’s reopening of its application queue after a 2022 freeze highlights the strain on U.S. transmission planning as power demand surges, especially from data centers. Over 800 projects applied by the deadline, spanning 349 battery-storage proposals, 157 natural-gas plants, 142 solar farms, 65 wind farms, 45 solar-storage hybrids, 45 nuclear projects, 11 hydro projects and other types, representing roughly 220 gigawatts of potential capacity.

PJM processed a 170 GW backlog by end-2025 but only about 31% of that capacity secured offers or signed connection agreements, underscoring the gap between applications and built capacity. The technology mix points to continued growth in low-carbon resources — batteries, solar, wind and hybrids — alongside substantial gas and some nuclear, revealing a mixed transition path.

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Canada funds $40-million study of microreactors to power remote northern military sites as national nuclear strategy advances by The Globe and Mail

The federal government is funding a $40-million Department of National Defence study to evaluate microreactors as heat and power sources for remote northern military facilities, with Atomic Energy of Canada Ltd. participating. Microreactors are compact, transportable units producing under 20 MW thermal that could supply heat directly or be converted to electricity; factory mass production remains unrealized.

Canadian startups like Boreal Energy Systems (1-MW Micro Modular Reactor) and Prodigy Clean Energy (barge-style transportable plant) target defence and Arctic markets, with past federal grants supporting development. Russia’s Akademik Lomonosov exemplifies maritime high-latitude nuclear power, but Arctic nuclear use is otherwise uncommon. Minister Tim Hodgson says a comprehensive national nuclear energy strategy will soon aim to support domestic construction of small and large reactors, boost exports of Canadian technology, and promote Canadian uranium.

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Boundary Dam Unit 4 Restart Adds ~150 MW of Baseload to Support Bell Data Centre and Highlights Saskatchewan–Federal Coal Policy Clash by Pipeline Online

Boundary Dam Unit 4 was restarted on April 22, 2026, after an intensive refurbishment and recertification that restored roughly 150 MW of dispatchable baseload capacity. The immediate goal is grid reliability and to underpin a planned ~300 MW Bell Canada data-centre near Regina; the government argues refurbished coal is a cheaper short-term option than building new gas plants.

Ottawa’s federal coal rules mandate 50-year retirements, while Saskatchewan’s Saskatchewan First Act and Energy and Security Strategy assert provincial authority, commit to returning several coal units through 2035, and target 3,000 MW of wind and solar plus eventual nuclear—creating regulatory friction.

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Indigenous Equity in Canadian Energy (2024–2026 YTD)

Indigenous equity participation in Canadian energy and infrastructure has expanded markedly in 2024–2026 YTD, with nearly 200 projects tracked and roughly 30% announced during this period. Ontario and British Columbia lead activity (32% and 25% of announcements) driven by IESO procurement incentives, Ontario’s Indigenous Opportunities Financing Program and Hydro One partnership models, and BC Hydro Calls for Power supported by federal loan guarantees. Saskatchewan and the Maritimes show growing activity; Alberta’s share slipped amid regulatory uncertainty.

Solar now dominates new investments (46%, up from 18%), wind accounts for 29%, hydro has declined, and emerging categories include AI data centres, transmission, storage and battery projects. Average project sizes rose substantially—wind to ~145.9 MW and solar to ~52.9 MW—while ownership trends favor control: 43% are majority Indigenous-owned, 31% 50/50 partnerships and 10% wholly Indigenous.

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