IPPSA Intelligence

Alberta Electric System Operator (AESO)

Alberta’s electricity system operator is coordinating multiple stakeholder consultations and technical sessions to advance market design, procurement, and grid development. Near-term deadlines in September and October invite feedback on fast frequency response (FFR+) product and procurement design, transmission-connected data centre connection requirements, and ancillary services cost-allocation for frequency response products. A hybrid technical session on the Restructured Energy Market ISO rules will shape tariff redesign and reliability standards. Market participants can also learn about incumbency treatment implementations and one-time Generating Unit Owner’s Commitment refunds.

Concurrently, the AESO published a Need Overview for the Little Smoky 1 Solar project, reflecting ongoing renewable generation growth in the Valleyview area. These initiatives underscore a shift toward integrating variable resources while ensuring system reliability through innovative frequency response services.

Data centre operators, developers, and generators must engage by specified deadlines to influence technical and commercial obligations, cost recovery mechanisms, and market rules. Policy decisions on cost allocation will determine who funds new reliability services amid increasing renewable penetration. This coordinated approach aims to balance economic efficiency, equitable cost sharing, and environmental benefits as Alberta’s grid evolves to accommodate modern loads and the next generation of energy projects.

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Alberta TIER Revisions

The Government of Alberta announced a fall 2025 update to its Technology Innovation and Emissions Reduction (TIER) system to recognize on‑site emissions‑reduction investments as an accepted compliance route, alongside paying into the TIER fund or buying credits, and to allow smaller facilities to opt out for 2025. The government frames the changes as measures to boost competitiveness, protect jobs and attract capital while seeking federal alignment on timelines and rules.

TIER, launched in 2007 and covering roughly 60% of provincial emissions, requires facilities emitting 100,000 tonnes or more annually to meet reduction targets; current compliance options include offsets, performance credits, sequestration tonnes or paying $95/tonne.

Since 2019 about $1.6 billion from TIER has funded geothermal, hydrogen, energy storage, methane reduction and carbon capture projects projected to cut about 70 million tonnes by 2030 and support roughly 21,000 jobs. If on‑site investments are clearly defined, measured and verified, they could spur local capital spending, technology deployment and jobs; however effectiveness hinges on eligibility criteria, monitoring and federal integration.

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Revolve Secures AUC Approval for 15.7 MW Bright Meadows Solar Project

Revolve Renewable Power’s subsidiary obtained Power Plant Approval from the Alberta Utilities Commission for its 15.7 MW Bright Meadows Solar Project near Wetaskiwin, Alberta. Employing agrivoltaics, the design integrates solar panels with ongoing agricultural activities to optimize land use and foster local support. The approval unlocks construction and operation pending final interconnection and local permits.

Construction is slated to begin in mid-2026, aiming for commercial operation by year-end. While promising modest revenue growth for Revolve and environmental benefits, timelines and outcomes remain contingent on regulatory, financing, and construction risks. Stakeholders await detailed commercial arrangements to de-risk successful execution.

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SMRs and CCS as a 'Grand Bargain'

Christopher Worswick opines that Canada faces a policy choice of marrying oil‑sands development with deep emissions reductions by deploying a mix of low‑carbon technologies—notably small modular reactors (SMRs) and carbon capture and storage (CCS). SMRs are promoted as a pragmatic source of continuous, low‑carbon heat and power that could replace natural gas in upgrading and extraction, targeting roughly 43% of oil‑sands emissions tied to on‑site heat and electricity; lifecycle emissions from nuclear are presented as a small fraction of natural gas.

CCS at sites like Cold Lake remains important but limited at scale, while solar and batteries struggle to meet 24/7 industrial demand and face mineral‑supply constraints; hydro can help where economically feasible. A proposed federal–Alberta “grand bargain” would link temporary regulatory flexibility and pipeline approvals to provincial commitments to deploy SMRs/CCS, theoretically lowering net greenhouse gases while enabling expanded production.

Benefits include faster industrial decarbonization and potential SMR industrial policy gains for Canada; risks center on deployment cost, timelines, regulatory design, and ensuring promised emissions cuts materialize. 

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Maxim Power Wins TSX Approval for 5% NCIB

Maxim Power Corp. announced that the Toronto Stock Exchange approved a normal course issuer bid allowing the company to repurchase and cancel up to 3,182,528 common shares, roughly 5% of shares outstanding, from Sept. 16, 2025 to Sept. 15, 2026. Purchases will be executed by a registered broker on the TSX and Canadian alternative trading systems at market prices, subject to a daily cap of 1,853 shares (25% of the six‑month average daily volume) with one weekly block purchase permitted.

Maxim is advancing a permitted gas project and pursuing wind permitting in Alberta. The NCIB is a routine capital‑markets tool that modestly reduces share count, can support per‑share metrics, and signals management confidence amid ongoing development in Alberta.

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So You Want to Supply Your Own Power

Bennett Jones writes that since Alberta’s “self-supply” amendments came into force in March 2024, interest in on-site power generation by industrial and commercial users has surged, particularly among data centres and crypto mining operations. Under the Electric Utilities Act (s. 2(1)(b)), a person may generate electricity on their own or leased property and use it solely on that property without being bound by the requirement to trade through the provincial grid.

However, several legal and regulatory constraints remain: generation and load must be co-located on contiguous land, ownership structures and definitions of “that person” must be clear, and eligibility for exemptions like Industrial System Designation (ISD) is restrictive and mainly geared toward generation with useful thermal output. A recent Alberta Utilities Commission decision (McCain Foods’ Coaldale) underscored the narrow interpretations being applied, especially where infrastructure crosses roads or third-party land.

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Capstone Commissions Wild Rose 2 Wind Farm 

Capstone Infrastructure has commissioned the 192 MW Wild Rose 2 wind farm in Cypress County, Alberta, its largest project to date, bringing the company’s operating fleet past 1 GW across 36 facilities. Offtake arrangements include a 15‑year power purchase agreement with Pembina Pipeline for 105 MW of energy and associated renewable attributes, and a 20‑year Renewable Attributes Purchase Agreement with the City of Edmonton for 78 MW — described as Canada’s largest long‑term municipal procurement of renewable attributes — supporting Edmonton’s corporate carbon neutrality by 2040 and community net‑zero by 2050 targets.

Natural Resources Canada supported the project through its Smart Renewables and Electrification Pathways Program, illustrating federal de‑risking and policy alignment with low‑carbon goals. Investors, municipalities and corporations are likely to increase similar engagements as policy incentives persist and markets mature.

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Energy Storage Canadian Market Outlook

Energy Storage Canada released The Canadian Storage Outlook this week that warns that Canada faces urgent electricity supply challenges as demand surges from electrification of housing, industry, transport, and data centres.  Shortfalls are already affecting investment: in Ontario, Québec and Atlantic Canada, some industrial growth is being turned away because of resource adequacy and reliability constraints. Energy storage (both short- and long-duration) is presented as a key enabler for decarbonization, cost containment, and grid reliability: to firm up intermittent renewables, avoid costly infrastructure deferrals, and provide ancillary and capacity services.

The report shows that Ontario and Alberta lead in installed and committed energy storage capacity, with over 2,800 MW contracted/planned in Ontario alone, while provinces like British Columbia, Québec, Saskatchewan, and the Atlantic provinces have significant untapped potential. Costs for battery‐based and other storage technologies are expected to keep declining through the decade, improving economics and competitiveness relative to gas-fired generation. To unlock that potential, the report calls for clearer regulatory and market frameworks, streamlined permitting, dedicated procurements, and market designs that accommodate storage’s flexibility and multi service value.

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Manitoba Hydro seeks nearly 11% electricity hike for 2026–28

Manitobans face rising utility bills as regulators and utilities move to shore up finances and fund infrastructure. Manitoba Hydro filed a General Rate Application proposing roughly 3.5% average electricity-rate increases per year for 2026–2028 (about 11% cumulative) beginning Jan. 1, 2026. The government frames these steps as necessary to maintain infrastructure, reliability and avoid sudden shocks, while regulators balance utility viability against consumer affordability.

The Public Utilities Board approved multi‑year distribution revenue increases for Centra Gas — a 4.5% rise effective Nov. 1, 2024, another 4.5% on Nov. 1, 2025, and 4.0% on Nov. 1, 2026 — measures aimed at stemming Centra’s losses (a $34 million net loss in 2023/24). Those increases apply to distribution (delivery) charges only; natural gas commodity prices are adjusted separately, so headline percentages will have smaller effects on total bills.

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AI-fueled data-center boom strains U.S. power grids

Rapid growth of Big Tech data centers, accelerated by generative AI, is straining U.S. grids and forcing policymakers, grid operators and utilities to consider limits on data‑center power during emergencies. States such as Texas have passed laws giving utilities authority to curtail large users, and PJM and the Southwest Power Pool are proposing or expanding rules that could deny guaranteed power or require participation in emergency reduction programs. Industry pushes back with efficiency claims, backup generators and calls for voluntary, incentivized curtailment rather than rigid mandates.

Tests and studies show steep projected demand increases in hotspots like Virginia, Ohio, Pennsylvania and Texas, prompting debate over whether to build new generation and transmission for brief peak hours or rely on demand flexibility and on‑site generation. 

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Blackstone Announces Agreement to Acquire Hill Top Energy Center

Blackstone’s Energy Transition Partners has signed a definitive agreement to acquire the Hill Top Energy Center, a 620 MW combined‐cycle natural gas plant in Greene County, Western Pennsylvania, from Ardian for nearly US$1 billion. The plant, commissioned in 2021, is one of the most efficient of its kind in the U.S. and is strategically located to serve growing demand in the PJM electricity market, especially from data centres and other AI-driven infrastructure.

This deal complements Blackstone’s broader plan to invest over US$25 billion in Pennsylvania’s digital and energy infrastructure (with a goal to catalyze a further US$60 billion into the commonwealth), reinforcing its conviction in energy infrastructure as a key enabler of the AI future.

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Capital Power and Consumers Energy sign 2040 PPA

Capital Power and Consumers Energy have agreed a long-term power purchase agreement securing contracted payments for 1,240 MW of Midland Cogeneration Venture capacity — roughly 75% of the plant — beginning June 2030 and extending to 2040. The deal provides ten years of incremental contracted revenue for MCV, a major natural-gas-fired combined heat and power facility critical to Michigan’s MISO grid.

Realization depends on assumptions about electricity, fuel and carbon prices, regulatory approvals including the Michigan Public Service Commission, and operational performance. Risks include market volatility, policy or regulatory changes, supply‑chain or plant issues, and broader technological shifts. 

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CFE Sells Bonds to Finance Mexico’s Electricity Transmission Grid Upgrades

Mexico’s state utility CFE sold bonds to finance transmission network upgrades, highlighting a shift toward capital markets financing for grid investment. The transaction—likely detailed in tenor, coupon, currency and structure—illustrates how utilities are tapping debt markets rather than relying on budgetary allocations to accelerate new lines, substations and system reinforcements needed to improve reliability and integrate more generation, including renewables.

Using bond proceeds for transmission can reduce bottlenecks, lower curtailment of low carbon power and facilitate energy transition, while exposing CFE to execution, political and market risks such as currency and interest rate volatility. 

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