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Canada federal: 5 energy policy briefs

The energy policies moving Canada federal’s power markets, one brief each: the problem, the mechanism, the market effect, who gains and who pays, where it stands on the path to binding law, and the official text.

Alberta Restructured Energy Market (REM) · real-time locational pricing, scarcity pricing and market-power mitigation

Canada · Alberta · Government of Alberta and Alberta Electric System Operator · decision · 2026

Where it stands: REM ISO rules approved by the Minister 12 March 2026 (AR 51/2026); participant readiness and market trials under way; go-live targeted mid-2027; interim mitigation in force to 30 November 2027

Alberta is rebuilding its energy-only market: interim supply-cushion and offer-mitigation rules already cap prices when supply is tight, and the AESO's REM design, whose ISO rules the Minister approved in March 2026, moves to real-time locational marginal pricing with scarcity pricing, an enhanced day-ahead market for operating reserves, tighter conduct rules and a reliability backstop, with go-live targeted for mid-2027.

The problem

Alberta's energy-only market delivered record prices in 2022 and 2023 (annual pool averages of C$162.46/MWh in 2022 and C$133.63/MWh in 2023) that the government attributed partly to economic withholding by large generators when the supply cushion was thin, alongside rapid renewable growth that the AESO said threatened reliability. Rather than add a capacity market (cancelled in 2019), the province on 11 March 2024 directed the AESO to redesign the energy-only market with stronger mitigation and firmer scheduling, while keeping investment signals for dispatchable generation.

What it does

Two layers. Interim measures under two regulations in force since 11 March 2024 (the Supply Cushion Regulation, AR 42/2024, and the Market Power Mitigation Regulation, AR 43/2024, implemented through ISO rules 206.1 and 206.2 from 1 July 2024) require offers to reflect available capacity, let the AESO direct long-lead-time units to commit when the supply cushion falls below 932 MW, and cap offers from suppliers controlling 5 percent or more of Alberta's generating capability at the greater of C$125/MWh or 25 times the day-ahead gas price once a reference unit's monthly net revenue exceeds one-sixth of its annual unavoidable costs; renewables and storage are exempt and both regulations expire on 30 November 2027. The AESO's final REM design, published in 2025 after stakeholder consultation and government direction, replaces the single pool price with real-time locational marginal pricing, adds scarcity pricing (an energy offer cap of C$1,500/MWh rising to C$2,000/MWh in 2032 and an overall price cap of C$3,000/MWh, with a floor falling from C$0 to minus C$100/MWh by 2032), an enhanced day-ahead market for operating reserves, new reserve products, market-power mitigation through offer caps triggered by conduct and impact tests, and a reliability backstop for the AESO to secure supply when the market falls short; the day-ahead energy commitment market in earlier drafts was dropped. The REM ISO rules were submitted to the government in January 2026, approved by the Minister on 12 March 2026 under section 20.01 of the Electric Utilities Act and adopted by the Restructured Energy Market ISO Rules Regulation (AR 51/2026); the remaining rules come into force on a date the AESO fixes with at least 30 days' notice, with go-live targeted for mid-2027.

Market effect

The interim mitigation has already compressed Alberta pool prices: the 2024 average fell to C$62.78/MWh and 2025 to C$43.68/MWh, and hourly spikes to the C$999.99 cap have become rare when the cushion is thin. That lowers merchant revenue for gas plants, which is why the design pairs mitigation with a reliability backstop and why generators warn of an investment gap. Locational marginal pricing exposes generators in congested areas to local prices, the enhanced day-ahead market for operating reserves gives dispatchable units firm reserve commitments, and scarcity pricing rather than a flat C$999.99 cap sets the value of firm capacity in tight hours. For renewables, the interim rules and the parallel 2024 restrictions on siting (agricultural land, viewscapes, pristine viewsheds) and the transmission cost-allocation reforms under the Transmission Regulation review raise costs and delay projects. The overall direction is toward a lower, less volatile price with firmer scheduling and more administered elements.

Key numbers

Price cap
C$999.99/MWh offer cap today; REM energy offer cap C$1,500/MWh (C$2,000 in 2032), overall price cap C$3,000/MWh
Target go-live
Mid-2027
Government direction and interim regulations
11 March 2024 (AR 42/2024 and AR 43/2024, expiring 30 November 2027)
REM ISO rules approved
12 March 2026 by the Minister (AR 51/2026)
Average pool price
C$162.46/MWh (2022), C$133.63 (2023), C$62.78 (2024), C$43.68 (2025)

Who gains and who pays

  • Large generators (TransAlta, Capital Power, Heartland, ENMAX) (costs): Offer caps and conduct tests limit scarcity margins; scarcity pricing and reserve products add firm revenue.
  • Renewable developers (costs): Lower pool prices, siting limits and transmission cost changes weaken merchant economics.
  • Industrial consumers and retailers (gains): Lower, less volatile wholesale prices; locational prices vary by region.
  • AESO (obligation): Must deliver locational pricing systems, mitigation tools and a reliability backstop by mid-2027.
  • Storage and flexible resources (mixed): Co-optimised reserves create revenue; compressed spreads reduce arbitrage.

Implementation

Interim supply-cushion and mitigation regulations are in force until 30 November 2027. The REM ISO rules were approved by the Minister on 12 March 2026 and adopted by regulation (AR 51/2026); the AESO is running market-participant readiness, certification and market trials (materials posted September 2026) and will give at least 30 days' notice of the day the remaining rules take effect, with go-live targeted for mid-2027. The Minister can approve amendments or suspend rules for market-transition errors under the regulation. In parallel the Transmission Regulation review is changing how transmission costs are allocated to generators. Check the AESO REM page for the current schedule; slippage is possible.

Concerns

  • Under-investment in dispatchable capacity if mitigation removes scarcity rents without a capacity payment
  • Regulatory risk from ministerial direction overriding the AESO process
  • Implementation and software risk for a 2027 day-ahead launch
  • Renewable investment slowdown from combined siting, pricing and transmission changes
  • Interaction with the federal Clean Electricity Regulations and the Alberta alternative

Dates to watch

  • 2027: Targeted mid-2027 go-live of the REM (real-time locational pricing)
  • 30 November 2027: Interim supply-cushion and market-power mitigation regulations expire

Sources

Checked against sources on .

Bill C-5 · One Canadian Economy Act (Building Canada Act) for national-interest projects

Canada federal · Parliament of Canada · statute · 2025

Where it stands: In force; Major Projects Office operating; first national-interest projects listed and conditions being set

Enacted in June 2025, the Building Canada Act lets Cabinet designate national-interest projects (pipelines, transmission, ports, mines, nuclear) and deem them approved, collapsing federal reviews into a single conditions-setting process with a two-year target and a Major Projects Office.

The problem

Canada's federal review regime (the Impact Assessment Act, Canada Energy Regulator hearings, Fisheries Act and species-at-risk permits) took five to ten years for major energy infrastructure, and the 2023 Supreme Court reference found parts of the Impact Assessment Act unconstitutional. In 2025, facing US tariffs, the new government promised to make Canada an energy superpower and to build interprovincial trade and infrastructure quickly, needing a legal tool to override the sequential permitting regime.

What it does

Bill C-5 received Royal Assent on 26 June 2025 after passing both Houses in under a month. Part 1 (Free Trade and Labour Mobility in Canada Act) removes federal barriers to interprovincial trade and labour mobility. Part 2, the Building Canada Act, allows the Governor in Council, after consulting provinces, territories and Indigenous peoples, to list a project as being in the national interest based on criteria such as strengthening autonomy and security, economic benefit, clean growth and Indigenous participation. Once listed, the project is deemed to have received the authorisations it needs under listed federal statutes, and a single conditions document sets out the terms, replacing separate decisions. A Major Projects Office coordinates reviews with a two-year target, and an Indigenous Advisory Council is created. The national-interest listing power sunsets after five years unless renewed. The first projects (including LNG expansion, a port, nuclear and mining projects, and critical-minerals corridors) were referred in late 2025.

Market effect

For power markets the act matters through transmission and generation: interprovincial transmission lines, nuclear new-build (Ontario's large nuclear and SMR projects, Alberta and Saskatchewan SMRs) and hydro or wind corridors can be listed and moved on a fixed clock, which shortens the time-to-revenue in project finance and lowers the permitting risk premium. For gas and oil, an accelerated pipeline (a West Coast oil pipeline and LNG capacity are the main candidates) changes Western Canadian Select differentials and gas basis in the long run. The act does not remove provincial approvals, and Indigenous consent is a constitutional constraint the act tries to internalise through the advisory council and consultation, so litigation risk moves rather than disappears. Investors should treat listing as a strong signal but not a completed permit.

Key numbers

Royal Assent
26 June 2025
Review target
Two years for listed national-interest projects
Sunset
Listing power expires after five years unless renewed
Coordination body
Major Projects Office

Who gains and who pays

  • Transmission, nuclear and pipeline proponents (gains): Deemed federal approvals and a two-year review target for listed projects.
  • Indigenous nations (mixed): Consultation duties preserved and an advisory council created; concerns about consent and pace.
  • Provinces (mixed): Provincial approvals still required; can champion projects for listing.
  • Federal regulators (IAAC, CER) (obligation): Reviews consolidated under the Major Projects Office and conditions documents.
  • Environmental and legal challengers (costs): Fewer decision points to challenge; scrutiny shifts to the listing decision.

Implementation

The Major Projects Office was established in 2025 and the first tranche of national-interest projects was referred and listed in late 2025, with further tranches expected through 2026. Regulations and the conditions documents for each listed project are the operative instruments. Legal challenges by Indigenous groups on consultation grounds are possible and would test the deemed-approval mechanism. For electricity, watch which transmission and nuclear projects are listed and the conditions attached.

Concerns

  • Constitutional challenges on the duty to consult and accommodate Indigenous peoples
  • Environmental review quality when approvals are deemed rather than decided
  • Politicisation of project selection
  • Provincial approvals and municipal permits remaining as bottlenecks
  • Five-year sunset creating a rush of listings

Dates to watch

  • 2026: Further national-interest project listings, including transmission and nuclear
  • 2030-06: Sunset of the listing power unless renewed

Sources

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Ontario Market Renewal Program · renewed day-ahead and real-time markets (launched May 2025)

Canada · Ontario · Independent Electricity System Operator · decision · 2025

Where it stands: Renewed market live since 1 May 2025; first-year review and rule refinements under way

On 1 May 2025 Ontario replaced its two-schedule uniform-price market with a financially binding day-ahead market and a single-schedule real-time market using locational marginal prices, ending the Hourly Ontario Energy Price and most congestion make-whole payments.

The problem

Since 2002 Ontario ran a two-schedule market: an unconstrained schedule set a uniform Hourly Ontario Energy Price (HOEP) while a constrained schedule actually dispatched units, with the difference paid out as Congestion Management Settlement Credits and other uplifts that reached hundreds of millions of dollars a year. Prices did not reflect location or real constraints, day-ahead commitments were not financially binding, and the system relied on out-of-market payments to keep gas units available.

What it does

The Market Renewal Program, approved through IESO Market Rule amendments reviewed by the Ontario Energy Board, launched on 1 May 2025 after a decade of design and a series of go-live deferrals. It introduces a day-ahead market with financially binding schedules and day-ahead prices, a single-schedule real-time market that produces locational marginal prices for generators (with a load-weighted zonal price for most loads), and an enhanced real-time unit commitment process that replaces the previous day-ahead commitment process. Make-whole payments are narrowed to guarantee cost recovery only where the market price does not cover a committed unit's offered costs. The Ontario Electricity Rebate and the Global Adjustment continue to determine most of what consumers pay, so the renewal changes wholesale price formation rather than retail bills directly.

Market effect

Locational prices expose congestion into the Greater Toronto Area and around the northern and eastern interfaces that HOEP hid, creating basis between Ontario zones for the first time and making the day-ahead versus real-time spread a tradable quantity. Financially binding day-ahead schedules let gas generators and imports lock in commitments and reduce the out-of-market uplift that used to be socialised. Because most Ontario supply is under contract or regulated (nuclear, hydro, contracted gas and renewables) and consumers pay the Global Adjustment, the wholesale price remains a small share of the total bill, but the new price signals matter for exports and imports with Quebec, Manitoba, New York, Michigan and Minnesota, for storage projects procured under the IESO's capacity and long-term procurements (the 2024 and 2025 LT1 and LT2 rounds that added several gigawatts of storage), and for the IESO's ability to co-optimise reserves. The first year of settlement data is the reference for whether uplift has actually fallen.

Key numbers

Go-live
1 May 2025
What ended
HOEP uniform price; most Congestion Management Settlement Credits
Pricing
Locational marginal prices for generators; zonal price for most load
Design and build period
About ten years from the 2015 market renewal launch

Who gains and who pays

  • Gas generators and importers (mixed): Day-ahead firmness and locational prices, but narrower make-whole payments.
  • Storage developers (gains): Day-ahead and real-time price spreads and locational signals support arbitrage and reserve revenue.
  • Large industrial consumers (Class A) (mixed): Zonal pricing and Global Adjustment interaction changes cost management strategies.
  • Interconnected markets (NYISO, MISO, Hydro-Quebec) (gains): Ontario prices now comparable to neighbouring LMP markets, easing trade.
  • IESO (obligation): Operates new day-ahead and real-time systems; monitors first-year outcomes.

Implementation

The renewed market is operating. The IESO and the Market Surveillance Panel are reviewing first-year performance, including make-whole costs, day-ahead convergence and any market-power concerns, and rule refinements are proceeding through the normal Market Rule amendment process. The Ontario Energy Board reviews rule changes. Watch the Market Surveillance Panel's monitoring reports for uplift and price-convergence statistics.

Concerns

  • Whether make-whole and uplift costs actually fall as intended
  • Market power in constrained zones now that prices are locational
  • Complexity for smaller participants adapting to two settlements
  • Interaction between locational wholesale prices and the Global Adjustment paid by consumers
  • Software and settlement disputes in the first years

Dates to watch

  • 2026-H1: First-year performance reports on uplift, convergence and market power
  • 2026: IESO long-term procurement rounds priced against the renewed market

Sources

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Clean economy investment tax credits (Clean Technology, Clean Electricity, CCUS, Hydrogen, Manufacturing)

Canada federal · Parliament of Canada (Department of Finance) · statute · 2024

Where it stands: All five credits enacted (C-59 and C-69, 20 June 2024; Clean Electricity ITC and CCUS extension in C-15, 26 March 2026); CRA administering

Five refundable federal credits worth 15 to 60 percent of capital cost for storage, renewables, nuclear, interprovincial transmission, carbon capture, hydrogen and clean manufacturing, conditioned on paying prevailing wages; all five are enacted (the last, the Clean Electricity ITC, by Bill C-15 in March 2026) and they are Canada's answer to the US IRA and the main lever behind provincial procurement economics.

The problem

The 2022 US Inflation Reduction Act threatened to pull clean-energy capital out of Canada. Provinces own electricity but cannot match federal tax capacity, and Crown utilities (Hydro-Quebec, BC Hydro, SaskPower, Ontario Power Generation) do not pay income tax so ordinary credits would not reach them. Ottawa designed refundable credits, with a special credit open to Crown corporations, to keep projects in Canada and to fund the grid build required by the Clean Electricity Regulations.

What it does

Budgets 2022 to 2024 announced five credits, enacted through Bill C-59 and Bill C-69 (both assented 20 June 2024) and, for the Clean Electricity ITC and the extension of full CCUS rates, Bill C-15, the Budget 2025 Implementation Act, No. 1 (Royal Assent 26 March 2026). The Clean Technology ITC pays 30 percent of the capital cost of solar, wind, storage, small hydro, geothermal, small modular reactors and non-road zero-emission vehicles acquired from 28 March 2023, phasing down from 2034. The Clean Electricity ITC pays 15 percent on non-emitting generation, storage, abated gas meeting an intensity threshold and interprovincial transmission, and is open, for property acquired from 16 April 2024 and available for use by the end of 2034, to designated provincial and territorial Crown corporations (at least 90 percent government-owned) that sign a written agreement with the CRA to follow the Income Tax Act, as well as to Indigenous-owned entities and pension-fund entities; the earlier policy condition that the province commit to a net-zero grid roadmap does not appear in the CRA's enacted-eligibility guidance. The CCUS ITC pays 37.5 to 60 percent depending on equipment type through 2035 (Budget 2025 extended the full rates by five years), halving for 2036 to 2040. The Clean Hydrogen ITC pays 15 to 40 percent by carbon intensity, and the Clean Technology Manufacturing ITC pays 30 percent on equipment for manufacturing clean technology and processing critical minerals. Each credit is reduced by ten percentage points if prevailing-wage and apprenticeship requirements are not met.

Market effect

A 30 percent refundable credit on storage and renewables lowers levelised cost by roughly a fifth, which is why Alberta's merchant market and Ontario's and Saskatchewan's procurements have attracted bids at prices that would otherwise be uneconomic. The Clean Electricity ITC changes the calculus for Crown utilities on nuclear refurbishment, SMRs and interprovincial lines because it effectively cuts federal cost-sharing into projects that were previously funded from rate base alone. Abated gas eligibility (with a CO2 intensity limit) supports CCS-equipped combined cycles in Alberta as a route to comply with the Clean Electricity Regulations. The credits also feed the transmission case for interties (Atlantic Loop, Ontario-Quebec exchanges). Because credits are refundable, they are cash grants in effect and flow through to lower contract prices in competitive procurements; bidders price them in, so the effect shows up as lower PPA prices rather than higher developer margins.

Key numbers

Clean Technology ITC
30 percent (20 percent without labour conditions), acquisitions from 28 March 2023; 15 percent in 2034, nil after
Clean Electricity ITC
15 percent; enacted by Bill C-15 (Royal Assent 26 March 2026); property acquired from 16 April 2024
CCUS ITC
37.5 to 60 percent by equipment type through 2035, halved for 2036 to 2040
Enacting bills
C-59 and C-69 (Royal Assent 20 June 2024); C-15 (Royal Assent 26 March 2026)

Who gains and who pays

  • Renewable, storage and SMR developers (gains): 30 percent Clean Technology ITC on eligible property; wage rules required for the full rate.
  • Crown utilities (OPG, Hydro-Quebec, BC Hydro, SaskPower, NB Power) (gains): First federal credit they can claim, via the Clean Electricity ITC enacted in March 2026, subject to a written agreement with the CRA.
  • Oil sands and gas generators pursuing CCS (gains): CCUS ITC of up to 60 percent on capture equipment.
  • Federal treasury (costs): Tens of billions of dollars over a decade; subject to future budget changes.
  • Crown utilities that do not meet the Clean Electricity ITC conditions (costs): Cannot access the 15 percent credit without the ownership test and CRA agreement.

Implementation

The Canada Revenue Agency administers the credits with Natural Resources Canada providing technical validation. Clean Technology and CCUS credits have been claimable since 2024; the Clean Electricity ITC became claimable when Bill C-15 received Royal Assent on 26 March 2026, which also extended the full CCUS rates to the end of 2035. The live 2026 question is Finance Canada's consultation (closed 13 March 2026) on a domestic-content requirement for the Clean Technology and Clean Electricity ITCs. The Clean Technology ITC steps down to 15 percent for 2034 and ends after 2034.

Concerns

  • Complexity and delay in the Clean Electricity ITC conditions for provinces and Crown utilities
  • Labour-condition compliance and audit risk
  • Fiscal cost and the risk of future budgets trimming rates
  • Eligibility of abated gas and the intensity threshold used
  • Interaction with provincial incentives and procurement rules

Dates to watch

  • 2026-H2: Finance Canada decision on a domestic-content requirement for the Clean Technology and Clean Electricity ITCs
  • 2034: Clean Technology ITC steps down to 15 percent; ends after 2034
  • 31 December 2035: Full CCUS ITC rates end (halved for 2036 to 2040)

Sources

Checked against sources on .

Clean Electricity Regulations (SOR/2024-263)

Canada federal · Government of Canada (Environment and Climate Change Canada) · regulation · 2024

Where it stands: In force since 1 January 2025; 65 t CO2/GWh limits bind from 1 January 2035; held in abeyance in Alberta (implementation agreement of 15 May 2026) pending the Alberta Court of Appeal reference

A federal performance standard of 65 tonnes CO2 per GWh on fossil generating units of 25 MW or more from 1 January 2035, with pooling, offsets and end-of-life relief for existing gas plants; the regulations are held in abeyance in Alberta under the May 2026 Canada-Alberta implementation agreement pending a court reference, after which they will be stood down by equivalency agreement or repealed.

The problem

Canada's grid is about 84 percent non-emitting, but Alberta, Saskatchewan, Nova Scotia and New Brunswick rely heavily on gas and coal. Provinces own electricity policy, so Ottawa used its Canadian Environmental Protection Act, 1999 authority over toxic substances (CO2 is listed) to impose a national emissions performance standard aimed at a net-zero grid by 2050, while trying to avoid a constitutional fight and reliability failures in gas-dependent provinces.

What it does

The regulations, made under CEPA and registered on 13 December 2024 (Canada Gazette Part II, 18 December 2024) after a 2023 draft in Canada Gazette Part I, apply to units of 25 MW or more that burn fossil fuels and are connected to a grid subject to the North American Electric Reliability Corporation standards. From 1 January 2035 each unit must keep its annual average emissions intensity at or below 65 tonnes of CO2 per GWh for 2035 to 2049, falling to zero from 2050. Units commissioned before 2025 are given relief until the later of 2035 or the end of a prescribed life (25 years from commissioning for units commissioned before 2025, and 31 December 2049 for planned units), and units that started construction by 2025 have transitional treatment. Compliance flexibilities include pooling of emissions across units under common ownership within a province, use of eligible offset credits for a limited share of emissions, and exemptions for emergency operation declared by the system operator. The regulations also require registration, continuous emissions monitoring and annual reporting from 2025. Provinces may seek equivalency agreements under CEPA section 10 so that provincial rules apply instead.

Market effect

The 65 t/GWh standard is roughly 15 to 20 percent of a modern combined-cycle plant's intensity, so unabated gas cannot run as baseload after 2035 without offsets or capture; it can run at low capacity factors, which turns Alberta's and Saskatchewan's gas fleets into peaking and firming capacity and raises the value of storage, hydro imports, nuclear (SMRs in Ontario, Saskatchewan and Alberta) and interties. In Alberta's energy-only market the effect is felt in the investment case for new combined cycles now: a plant financed in 2026 must plan for 2035 constraints, which pushes toward CCS-ready designs with the federal CCUS investment tax credit or toward gas peakers plus batteries. Offsets and pooling create a compliance market and let a portfolio owner run its most efficient units harder. Reliability exemptions reduce the risk of load-shed but weaken the standard's bite in tight years. For traders the regulation is a 2035 event with a 2026 to 2030 investment signal; watch the Alberta-specific outcome, which could exempt the province with the most gas.

Key numbers

Performance standard
65 tonnes CO2 per GWh, annual average, 2035 to 2049; zero from 2050
Applies to
Units of 25 MW or more from 1 January 2035
Registration number
SOR/2024-263, registered 13 December 2024 (Canada Gazette Part II, 18 December 2024)
Existing-unit relief
Later of 2035 or end of prescribed life (25 years from commissioning; 31 December 2049 for planned units)
Alberta
In abeyance under the 15 May 2026 implementation agreement pending the Alberta Court of Appeal reference

Who gains and who pays

  • Gas and coal generators in Alberta, Saskatchewan, Nova Scotia, New Brunswick (costs): Must cut intensity, add capture, buy offsets or shift to peaking duty by 2035 (or end of prescribed life).
  • Provincial governments and system operators (mixed): Alberta and Saskatchewan oppose; the regulations are in abeyance in Alberta pending a court reference, with an equivalency agreement or repeal to follow.
  • Hydro-rich provinces and interprovincial transmission developers (gains): Firm clean supply becomes more valuable; interties gain a policy rationale.
  • Storage, nuclear and CCS developers (gains): Stronger 2035 demand for firm non-emitting or abated capacity.
  • Industrial and residential ratepayers in gas-dependent provinces (costs): Higher compliance costs pass through; magnitude depends on flexibilities used.

Implementation

Registration and reporting obligations began on 1 January 2025. The performance standard itself does not bind until 2035, so the next years are about litigation, equivalency negotiations and investment decisions. The 27 November 2025 Canada-Alberta memorandum of understanding (a political agreement, not a legal instrument) committed Ottawa to suspend the regulations' application in Alberta, and the 15 May 2026 implementation agreement keeps them in abeyance there while Alberta's reference on the regulations is before the Alberta Court of Appeal and any Supreme Court appeal: if the regulations are upheld the parties negotiate a CEPA equivalency agreement to stand them down in Alberta; if they are struck down Canada has agreed to repeal them. No amending regulation had been pre-published in the Canada Gazette as of September 2026. Saskatchewan's existing equivalency agreement covers only the coal-fired electricity regulations and expires on 31 December 2026. Check the CEPA registry for amendments and equivalency agreements.

Concerns

  • Constitutional challenge or de facto non-compliance by Alberta and Saskatchewan
  • Reliability in gas-dependent provinces when hydro imports are constrained
  • Affordability in provinces without hydro or nuclear
  • Offset supply and integrity if many units rely on credits
  • Political durability: a change of federal government could repeal the regulations

Dates to watch

  • 31 December 2026: Canada-Saskatchewan equivalency agreement (coal-fired electricity regulations) expires
  • 2027: Alberta Court of Appeal reference decision (no fixed date) and the resulting equivalency agreement or repeal
  • 1 January 2035: 65 t CO2/GWh performance standard applies

Sources

Checked against sources on .