AESO REM

AESO’s Restructured Energy Market (REM) design was published in 2025 and the associated REM ISO rules received ministerial approval in March 2026. AESO’s IT roadmap provides for a participant soft launch beginning in January 2027, system trials starting in Q3 2027, and targeted production market cutover in Q2 2028.¹

The production target should not be mistaken for the deadline to begin preparing. Participants need to assess impacts, assign ownership, make platform and data decisions, and prepare for early system access and testing during 2026. 

REM aligns Alberta more closely with market practices used across major North American ISOs and RTOs, including security-constrained dispatch and locational pricing. However, REM is not a direct copy of ERCOT or any other market. AESO has developed the design around Alberta’s energy-only market, competitive-offer framework, reliability requirements and provincial policy direction.

Below we examine the three changes likely to have the most impact on power trading companies operating in the Alberta market and explore how these changes are interconnected:

• Locational marginal pricing (LMP)
• Security-constrained economic dispatch (SCED)
• Congestion exposure and risk management

Locational marginal pricing

Today, Alberta’s wholesale spot energy market settles at a common province-wide pool price. REM introduces locational marginal pricing (LMP), which means every location or node on the network can have its own price. 

This necessitates a shift in focus from trading simply energy to trading energy plus location. The geography of the market and the transmission map become critically important. 

Not all market participants will settle at a nodal price. Under the REM design, source assets and controllable sink assets are subject to LMP, while eligible non-controllable sink assets generally use the Alberta Load Price (ALP) unless they elect LMP. Each locational price reflects an energy component together with location-specific congestion and marginal losses.

Transmission constraints will cause locational prices to shift and diverge. Along with LMP pricing, REM will transform congestion from being an operational concern for the market operator into a trading concern – and therefore also a potential trading opportunity.

Trading companies will need to incorporate transmission analytics into their trading strategies, including monitoring constraints, outage forecasts and flow forecasts. Congestion risk will be embedded in every nodal power position. 

Traders will need to predict which transmission constraints will bind when, and the impact that will have on the locational pricing forecasts. In the redesigned market, trading risk will be magnified because locational prices may separate when power cannot physically flow where it is needed. 

Security-constrained economic dispatch

In a power market with a single market price, traders think primarily in terms of supply and demand balance, with the marginal resource setting the market price. 

In the REM real-time market, AESO will determine dispatch and pricing through a security-constrained process that accounts for market offers, system limits and transmission constraints. The market-clearing process will normally run every five minutes. It will seek economically efficient, physically feasible dispatch by minimizing offer-based dispatch costs while respecting system constraints. Under REM, real-time energy and the 30-minute ramping reserve product (R30) will be co-optimized. 

SCED determines which generators should run and the marginal cost of serving an additional megawatt-hour (MWh) of energy at every pricing node on the grid. That marginal cost becomes the locational marginal price at every location. Therefore, LMP pricing is the byproduct of the SCED optimization problem. 

AESO’s optimization changes under REM because it includes the physical constraints of the network when determining which generation resources will run. In an SCED market, the trader must consider the optimization logic employed by the market operator and how that optimization will influence various market prices. The trader must consider transmission constraints that may lead to generators in different regions becoming the marginal resource. 

Traders will need to understand market constraints, when and where transmission congestion will appear, and how long it will last. This requires more precise forecasting of regional renewable generation, localized demand forecasts, and the anticipation of transmission congestion.

Traders must also become aware of transmission outages and the impact those outages have on dispatch and therefore on LMP pricing. The trading risk profile becomes significantly more complex, requiring analysis of demand, generation, transmission constraints and the market’s dispatch optimization. 

Congestion exposure and risk management

After AESO’s REM implementation, congestion will be reflected in LMP prices and traders will be exposed to congestion pricing. That exposure cannot currently be hedged through an AESO-administered financial transmission rights (FTR) market, although bilateral and forward arrangements remain relevant options. 

Following its 2026 consultation, AESO decided not to advance a centralized FTR market at this time. It is instead exploring data and reporting to support voluntary risk management and market metrics that could inform any future reconsideration.

During the initial rollout of REM, traders will be exposed to locational congestion risks without a centralized FTR market and should therefore assess contractual, portfolio and operational risk-management options. 

Transitioning from single-price to security-constrained nodal markets

To prepare for the upcoming changes in the Alberta power market, power trading companies will need to examine and enhance trading strategies, business processes and systems across several dimensions:  

• Trade capture
• Position management
• Forecasting
• Market analytics
• Risk analytics
• Reporting
• Settlements
• ETRM systems
• Bid-to-bill systems
• SCADA/telemetry systems
• Market interfaces and integration

The transformation is not limited to forecasting or trading strategy. REM also introduces new energy-offer structures, R30 participation, five-minute dispatch and settlement intervals, and updated market-power mitigation. These changes create dependencies between market strategy, offer approvals, operator actions, interfaces, metered volumes, settlement calculations and financial controls.

The most important commercial challenges are the need to understand where power will be most valuable and when transmission constraints will cause prices to separate.  Transmission becomes an important input into trading decisions, necessitating a shift to locational price forecasting, transmission congestion forecasting, along with outage and constraint analysis. These changes introduce new dimensions to position analysis, risk management, hedging, exposure analysis and risk reporting. 

In addition to evaluating trading strategy and risk analytics capabilities, trading companies need to analyze their system landscape. SCED, LMP pricing and new market products increase the volume, frequency and complexity of market data and transactions. As a result, ETRM, bid-to-bill, SCADA/telemetry, and settlement systems will need to operate in a more closely integrated manner to effectively support the trading business. 

For example, a generator may need its bid-to-bill platform to construct and submit revised energy offers, retain dispatch instructions and operator actions, and associate metered volumes with the relevant five-minute prices. Downstream settlement and finance systems then need to reconcile expected revenue with AESO results. Inconsistent asset identifiers, timestamps, or data version can create errors that are difficult to identify after the fact.

AESO plans to provide participant access through its soft-launch window beginning in January 2027, followed by collaborative trials from Q3 2027. Market participants therefore have less time than the Q2 2028 production target might suggest to confirm requirements, configure interfaces and controls, obtain test access, and demonstrate operational readiness.

Firms should begin now with a cross-functional REM impact assessment covering trading, market operations, technology, data, settlement and compliance. They should then prioritize material gaps, assign accountable owners, secure budgets, and establish a sequenced implementation and testing roadmap rather than wait for every technical specification to be finalized.

How Capco can help

Capco helps power trading companies prepare for market transitions through trading and risk capabilities, ETRM and bid-to-bill modernization, operating-model change, and market-systems integration. For example, Capco has supported power-market clients adapting to ERCOT’s Real-Time Co-optimization plus Batteries (RTC+B) changes, including SCADA-related capabilities and trading-system enhancements. This work has included support for battery resource commissioning, operator transitions and trading-logic implementation to address evolving market and operational requirements.

For Alberta participants, the immediate priority is to translate REM requirements into a fact-based readiness plan: identify material operating and technology gaps, design a target architecture, and sequence implementation and trial preparation. Capco can support readiness assessment, operating-model and integration design, testing, and cutover planning as participants prepare for the restructured market. 

References

¹ https://www.aeso.ca/transition/it-systems/