Alberta's Energy Crisis: Understanding the Challenges and Solutions

Since 2020, the AESO has declared 26 Energy Emergency Alerts (EEAs). A staggering 73% of these events occurred during extreme heat or cold. Instead of having a robust, self-sustaining system, Albertans are becoming a de facto part of the grid's emergency response. We're asked to turn off appliances and unplug devices to prevent blackouts.

For many of us, a new routine has emerged. Daily text message alerts or public pleas from the Alberta Electric System Operator (AESO) to reduce power consumption have become commonplace. These "grid alerts," often triggered by a "stressed" power system or tight supply margins, signal a system on the brink.

This situation has shifted the burden of grid stability from operators and regulators to consumers. It's a clear sign that the foundational promises of affordability and reliability have been compromised.

The evidence suggests this isn't a coincidence. It's the direct result of a market structure and a series of policy decisions that have left Alberta's electrical system vulnerable and unprepared for modern demands.

The Unraveling of the "Energy-Only" Promise

Alberta has long championed its "energy-only" electricity market. In this framework, generators are paid solely for the power they produce and sell to the grid. This model has been in place since 2000 and was reaffirmed in 2019 when the government abandoned plans for a "capacity market."

The official rationale was that the energy-only model was simpler and had a proven track record of providing affordable and reliable power. However, recent data raises serious questions about whether these promises have been fulfilled.

Between 2021 and 2023, the average regulated electricity rate skyrocketed. In Edmonton, the rate surged by 143.1%, from 9.826 cents per kilowatt-hour ($/kWh) to 23.89 $/kWh. Calgary experienced a similar increase of 143.6% over the same period. This dramatic rise in cost occurred despite the system being paid for the energy it produces, which should lead to greater affordability.

Further exposing the system's vulnerabilities, record-setting demand peaks were reached in 2024. The winter peak climbed to 12,384 megawatts (MW), a 1.6% increase from the previous record. Meanwhile, the summer peak reached 12,221 MW, a 6.1% increase. During a cold snap in January 2024, the Alberta electricity pool price hit its maximum cap of 999.99/megawatt−hour (/MWh) multiple times, underscoring the severe strain on the system's capacity.

In response to these market failures, the government introduced temporary regulations in March 2024: the Market Power Mitigation Regulation and the Supply Cushion Regulation. These rules aimed to address concerns over "economic withholding," where large generators hold back supply to drive up prices, and "physical withholding," where assets are kept offline during high demand.

While these policies were intended to promote affordability and reliability, industry analysts criticized them for creating a new layer of regulatory uncertainty. According to EnergyRates.ca's economist Joel MacDonald, setting the price ceiling too low could discourage private producers from investing in new generating capacity, potentially leading to tighter supply in the long run.

Further complicating the investment landscape is the AESO's new Optimal Transmission Planning (OTP) framework, adopted in July 2024. This framework shifts from a "zero congestion" standard to a model emphasizing economic efficiency. New generators must pay an upfront, non-refundable Transmission Reinforcement Payment (TRP) towards infrastructure costs.

This change, while intended to make the system more economically rational, is expected to "create uncertainty for the identified generation-driven portfolio due to delays or reprioritization."

The CEO of the Canadian Renewable Energy Association (CanREA), Vittoria Bellissimo, stated that the new market design "misses the mark" on modernizing the grid. It will likely lead to "higher-priced gas-fired power and fewer wind and solar plants."

The government's ad-hoc policy interventions are a direct consequence of the "simplicity" of the energy-only market proving to be simplistic and unreliable. This reactive policymaking erodes investor confidence, creating a vicious cycle where a market designed to spur investment through free-market principles is now perceived as unstable and unpredictable.

The For-Profit Paradox: Why Generators Aren't Building

The argument that for-profit generators are unwilling to invest in much-needed growth requires a nuanced understanding of their business model. Publicly traded companies like TransAlta and Capital Power are legally obligated to prioritize "stable and growing cash flows" and "shareholder value." Their investment decisions are based on a cold calculation of risk versus return.

A significant development reinforcing concerns about market control is TransAlta's acquisition of Heartland Generation in November 2023 for $658 million. This purchase gave TransAlta control of 46% of Alberta's electricity generation market. Critics called this move "a catastrophe" that would "likely lead to economic withholding." This market consolidation suggests that power is concentrated in the hands of a few large players, reducing competitive pressures that might otherwise drive investment in a more resilient grid.

While some point to a lack of investment, a closer examination reveals a more complex picture. For instance, Capital Power invested approximately $1.6 billion to repower its Genesee Generating Station from coal to 100% natural gas, completing the conversion five years ahead of the government's mandate. This project added an additional 512 MW of capacity to the grid. Similarly, TransAlta's investor presentations indicate plans to deploy "approximately $3.5 billion of growth capital" by 2028. These investments demonstrate a clear appetite for capital spending.

The core problem isn't a lack of investment appetite but a fundamental misalignment between private, shareholder-driven incentives and the public need for grid resilience.

A government document on the pause on renewable energy projects explains a key difference in Alberta's market. Unlike other provinces, transmission costs for new projects are often "assigned to rate payers" rather than being part of the business case for the private company. This structure fundamentally changes the investment calculus, incentivizing projects that benefit the generator but may not be optimal for the grid as a whole.

The result is a paradox: while companies are willing to invest billions, they may hesitate on critical, long-term grid growth that requires a stable regulatory and revenue environment, which the current, reactive policy landscape lacks. The public receives the benefit of capital-intensive projects only when they serve the private interests of the generator.

The Intermittency Challenge: When Sunshine and Wind Fall Short

Alberta’s power grid faces a new and complex challenge with the rapid expansion of distributed generation, particularly in wind and solar. These "micro-generation" systems allow individuals and businesses to produce their own power and sell excess back to the grid. This uptake is driven by consumer choice and government policies that allow micro-generators to receive credits for the power they send to the grid.

The rapid increase in installed wind and solar capacity is not without consequences. According to the AESO's 2024 Annual Market Statistics report, the growth in these intermittent sources "heightened net demand variability (NDV), surpassing projected levels by two years." This confirms that the variability of solar and wind is a significant factor. The technical implications of this variability are also a major concern. The operation of intermittent sources can lead to "abrupt degradation in system voltage" and an increased "likelihood of voltage collapse." Unlike traditional synchronous generation units, which provide a stable, dispatchable power source, solar and wind create a new level of complexity for the grid operator to manage.

This problem is exacerbated by a policy gap. The Rural Municipalities of Alberta (RMA) passed a resolution requiring new renewable energy developments to contribute a "stated minimum electricity contribution to the grid on demand." However, the government's response indicates that this intent has not been met. While new regulations and bills like Bill 52 aim to support reliability, they do not specifically mandate this critical requirement.

Another fundamental issue created by the rapid adoption of distributed generation is the economic externality known as "uneconomic bypass." As a report from Norton Rose Fulbright explains, uneconomic bypass occurs when a consumer uses a Distributed Energy Resource (DER) to reduce their transmission and distribution bills without reducing the overall costs of the electric system. The fixed costs of maintaining the grid and its infrastructure do not disappear.

Instead, they "must be recovered from other customers." This creates a "vicious cycle" where a shrinking number of non-DER customers bear an increasing share of the system's fixed costs. The problem isn't the technology itself but the lack of a coherent policy framework to manage its integration into a legacy grid. This creates a financial burden on non-DER customers and technical instability for the system as a whole. Alberta has encouraged the rapid adoption of new technology without implementing the necessary rules and regulations to ensure it integrates seamlessly and fairly.

The Perfect Storm: Policy, Market, and Technology Collide

The current fragility of Alberta's electricity grid results from a convergence of three powerful forces. First, an outdated "energy-only" market model has failed to deliver on its foundational promises of affordability and stability. This has led to extreme price volatility and a reactive regulatory environment.

Second, a for-profit market dominated by a few large players, while still attracting investment, operates on a principle of private gain over public need. This dynamic is further strained by regulatory uncertainty.

Finally, the rapid, unmanaged expansion of intermittent, distributed generation is creating new technical and economic challenges that current policy does not adequately address.

Adding to this precarious situation is the spectre of the federal Clean Electricity Regulations (CER), which took effect on January 1, 2025. The AESO, the very body tasked with maintaining Alberta's grid, has issued a stark warning about the regulations. They conclude that the CER "pose a significant risk to the reliability and affordability of Alberta's electricity system."

The AESO projects that to comply with the CER, the system would require $30 billion in additional capital and operating costs between 2024 and 2049. This could result in wholesale electricity prices being 35% higher than they would have otherwise been between 2035 and 2050.

The most dire projection from the AESO's analysis is the threat to reliability itself. The AESO forecasts that the CER "would make Alberta's electricity system more than 100 times less reliable than the province's supply adequacy standard" by 2038. This is because the regulations "will restrict the operation of existing dispatchable generation units" while no "economically and operationally proven low carbon emitting supply alternatives" are available in the required timeframe to replace them.

The current system's instability is a direct result of provincial policies that have failed to address fundamental market and technological shifts. The looming threat of federal regulations, as viewed by the provincial grid operator, is poised to compound these issues by limiting the very assets needed for stability before proven alternatives are ready. This creates a perfect storm where market flaws, misaligned private incentives, and technological complexities collide with a politically charged regulatory framework. The final result is a grid that, despite the best efforts of its operators and consumers, remains on a perilous path toward a less reliable and more expensive future.

The Path Forward: From Policy Paradox to Practical Power

So, what’s a province to do? The impulse lately has been to layer new, reactive regulations on top of an existing market structure, creating a mess of uncertainty and disincentives.

The path forward isn't to abandon the energy-only model entirely but to adapt it thoughtfully to the realities of a modern, multi-directional grid.

First, to address price volatility and unmanaged growth of intermittent sources, the government and the AESO are already making moves. The implementation of a "day-ahead reliability market" is a positive step. This will ensure enough power is available at all times by requiring generators to commit their capacity in advance, with penalties for non-fulfillment. Further development of "locational marginal pricing," where the price of power reflects the true cost of making and delivering it to different locations, could provide a more honest signal to the market. This would encourage investment in areas where it's needed most to relieve congestion. It's a more subtle yet powerful market mechanism than heavy-handed price caps.

Second, the for-profit paradox can be addressed by realigning incentives. Instead of simply paying for energy, the market can be designed to compensate for "grid-supporting" services. The AESO is already piloting and evaluating technologies that can enhance the grid without building new infrastructure.

For instance, "non-wires alternatives" like demand response and behind-the-meter storage, such as battery energy storage systems (BESS), can now compete with traditional "wires solutions" to address peak constraints. By creating a clear, market-based framework for these solutions, the province can harness private capital to build resilience, not just generation.

Additionally, the Rural Municipalities of Alberta (RMA) have proposed a concrete solution: require new renewable projects to have a "stated minimum electricity contribution to the grid on demand." This could be a market-based requirement, incentivizing private developers to integrate battery storage or other solutions into their projects from the outset.

Finally, while the challenges of the federal Clean Electricity Regulations (CER) are significant, the AESO's analysis suggests the issue is a matter of timing and readiness, not an absolute prohibition on progress. The AESO points out that the regulations restrict the operation of existing units before "economically and operationally proven low carbon emitting supply alternatives" are available.

A more pragmatic approach would be to focus on accelerating the development and commercialization of these technologies, such as abated natural gas and hydrogen-fired generation. Clear, long-term policy signals can give private investors the confidence to commit capital.

The AESO's own Distributed Energy Resources (DER) Roadmap acknowledges that the path forward requires better data visibility, improved forecasting, and coordinated planning and operations to manage the shift from a one-way to a two-way power flow. The solutions are not a mystery; they simply require the political will to implement them with a focus on practical, market-based mechanisms rather than reactive, short-term fixes.

Frequently Asked Questions

1. What is a "grid alert"?

A grid alert is issued by the Alberta Electric System Operator (AESO) when the province's power system is stressed and requires the use of emergency reserves to meet demand. These alerts signal a potential for power interruptions and are often issued during extreme weather, such as intense heat or cold.

2. Why are Albertans being asked to conserve power?

The public is asked to conserve power to help prevent outages during a grid alert. By reducing consumption during peak hours, particularly in the evening, consumers can help alleviate strain on the electrical system and reduce the need for more drastic measures like "load shedding," or planned power interruptions.

3. Why did electricity rates increase so dramatically?

Between 2021 and 2023, the average regulated electricity rate in Edmonton and Calgary increased by over 143%. This price surge occurred even though the system is designed to be affordable. These high prices were a contributing factor to the government's introduction of temporary regulations to address market power and physical withholding.

4. What is the difference between an "energy-only" and a "capacity market"?

In Alberta's "energy-only" market, generators are only paid for the electricity they produce and sell. In a "capacity market," generators receive an additional payment for having facilities available, particularly during periods of high demand. This provides more revenue certainty for investors and a more reliable supply for the grid.

5. How is micro-generation, like solar panels, affecting the grid?

The rapid growth of intermittent sources like wind and solar has heightened "net demand variability," creating challenges for the AESO to manage. The AESO notes that the shift to a two-way power flow from traditional one-way flow is a major transformation that requires improved forecasting and technical solutions.

6. What is "uneconomic bypass"?

Uneconomic bypass occurs when customers with distributed energy resources, such as solar panels, reduce their personal transmission and distribution bills without reducing the overall costs of maintaining the grid. This can create a "vicious cycle" where the fixed costs of the grid are shifted to a shrinking number of non-DER customers, leading to higher bills for them.

7. How is the government responding to these issues?

In addition to the temporary Market Power Mitigation and Supply Cushion regulations, the government has passed Bill 52. This will enable a day-ahead reliability market and allow for new transmission policies. The AESO is also adopting a new Optimal Transmission Planning (OTP) framework to ensure new projects meet reliability needs and provide economic benefits.

8. What is the impact of the federal Clean Electricity Regulations (CER)?

The AESO warns that the CER poses a significant risk to the reliability and affordability of Alberta's grid. The regulations would restrict the operation of existing dispatchable generation units. The AESO projects that the system would become more than 100 times less reliable by 2038 and require $30 billion in additional costs.