Background
The AESO published the 2024 Long Term Outlook (LTO) which provides a 20-year outlook on Alberta’s electricity load and generation based on current assumptions, with an update published at least every two years. In response to ongoing uncertainty around Alberta’s market design and policy climate, the AESO released three additional scenarios along with the main Reference Case.
This note provides Power Advisory’s summary and commentary on the 2024 LTO. The latest LTO was published in a modular format, with the AESO releasing a main LTO report, four reports detailing outcomes of each scenario, and in-depth reports on load forecast methodology, generation forecast methodology, policy and regulatory drivers, emerging technology drivers, risks and uncertainties, and implications, insights, and outcomes.
The four scenarios in the 2024 LTO were (1) the Reference Case, (2) Decarbonization by 2035, (3) Alternative Decarbonization, and (4) High Electrification. The first three scenarios have a common load forecast input.
Demand Outlook
The 2024 LTO shows strong and sustained electricity demand growth and is linked with economic factors like GDP, population growth, employment rates, and oilsands production. Oilsands production is expected to peak in the early 2030s, stabilize for several years, and gradually decline thereafter. These macroeconomic assumptions were common across all four scenarios.
Additional load drivers were identified starting in the 2030s, such as accelerated adoption of EVs across different vehicle categories, growing hydrogen production, electrification of building heating and cooling systems, and electrification of heavy industries such as chemical, pulp and paper, and cement. Different assumptions around these load modifiers underpin the higher load forecast in the High Electrification scenario and explain why the 2024 LTO Reference Case has a higher growth rate than the 2021 LTO. Average hourly Alberta internal load (AIL) increases by 26 percent between 2024 and 2043 in the Reference Case, and by 44 percent in the High Electrification scenario. Alberta is expected to remain a winter peaking jurisdiction.
Figure 1: Average AIL forecast
The Reference Case has moderate EV growth due to the absence of provincial EV policies and subsidies, while the High Electrification scenario achieves the ambitious federal 2030 Emissions Reduction Plan (ERP) new sales targets (for light-duty vehicles, the ERP targets new sales requirements of 20% by 2026, 60% by 2030, and 100% after 2035. For medium- and heavy-duty vehicles, the ERP targets 35% of new sales by 2030, with new regulations for a subset of these sales achieving 100% by 2040). Annual average EV load is expected to account for 10.6 percent and 13.8 percent of AIL by 2043 in the two respective load forecasts. The AESO also assumes managed EV charging profiles but acknowledges there are no specific plans yet to incentivize managed charging behaviour in Alberta, pointing instead to consensus by market participants and policy makers that the benefits will create incentives in the future. There are also EV charging pilot programs being deployed by different distribution facility owners (DFOs) in Alberta. Achieving this managed EV load profile will require continued adaptation, planning, and cooperation among the system operator, DFOs, retailers, and EV owners.
Building electrification impacts are not noticeable until 2030 but increase exponentially afterwards. Heating peaks tend to occur in the early morning and late evening which aligns with off-peak hours while cooling demand overlaps with on-peak hours, suggesting that cooling has a more significant impact on system peak.
Figure 2: Load forecast impacts from building heating/cooling electrification
Alberta has a growing focus on expanding its hydrogen production and usage in the transportation and industrial sectors. Cumulative hydrogen production reaches an estimated 2.2 million-metric tonnes (MT) by 2043 in the Reference Case, which will add about 553 MW of incremental average hourly load.
Generation outlook
The AESO prepared four different supply outlooks, one for each scenario. The Reference Case includes 25,626 MW of capacity additions and CCUS retrofits between 2024 and 2043, with 1,800 MW of nuclear small modular reactors (SMRs) entering in the last two years. This was the only scenario with no new CCUS assets added, relying solely on retrofitting existing combined cycle (CCGT) assets between 2028 and 2031, coinciding with federal investment tax credit (ITC) availability. The High Electrification scenario had the largest capacity build of all scenarios.
Across all four scenarios, cogeneration, wind, and solar additions were nearly identical, with renewables peaking in the mid-2030s. No new wind or solar was added after 2036 and capacity fell with gradual retirements. All coal-to-gas assets retire by the end of 2038 at varying paces in different scenarios. Differences in supply stack came from combined cycle with CCUS, CCUS retrofits, natural gas simple cycles, hydrogen-fueled simple cycles, and SMRs.
Figure 3: Reference Case – total installed capacity
Figure 4: High Electrification scenario – total installed capacity
Table 1: Supply assumptions across scenarios from 2024 to 2043
New wind and solar additions were mainly driven by exogenous demand for corporate power purchase agreements (PPAs), ITCs, and renewable credits and offsets while oilsands cogeneration was added exogenously based on oilsands growth. Notably, wind and solar build decisions did not include impacts from the Renewables Moratorium. The Reference Case also assumes increased intertie capacity over time achieving a maximum WECC import capability of 1,434 MW by 2030, more than double the current ATC of 650 MW.
Table 2: Reference Case intertie average capability and maximum capability assumptions
Resource Adequacy
The LTO included a probabilistic assessment of supply adequacy in the years 2028, 2030, 2033, 2035, 2038, and 2043. The AESO expects all years except 2038 to meet supply adequacy standards in the Reference Case, with significant risk in 2038 from the mandated retirement of coal-to-gas assets. Conversely, the AESO also expects periods of supply surplus into the 2030s because of recent gas-fired and renewable additions.
Table 3: EUE, LOLE, and LOLH metrics for Reference Case
The Decarbonization by 2035 scenario has the highest risk of load shed due to the stringent CER limitations on unabated gas assets. Shortfall exceeds the acceptable threshold in 2035 and 2038 by orders of magnitude, which suggests the optimal resource mix cannot meet the forecast load under the CER requirements. The remaining two scenarios have shortfall results more like the Reference Case.
Table 4: EUE, LOLE, and LOLH metrics for additional scenarios
Comparison with Power Advisory April 2024 Forecast
Power Advisory provides a bi-annual Alberta wholesale electricity price forecast out to 2050 for its subscribers. The latest April 2024 forecast included three scenarios, a Base Case, a Business-As-Usual scenario, and Pathways to Net-Zero scenario. Like the LTO Reference Case, Power Advisory’s Base Case captures our view of the current most likely assumptions.
The LTO Reference Case assumes a 26 percent increase in average AIL by 2043 and a 31 percent increase in peak AIL, while the Power Advisory Base Case has a 32 percent increase in both by 2043. The difference in peak AIL comes from different assumptions in EV and space heating load profiles.
Figure 5: Peak and Average AIL in AESO's Reference Case and Power Advisory's Base Case
Table 5 shows the installed capacity in the LTO Reference Case and Power Advisory’s Base Case in 2043. Unlike the LTO which stops adding wind and solar by 2036 and has declining capacity, the Power Advisory forecast continues expanding renewable capacity based on economic signals rather than PPA demand or external revenue streams. Power Advisory recognizes these revenue streams exist for developers but may diminish over time. The Power Advisory forecast foresees a slowdown in wind and solar generation in the next five years due to land use and viewscape restrictions, low power prices from new gas-fired generation in 2024 and delays in signing PPAs due to market structure uncertainty. Expansion of renewables picks up in the 2030s from load growth and higher prices. The LTO has almost no variability in renewable assumptions across scenarios, which may not capture a realistic range of potential outcomes.
Table 5: Comparison of capacity assumptions in 2043
In the Reference Case, the AESO assumes nearly all existing CCGT and cogeneration units will retrofit with CCUS by 2031 while Power Advisory’s CCGT retrofits are gradual and occur over a longer period, with a handful of assets remaining unabated. Although Power Advisory is skeptical of the scale and speed of the AESO’s assumptions around retrofitting (especially with new CCGT assets still commissioning), well-designed ITCs can indeed send strong signals around the role of new technology in emissions reductions.
As a result of the ambitious CCUS retrofitting campaign for nearly all CCGT and cogeneration assets, the LTO’s emissions estimates see a sharp drop from 2027 to 2031. Power Advisory’s outlook on retrofitting is more modest and assumes a slower pace of hydrogen blending in new combined and simple cycle units. The LTO also forecasts a higher portion of load served by imports, which would displace higher emitting domestic generation.
Figure 6: Annual electricity sector emissions
One key difference between the LTO Reference Case and Power Advisory’s Base Case is carbon policy assumptions. The LTO assumes the HPB declines to zero by 2050 while Power Advisory’s declines to zero by 2035. The difference results in higher operating costs for unabated assets beyond 2030 and more storage deployed in the Power Advisory forecast.
Figure 7: Carbon price and HPB benchmark assumptions
Power Advisory Commentary
The 2024 LTO reports and data file provide detailed insights into the AESO’s view on Alberta’s electricity needs and development pathways. The scenarios outline additional trajectories for the grid and serve as good sensitivity checks. Unlike other Canadian jurisdictions, this document is not an integrated resource plan outlining a roadmap of investment decisions, but instead captures the story of evolving economic, social, and political impacts.
Overall, the AESO’s LTO is very optimistic about the pace and scale of CCUS commercialization and the magnitude of future intertie expansion. Their renewables outlook is similar to Power Advisory’s outlook, slowing down after the near-term capacity expansion. Both forecasts also indicate the need to deploy new technologies not currently on the system to meet the combined goals of decarbonization, affordability, and reliability. Power Advisory notes that CCUS technology has yet to be widely deployed in the electricity sector, and with Capital Power’s recent cancellation of their Genesee CCUS project, there remain clear challenges to commercialization at the scale shown in the LTO. The assumed intertie expansion is also significant, and the AESO must be prepared to expand its reliability products to facilitate this growth. It will also require neighbouring jurisdictions to be aligned with this outlook.
The Decarbonization-by-2035 scenario explored impacts of the original draft CER. In the February 2024 update, there were proposals to loosen restrictions. This will relieve some supply adequacy concerns in this scenario, though the AESO will still need to be prepared to manage contingencies should any version of the CER resembling the current proposal be enacted.
As things currently stand, Alberta seems to be nearing the end of its latest major thermal buildout cycle, with the commissioning of Cascade, Genesee Repowering projects, and Suncor’s Base Plant. The LTO demonstrates a path under the current market structure that results in a reliable and largely decarbonized electricity system which could indicate that long-term contracts for supply adequacy reasons are unnecessary. That said, it remains to be seen what the size and scope of future build cycles will be since they will occur in the context of the REM, new Transmission Regulation, and with new land use restrictions.