AB · Energy-only (under redesign) · 2023
An energy-only island that finished coal in June 2024. 2025 peak load was 12,785 MW. The 2024 LTO has peak heading for ~16 GW by 2043 — and the 2026 LTO is still being written.
| 2023 | 2026 | 2030 | 2035 | 2050 | |
|---|---|---|---|---|---|
| Generation TWh | 84.1 | 90.5 | 100.0 | 102.5 | 149.2 |
| End-use electricity TWh | 76.3 | 79.0 | 86.5 | 95.8 | 128.3 |
| Capacity GW | 21.0 | 29.2 | 31.1 | 35.5 | 60.5 |
| Gen − end-use TWh | 7.8 | 11.6 | 13.5 | 6.7 | 20.9 |
Same workbook for every jurisdiction. Residual ≠ surplus. Source: CER EF2026.
2025 observed Alberta Internal Load averaged 10,316 MW and peaked at 12,785 MW. The latest published AESO Long-term Outlook is still 2024 (the 2026 LTO is in stakeholder process as of August 2026). That 2024 reference case: average load +26% and peak +31% by 2043 (~16 GW peak); high electrification +44% average and ~20 GW peak. A single large data-centre allocation can eat a large fraction of that 20-year growth. Oil sands remain both customer and cogen. CER Current Measures has Alberta generation going 84 TWh (2023) → 91 (2026) → 103 (2035) → 149 (2050) — a different model than AESO, shown for comparison only.
Winter-peaking, industrial. Oil sands and bitumen cogen are a large fraction of both load and supply. Per-capita electricity use is high (17.9 MWh in 2020).
Competitive retail plus a Rate of Last Resort. CER (Mar 2026) places Alberta toward the expensive end of the provincial range; bills move with wholesale conditions, riders, and retailer products.
AESO: 2024 Long-term Outlook (latest published; 2026 LTO in preparation) (2024-05-15)
Energy-only market plus a 2024–25 renewable and storage build. Coal finished June 2024. The 2024 LTO Reference Case adds ~26 GW of capacity and retrofits to 2043 (solar, wind, CCGT+CCUS, and 1.8 GW of SMRs only in the last two years of that outlook — announced, not a plant). Near-term adequacy is a winter-peak and flexibility problem, not an annual-energy problem. The 2026 LTO is in stakeholder process and is not published as of August 2026.
Alberta Internal Load (AIL), hourly average and peak. 2025 observed AIL: average 10,316 MW, peak 12,785 MW. Primary document
Coal is gone as of June 2024 — converted to gas, not replaced with nothing. 2023 was the last CER year with coal energy (8.9 TWh). The residual emissions story is gas. CER has Alberta capacity jumping 21 GW (2023) → 29 GW (2026) on wind and solar. Shepard (860 MW) is still the largest gas plant; Travers (465 MW) the largest solar farm. 2024 LTO reference adds ~26 GW of capacity and retrofits through 2043. SMRs in that outlook appear only in 2042–43 — announced.
About 26,000 km of transmission. Weak east–west and weak international: BC 800 MW out / 1,000 MW in; Montana 325 / 310 MW; Saskatchewan 150 MW both ways (NRCan 2026). Alberta is, electrically, an island with a few pontoon bridges. Congestion in the south (wind/solar) versus load in the north (oil sands) is the internal transmission plot. AESO plans; AltaLink and ATCO own most of the bulk system; AUC sets tariffs.
| Path | MW → | MW ← | Kind |
|---|---|---|---|
| BC – Alberta | 800 | 1,000 | interprovincial |
| Alberta – US (Montana) | 325 | 310 | international |
| Alberta – Saskatchewan | 150 | 150 | interprovincial |
Transfer capability, not average flows. Source: NRCan Powering Canada Strong, May 2026, Figure 5.
Unique in Canada: an energy-only wholesale market, no capacity market (yet), merchant generators, competitive retail. Pool price volatility is the point of the design — and the political problem. A Restructured Electricity Market (locational marginal pricing, higher offer caps, new reliability products) is slated for mid-2027. Until then, the 2024–26 market is a system in between.
Alberta Department of Affordability and Utilities sets policy. AESO operates the grid and the market. AUC regulates wires and retail default. MSA watches market behaviour. AER regulates upstream oil and gas, which is the load. CER permits the Montana intertie.
| Operator | Alberta Electric System Operator (AESO) |
| Regulator | Alberta Utilities Commission; Market Surveillance Administrator |
| Transmission | AltaLink, ATCO Electric, ENMAX, EPCOR |
| Dominant utility | Merchant generators (TransAlta, Capital Power, Heartland, ENMAX, Suncor cogen) |
TransAlta, Capital Power, Heartland Generation, ENMAX, EPCOR, Suncor (cogen), FortisAlberta (distribution), AltaLink (Berkshire-owned transmitter), ATCO Electric. Wind/solar developers have been the fastest-growing class of owner. Retailers are a separate competitive layer.
Operating: coal-to-gas conversions complete; Travers; a large wind fleet. Under construction: Dunmore Solar (216 MW) and more. Announced: market redesign 2027; various gas, storage, and renewable proposals. Nuclear (SaskPower/OPG pathway, Alberta exploration) is announced, not a plant.
| Plant | Fuel | MW | Status | Owner |
|---|---|---|---|---|
| Shepard Energy Centre | gas | 860 | operating | ENMAX / Capital Power |
| Travers Solar | solar | 465 | operating | Greengate |
Energy-only vs. capacity payments after several tight winters. Renewable moratorium (2023–24) and land-use rules vs. the interconnection queue. Who funds northern transmission to serve oil-sands electrification. Federal Clean Electricity Regulations vs. provincial gas-as-baseload policy.
2022 intensity still includes coal. Coal-fired generation was fully phased out by June 2024 via coal-to-gas conversions. Intensity should keep falling; 2023 generation was already 20% non-emitting.
| Metric | 2023 | Note |
|---|---|---|
| Generation | 84.13 TWh | CER EF2026 |
| Capacity | 21,006.3 MW | includes storage where reported |
| End-use electricity | 76.3 TWh | converted from PJ |
| Net international exports | 0.3 TWh net import | positive = export |
| Interprovincial in-flows | 1.3 TWh | Quebec’s in-flow is mostly Churchill Falls |