2025 Western Assessment Supplemental Information

Current resource mix

Natural gas dominates the resource mix in the Alberta subregion, with 61% of the installed capacity. Wind generation makes up 25% of the resource mix, while solar and hydro make up 8% and 4%, respectively.

2035 resource mix

If all generating resources included in current resource plans are built, in 2035 natural gas's share of the resource mix will decrease to 45%, while solar's share will increase to 23%. Battery storage is expected to grow from 1% of the resource mix to 3% in 2035.

Planned additions

The subregion is expected to add close to 10 GW of new generation over the coming decade, primarily solar (5 GW) and wind (3 GW).

Planned retirements

No retirements are planned in the Alberta subregion through 2035 according to current resource plans.

Annual and peak demand

Demand in the subregion is forecast to grow by 9% over the coming decade, while peak demand is projected to increase 8%. A major driver of demand growth in this subregion is transportation electrification.

Loss of Load

Alberta saw no loss of load in any of the scenarios.

Resource mix

Basin’s resource portfolio as of year-end 2024 is primarily coal and natural gas. The two make up 51% of nameplate capacity in the subregion. Wind and solar make a combined total of 36% of the resource mix, with the remaining portfolio primarily composed of hydro resources.

2035 resource mix

Over the next decade, wind and solar additions are anticipated to shift the resource mix to 51% variable energy resources (VER) and 33% thermal resources. BESSs are anticipated to make up 8% of the resource mix in the subregion by year-end 2035.

Planned additions

Basin has over 15 GW of resource additions planned from 2026 through 2035. Slightly over 40%, or 6 GW, of the planned additions are wind resources, and over 25%, or 4 GW, are solar resources. BESS makes up 18%, or 3 GW, of the resource additions in the subregion, with half of the BESS capacity planned to be added in 2026.

Planned retirements

Approximately 2.2 GW is planned for retirement through 2035, almost half of which are coal (980 MW). 700 MW of wind resources are planned for retirement over the decade, along with 360 MW of natural gas generation.

Annual and peak demand

Demand in the subregion is forecast to grow by almost 26% over the coming decade, while peak demand is projected to increase 18%. Interconnection-wide annual energy load is projected to increase by 25%, and peak energy by 20%. Main contributors to demand growth in the Basin subregion are data centers and semiconductor manufacturing.

Loss of Load

The heat maps below highlight the loss of load in several scenarios.

The heat maps for 2030 and 2035 67% Additions Scenario provide the clearest picture of the risk hours for the subregion. Basin is summer-peaking with peak load generally occuring between 3 p.m. and 4 p.m. However, during the summer, heat can linger after the peak hour, resulting in elevated demand lasting through the evening. Basin’s planned resource additions are primarily wind and solar. The summer is not generally as windy as winter or shoulder seasons, and solar begins to dissipate in the evening. The elevated loads, coupled with a reduction in solar output during the evening hours, and general variability of wind, results in Basin showing the greatest risk to resource adequacy between 5 p.m. and 10 p.m. during July and August. Summer evenings also correspond with elevated demand in the Rocky Mountain and California subregions, lessening import availability from these subregions to Basin and further contributing to the loss of load.

Current resource mix

Hydro dominates the resource mix in the British Columbia subregion with 89% of the installed capacity. Biomass makes up 5%, wind 4%, and natural gas 2% of the resource portfolio as of year-end 2024.

2035 resource mix

If all generating resources included in current resource plans are built, in 2035, hydro's share of the resource mix would decrease to 83%, primarily due to a large influx of wind capacity, which would then made up 10% of the resource portfolio.

Planned additions

2.2 GW of new generation is planned in the subregion over the coming decade, including 1.5 GW of wind in 2030. There is also .5 GW of additional hydro capacity planned in 2032.

Planned retirements

Approximately 290 MW of natural gas generation is slated for retirement over the next decade.

Annual and peak demand

Demand in the subregion is forecast to grow by 8% over the coming decade, while peak demand is projected to increase 3.4%. Population growth, transportation and industrial electrification, and natural gas processing all contribute to demand growth in this subregion.

Loss of Load

British Columbia saw no loss of load in any of the scenarios.

Current resource mix

Natural gas makes up 37% of the resource mix in the California subregion on a nameplate capacity basis, followed by solar, which makes up 24%. Hydro and BESS make up 12% and 11%, respectively. Wind is 8% of the resource mix.

2035 resource mix

If all generating resources included in current resource plans are built, in 2035, natural gas's share of the resource mix will decrease to 25%, while battery storage and wind will each increase to 17% and solar to 26%.

Planned additions

The subregion is expected to add 49 GW of new generation over the coming decade. That includes 19 GW of wind, 15 GW of solar, and 11 GW of BESS. Approximately 2 GW of natural gas and geothermal generation is expected to be added.

Planned retirements

Nearly 6 GW of generation is planned for retirement over the coming decade, nearly all of it natural gas (3.6 GW) and nuclear (2.3 GW).

Annual and peak demand

Demand in the subregion is forecast to grow by 26% over the coming decade, while peak demand is projected to increase 21%. Transportation electrification and the anticipation of additional load during extreme heat events are major factors of demand growth for this subregion.

Loss of Load

The California subregion did not show loss of load in the All Additions or High Load scenarios. California only shows loss of load under the 67% Additions Scenario, and not until 2032, 2033, and 2035. The loss of load heat maps for 2035 for the 67% Additions Scenario are shown below.

California shows two LOLHs in 2035 totaling 471 MWh of EUE in September. This occurs between the hours of 6 and 7 p.m. This time frame is slightly after peak, which generally occurs between 4 and 5 p.m. in this subregion. During the summer, heat can linger after the peak hour, resulting in elevated demand lasting through the evening. California is anticipated to retire 6 GW of natural gas and nuclear capability over the next decade, while adding approximately 34 GW of solar and wind. Solar availability diminishes in the evening, and wind output during this time can vary. The elevated load during summer evenings, coupled with thermal retirements and diminishing solar availability during this period, result in the identified LOLHs shown below.

Current resource mix

Natural gas makes up 72% of the resource mix on a capacity basis. This is followed by geothermal at 13%, solar at 8%, and petroleum at 7%.

2035 resource mix

If all generation resources are built according to current resource plans, in 2035, solar's share of the resource mix will increase to 14%, while geothermal and petroleum will decline to 9% and 4%, respectively. Natural gas remains at 72%.

Planned additions

600 MW of solar is planned to be built over the coming decade in the Mexico subregion. This occurs primarily in years 2026 and 2028.

Planned retirements

The subregion has no retirements through 2035.

Annual and peak demand

Demand in the subregion is forecast to grow 45% over the coming decade, while peak demand is projected to increase 41%. The anticipation of additional load during extreme heat events is the major factor driving demand growth for this subregion.

Loss of Load

The Mexico subregion only shows loss of load under the 67% Additions Scenario in years 2034 and 2035. The loss of load heat maps for 2035 are provided below for the 67% Additions Scenario.

Mexico is a summer-peaking subregion that generally experiences peak load between 4 and 5 p.m. August is typically the hottest month in the subregion, thereby experiencing the greatest demand. Similar to California and Basin, summer heat can last beyond the peak hour, resulting in elevated demand through the evening. Solar is diminished during this period, and solar resources are the only additions planned for this subregion. The significant increase in demand over the next 10 years, coupled with the solar resource additions, which have diminished efficacy as daylight wanes, are the primary reason for the LOLHs during summer evenings after peak. The California subregion does support Mexico if there is surplus energy to do so, but despite the Mexico subregion importing up to the transfer limit from California, loss of load still occurs.

Current resource mix

As of year-end 2024, the Northwest’s resource portfolio primarily consists of hydro, natural gas, and wind resources. Hydro resources are a significant contributor to the Northwest’s energy supply making up 55% of the resource portfolio. Natural gas makes up 18%, and wind accounts for 16%.  

2035 resource mix

Resource plans indicate a significant influx of wind, solar, and BESS resources by year-end 2035. Wind grows to a 27% portfolio share, BESS increases to 6%, and solar increases to 9%.

Planned additions

14 GW of new generation is planned in the subregion over the coming decade, including almost 8 GW of wind and 3 GW of battery storage.

Planned retirements

The Northwest has approximately 340 MW of retirements slated to occur between 2026 and 2035. Over one-third of these retirements is biomass facilities. Hydro, wind, and solar retirements make up approximately half the retirements. It is worth noting that part of the renewable retirements may be repowers or non-renewals of purchase power agreements. The remaining retirements are primarily natural gas resources, the majority of which are set to retire in 2035.

Annual and peak demand

Demand in the subregion is forecast to grow by 24% over the coming decade, while peak demand is projected to increase 21%. Major drivers of demand growth in the Northwest include data centers, residential and transportation electrification, customer growth, and semiconductor manufacturing.

Loss of Load

The Northwest shows loss of load in all scenarios beginning as early as 2028 in the 67% Additions Scenario. Heat maps showing the timing and seasonal loss of load are provided below for the 2030 and 2035 All Additions, 67% Additions, and High Load scenarios.

The Northwest is unique in that it experiences loss of load in the summer and winter in all scenarios, as well as the shoulder seasons in the High Load Scenario. The Northwest is also unique because, over the last decade, it has experienced system peaks both during the morning ramp (between 7 and 10 a.m.), which are more typical, and during the evening between 5 and 6 p.m. Morning ramps in the winter coincide with the greatest frequency of loss of load, whereas in the summer, the evening peak hours are when the greatest energy shortfalls are projected to occur. LOLHs and LOLEvs are greatest in the winter months, primarily in January and December, indicating that these months have a higher propensity for loss of load. Electricity is the predominant source of heat in the Northwest subregion, with the coldest temperatures occurring in the early morning and again dropping in the evening. In the winter, solar primarily contributes between the hours of 9 a.m. and 3 p.m., coinciding with the hours of greatest demand. Solar irradiance is weaker during the winter, which also lessens the contribution from solar resources. Wind makes up over 50% of the projected resource additions for the subregion, however these resources have the highest variability in energy output compared to other VERs. Wind can be prone to icing or overspeed during extreme cold weather events, which may minimize their availability during periods of elevated load. The significant demand associated with heating electrification, coupled with the timing of solar output and high wind variability, are the main drivers of LOLHs during the winter. In the summer, the primary driver of LOLHs is solar availability diminishing in the evening during periods of elevated demand. Given that BESS resources are modeled as being fully available for discharge, and that the All Additions Scenario shows LOLHs, these results indicate that the Northwest will need additional resources to meet demand over the next decade.

The California, Alberta, and British Columbia subregions support the Northwest during the morning winter ramps and evenings. However, transfer limitations from these subregions are frequently reached when attempting to mitigate loss of load in the Northwest, preventing further support to the subregion. In the summer, the California and Rocky Mountain subregions must meet their own native load obligations in the evenings, and can only provide limited support to the Northwest. The Alberta subregion also assists the Northwest during summer evenings but runs into transfer limitations. Beyond additional resources, additional transfer capability to the Northwest would also help reduce the projected loss of load in the subregion.

Current resource mix

On a capacity basis, the resource portfolio in the Rocky Mountain subregion primarily consists of natural gas, coal, and wind resources. Natural gas and coal together make up 55% of the resource mix, with wind at 21%. Solar and hydro each make up 10%. Battery storage is at 1%.

2035 resource mix

If all generation resources are built according to current resource plans, the capacity of thermal generation in the subregion will decrease to 40%, from 55% today. Wind would increase to 31% of the resource mix, while solar would increase to 14% and BESS to 6%.

Planned additions

15 GW of new resources is planned in the subregion over the coming decade, including almost 8 GW of wind and 3 GW of both natural gas and solar.

Planned retirements

Over 6 GW of generation is planned for retirement over the coming decade, including 2.8 GW of coal and 1.7 GW of both natural gas and wind.

Annual and peak demand

Demand in the subregion is forecast to grow by 27% over the coming decade, while peak demand is projected to increase 23%. Major drivers of demand growth in the Rocky Mountain subregion include data centers, as well as commercial and industrial customer growth.

Loss of Load

The Rocky Mountain subregion does not show loss of load in the All Additions or High Load scenarios. This subregion shows loss of load under the 67% Additions Scenario for years 2030 through 2035, as well as one LOLH in 2034 and 2035 of the 85% Additions Scenario. The loss of load heat maps for the 2030 and 2035 67% Additions Scenario are provided below.

The Rocky Mountain subregion shows one LOLH for 5 MWh of EUE in 2030 and 18 LOLHs for 4,297 MWh of EUE in 2035 in the 67% Additions Scenario. The LOLHs occur between the hours of 4 and 9 p.m., primarily in July and August. This time frame includes the peak hour, which is anticipated to occur in the summer between 4 and 5 p.m. The Rocky Mountain subregion is showing a significant increase in both its annual demand and peak hour forecasts. The 2035 peak hour demand is projected at over 3 GW higher than last year’s forecast, and the annual demand totals close to 13 TWh higher than last year’s forecast. Similar to other subregions showing LOLHs during and shortly after their summer evening peak, these LOLHs are primarily a product of demand remaining elevated while solar output diminishes. In addition, there are over 6 GW of resource retirements with 4.5 GW of that being thermal resources. The additions in the 67% Additions Scenario total about 10 GW, with close to 7 GW of that being VERs. The reduction in additions, coupled with the increased uncertainty in energy output and unchanged retirements in the 67% Additions Scenario, also contribute to the LOLHs projected for this subregion.