Executive Summary
Accounting for existing resources, planned resources that are sited and licensed, and the implementation of the Council’s energy efficiency targets, the Northwest power supply is likely to become inadequate by 2021, primarily due to the retirement of the Centralia 1 and Boardman coal plants (1,330 megawatts combined). The loss-of-load probability (LOLP) for that year is estimated to be over 6 percent, which exceeds the Council’s standard of 5 percent.
By 2022 the LOLP is projected to rise to about 7 percent, due to the additional retirements of the North Valmy 1 coal plant, the Colstrip 1 and 2 coal plants and the Pasco gas-fired plant (479 megawatts combined). In 2023 the LOLP is expected to remain at about 7 percent. The increase in LOLP would be higher except for the Council’s targeted energy efficiency savings and savings from codes and federal standards. Additional capacity needed to maintain adequacy is estimated to be on the order of 300 megawatts in 2021 with an additional need for 300 to 400 megawatts in 2022.
It should be noted that this analysis examines the adequacy of the aggregate regional power supply. Individual utilities within the Northwest have varying resource mixes and loads and, therefore, have varying needs for new resources. In aggregate, Northwest utilities have identified 540 megawatts of wind, about 800 megawatts of (unspecified fuel source) capacity and other small resources that could be developed by 2021, if needed.[1] These planned resources are not included in this assessment because they are not sited and licensed. Also excluded from this analysis are approximately 400 megawatts of demand response, which is the remaining part of the 600 megawatts identified in the Council’s Seventh Power Plan as likely being available by 2021. While the Council believes this level of demand response will be available, it is not included in this analysis because of ongoing concerns regarding barriers to its acquisition.
While it appears that regional utilities are well positioned to face the anticipated shortfall beginning in 2021, different manifestations of future uncertainties could significantly alter the outcome. For example, the results provided above are based on medium load growth. Reducing the 2023 load forecast by 2 percent[2] results in an LOLP of just under 5 percent and has roughly the same effect as adding 650 megawatts of capacity. Increasing the load forecast by 2 percent[3] raises the 2023 LOLP to about 10 percent and almost doubles the amount of capacity needed (from 650 to 1,000 megawatts) to satisfy the Council’s 5 percent standard.
The reference case results assume a conservative level of available Southwest market supply. Increasing that supply by 500 megawatts lowers the 2023 LOLP to a little over 5 percent and only about 50 megawatts of additional capacity are needed to meet the Council’s 5 percent standard. However, decreasing the Southwest market supply by 500 megawatts raises the LOLP to 8.6 percent and would require 1,050 megawatts of additional capacity.
Reducing the load forecast by 2 percent and increasing the Southwest market availability by 500 megawatts lowers the LOLP to 3.5 percent and no additional capacity is required for adequacy. However, increasing the load forecast by 2 percent and decreasing the Southwest market by 500 megawatts raises the LOLP to 12 percent and requires about 1,500 megawatts of additional capacity to satisfy the Council’s adequacy standard.
Potential shortfall events for the 2023 operating year occur almost exclusively during December, January and February. Event durations range from a single hour to over 24 hours and average about 20 hours. The most common event duration is 16 hours, which occur over the commonly defined peak hours of the day. Events also tend to have a uniform hourly magnitude because, whenever possible, the hydro system is operated in a way to spread out projected shortfalls evenly across the peak hours of the day. For example, it is much easier to resolve a flat 100 megawatt shortfall over the 16 peak hours of the day than a 2-hour 800 megawatt shortfall
[1] Source: Pacific Northwest Utilities Conference Committee’s 2018 Northwest Regional Forecast.
[2] This means multiplying the load in each hour of the year by 0.98.
[3] This means multiplying the load in each hour of the year by 1.02.
