There are several assumptions used across different analytical aspects of the 2021 Power Plan. These are detailed below.
The plan analysis period is 20 years - October 2021 through September 2041 – or, water year 2022 through water year 2041. For brevity, this period is often simply referred to as 2022 through 2041. The focus of resource recommendations is on the near-term action plan period, October 2021 – September 2027. The regional portfolio model analysis period is quarterly, defined as fall (Oct – Dec), winter (Jan – Mar), spring (Apr – June), and summer (July – Sept). The analysis also focuses on daily peak and off-peak periods. In contrast to the traditional WECC periods of heavy and light load hours, the on-peak periods for the 2021 Plan are 7pm – 10:59pm Monday – Saturday, and all other hours are off-peak.
Economic and financial assumptions
There are two main economic and financial assumptions. All financial information is presented in 2016 dollars and the discount rate is 3.75%. Deflators to translate from other years to 2016 can be found here. The discount rate is based on a weighted average cost of capital (WACC) across a range of regional public and private utilities and further information on the development of the discount rate can be found in this presentation.
Resource cost framework
The Act directs the Council to develop a power plan that gives priority to new resources which the Council determines to be cost-effective. “Cost-effective” when applied to any measure or resource under the Act, means that such measure or resource is forecast to be reliable and available within the time it is needed and forecast “to meet or reduce the electric power demand … at an estimated incremental system cost no greater than that of the least-cost similarly reliable and available alternative measure or resource, or any combination thereof” (Northwest Power Act, §3(4)(A)). Therefore, a resource is cost-effective only in comparison to other measures/resources or any combination thereof that are similarly reliable and available, and the ‘incremental system costs’ provide a basis for that comparison
System cost, as the term is defined in the Act, means an estimate of all direct costs of a measure or resource over its effective life, including, if applicable, the cost of distribution and transmission and such direct and quantifiable environmental costs and benefits determined based on the methodology developed by the Council in each power plan (Northwest Power Act, §3(4)(B)). To consider all these elements together in such a way that best meets the requirements of the Act, the Council uses a total resource costs and benefits perspective for its planning, which has been reflected in the Resource Cost Framework. Staff developed this framework, describing what costs are, or are not, included for a given resource, basing the determination on the definition of system cost, to document how the Council evaluates and accounts for costs when quantifiable across resources and to help support a consistent treatment of costs.
However, while the Council aims for consistency in its treatment of costs and benefits of conservation and generating resources whenever possible to promote a fair comparison of resources considered for development in the resource strategy, consistency is not required under the statute, and consistency is not always possible or appropriate across resources. Not all direct costs and benefits of a measure or resource are quantifiable nor are all costs equally applicable as the statute acknowledges may be the case in the definition of system costs. Additionally, especially when considering quantifiable environmental costs and benefits, the Council takes care to not double count a quantified effect as both a cost for one resource and a benefit for another resource.
One cost considered and reflected in the resource cost framework, for which additional context may be helpful, is the value of certain resources to defer investment in transmission and/or distribution systems. The 2021 Plan used a deferred transmission value of $3.08 per kilowatt-year and a deferred distribution value of $6.85 per kilowatt-year (levelized in 2016$). Details on the methodology used to estimate these values and the Council’s efforts to develop the methodology with regional input and review can be found in this presentation. To summarize simply here, regional utilities were asked to complete this workbook to estimate their historical and/or projected expenditures for transmission and distribution upgrades that may be deferrable, which were then weighted to estimate a regional value. Both deferred transmission and distribution values were applied to energy efficiency, demand response, and battery storage. The deferred transmission value was applied to the pumped storage reference plant. As noted above, these deferred transmission and distribution values are meant to represent an average value across the region. There may be locations where a resource could have significantly higher value to defer build (such are described as “non-wires alternatives”); however, there are also locations where such resources have negligible value.
In the regional portfolio model, the loads and resources are compared at a common point of generation busbar. Distributed resources (energy efficiency and demand response) are grossed up to account for line losses that would have occurred had a central generator produced the power saved. Due to improvements in transformer efficiency, the 2021 Power Plan estimates the transmission and distribution losses decrease over time, by 0.01 percent per year. For the behind-the-meter resources, the average loss over the 20 year planning horizon was used and assumed to be 4.7 percent for distribution and 2.3 percent for transmission, the calculation can be found here. For energy efficiency, there is further refinement based on the portion of the losses that are resistive losses versus no-load losses. Detailed assumptions can be found in the ProCost model. In Aurora and GENESYS, transmission losses are dependent on the path and calculated for every hour. They range from 1 to 6.6 percent (across the entire WECC) and details are available by request of the Aurora archive.
Greenhouse gas parameters
The social cost of carbon is incorporated into the regional portfolio analysis to account for the damage cost of emissions from generating resources. In the 2021 Plan, estimates of the these costs are based on the social cost of carbon from the federal interagency working group (IWG), 2016 revision, assuming a 2.5 percent discount rate. The table of the social cost of carbon from the 2016 IWG report can be found here and is presented in the graph below.
The 2021 Plan includes emission rates from generating plants for carbon dioxide, nitrous oxide, and methane and the global warming potential from each are from the Intergovernmental Panel on Climate Change (IPCC) Fifth Assessment Report (AR5), summary available here. In the regional portfolio model, the carbon damage cost is included as one component of the net present value of the total system cost. Within the Greenhouse Gas Tipping Point scenario, additional analysis was done to not only include the carbon damage cost as a component of net present value of total system cost, but to also have the carbon costs inform the resource dispatch. Similarly, for GENESYS and Aurora, the social cost of carbon was added in as part of the dispatch cost only for the Greenhouse Gas Tipping Point scenario. More details on the Aurora analysis including the cost of carbon within the dispatch cost to estimate the WECC-wide price buildout are provided here.
Climate change analysis
The impacts of global climate change are incorporated in the plan’s analysis. Future climate temperatures and streamflows are obtained from three general circulation models (GCMs) that have been downscaled to the Northwest region. The three models, all assuming an 8.5 representative concentration pathway, plus the downscale methodology (BCSD or MACA) are: CanESM2_RCP85_BCSD_VIC_P1, CCSM4_RCP85_BCSD_VIC_P1 and CNRM-CM5_RCP85_MACA_VIC_P3. More details on these scenarios and what they represent can be found here. Details on how the varied impacts from these scenarios were incorporated across the analysis can be found here. Note, for energy efficiency and demand response, analysis is limited to a single future weather condition and the GCM CanESM2_RCP85 was selected. More information on how that was incorporated within the energy efficiency supply curves is available here.
 For WECC and BPA, heavy load hours are times of heavy electricity usage from 6 am to 10 pm Monday through Saturday, light load hours are times of low electricity usage from 10 pm to 6 am Monday through Saturday and all day Sunday.
This comparative exercise to determine cost effectiveness as provided for under the Act is detailed more thoroughly in the Cost Effective Conservation Recommendation Summary.
 For conservation, this is referred to as the Northwest Resource Cost
 The choice of the 2.5% discount rate is consistent with the Clean Energy Transformation Act in Washington. Currently Washington is the only state in the Northwest to have codified the discount rate into law. Using the same discount rate facilitates use of the 2021 Power Plan in Washington by being consistent with the legally required discount rate for Washington utilities. It is also reflective of a future value of emissions generated or avoided today.
 For demand response, the load forecast for the CanESM2_RCP85 climate future was used for the analysis and no further adjustments were made.