This section describes the methodology for assessing generating resource and energy storage technologies and developing reference plants for consideration in the 2021 Power Plan. Following an initial assessment and categorization of all future resource options viable in the Pacific Northwest, in-depth quantitative and qualitative analysis is performed on various resource technologies – some of which are then developed into reference plants. A reference plant is a collection of characteristics that describe a resource technology and its theoretical application in the region. It includes estimates of typical costs, configurations, logistics, and operating specifications. These reference plants become inputs to the Council’s Regional Portfolio Model (RPM) as options, along with energy efficiency and demand response, for selection to fulfill future resource needs.
Methodology for Developing New Generating Resource Reference Plants
When developing a reference plant, inputs and considerations include the methodology for determining quantifiable environmental costs and benefits, financial assumptions, the Council’s revenue requirements tool MicroFin, and the fuel price forecast. Other considerations, like state and federal policies, aide in shaping what generating resource options could play a role in the future regional power system.
Categorization of New Generating Resource Options
The Council prioritizes and categorizes generating resources based on a resource’s commercial availability, constructability, and quantity of developable potential in the Pacific Northwest during the 20-year planning period. For assessment purposes, generating resource technologies are classified into three categories: primary, secondary, and long-term (emerging technology) resources. The categorization is meant to act as a framework to determine which resource technologies will be developed into generating resource reference plants.
Per the Northwest Power Act, Section 3(4)(A)(i), “‘Cost-effective’ when applied to any measure or resource… must be forecast – to be reliable and available within the time it is needed” (emphasis added). In other words, a resource option must be available within the 20-year power planning horizon (in this plan, 2022-2041). This is typically applied through the consideration of resources that are commercially available at the start of the planning horizon. However, emerging technologies that are not commercially available at the beginning of the power plan but could potentially be available and deployable during the planning horizon are treated as long-term resources and evaluated in the analysis.
The Council develops generating resource reference plants based on typical regional configurations with estimated costs and performance characteristics for most of the primary resources and makes determinations about which – if any - secondary and long-term resources are developed into reference plants.
- Primary: Significant resources that are deemed proven, commercially available, and deployable on a large scale in the Pacific Northwest at the start of the power planning period. These resources have the potential to play a major role in the future regional power system.
- Secondary: Commercially available resources with limited, or small-scale, developmental potential in the Pacific Northwest. While secondary resources are currently in-service or available for development in the region, they generally have limited potential in terms of resource availability or typical plant size. While secondary resources are not usually explicitly modeled, they are still considered viable resource options for future power planning needs.
- Long-term: Emerging resources and technologies that have a long-term potential in the Pacific Northwest but are not commercially available or deployable on a large scale at the beginning of the power planning period.
For the 2021 Power Plan, the following table represents the categorization of new generating resource technologies. Resource technologies in blue were developed into full reference plants. The natural gas simple cycle combustion turbine using a frame technology was selected for development into a full reference plant as a proxy for other gas peaker technologies (e.g. the aeroderivative technology) because it is much less expensive – see the natural gas reference plant for more information. Conventional geothermal, while categorized as a secondary resource with limited development to date, was developed into a reference plant as an additional renewable, carbon-free resource option. For the long-term resources, an emerging technology proxy reference plant was developed based on small modular reactors – however it is meant to be representative of any emerging technology with future potential in the region.
Categorization of New Generating Resource Technologies for the 2021 Power Plan
|Solar PV||Conventional Geothermal||Small Modular Reactors (Nuclear)|
|Onshore Wind||Biomass, Biogas||Offshore Wind|
|Battery Storage (Lithium Ion)||Hydropower (Upgrades)||Enhanced Geothermal Systems|
|Solar PV + Storage||Small Hydropower||Carbon Capture and Sequestration|
|Pumped Storage||Combined Heat and Power||Ocean Energy (Wave, Tidal)|
|Natural Gas Combined Cycle Combustion Turbine||Distributed Generation||Hydrogen Gas Turbine|
|Natural Gas Simple Cycle Combustion Turbine (Frame)||Allam Cycle Gas Turbine|
|Natural Gas Reciprocating Engine|
|Natural Gas Simple Cycle Combustion Turbine (Aeroderivative)|
Methodology to Develop Reference Plants
Once the new generating resources with potential in the region were identified and classified, staff performed extensive quantitative and qualitative analyses on the various technologies. Reference plants were developed in configurations and locations that are realistic for operation in the region. Along with reference plant specifications, operating characteristics and cost estimates were developed. All reference plants were presented and vetted with the Generating Resources Advisory Committee (GRAC), an advisory committee to the Council populated with industry subject matter experts from different roles and locations around the region.
The Council develops cost estimates for reference plants based on a specific configuration and location in the region. Staff performed an extensive literature review of publicly available reports, media sources, public utility commission filings, utility integrated resource plans, and manufacturer catalogs and reports. In addition, staff tracked and compiled new and planned projects in the region, western interconnect, and across the United States for specific data points. Through this research, information such as capital costs, operating and maintenance (O&M) costs, technology performance, construction timelines, and plant lifetimes are compiled and plotted to identify consensus and trends. These plots are used as the basis for configuring realistic capital, variable O&M, and fixed O&M costs for each reference plant.
For the 2021 Power Plan, all generating resource reference plants are based off of 2019 technology (the technology that was available at the time the reference plants were developed) and are represented in 2016 year dollars. All reference plant inputs were frozen as of early 2020 in order to be transferred as inputs to the Council’s power planning models.
Forward Cost Curves
The forward cost curve represents the assumption that the technology cost will decline (for some resources at least) if selected to be built in a future year (recall that reference plants are based off of 2019 technology vintage and are represented in 2016 year dollars). For established resources like natural gas technologies, a 0.5% cost de-escalation is applied every year to reflect gradual, expected improvements. For newer resources with a lot of recent cost volatility and cost decreases, like wind, solar, and battery, the Council leaned on NREL’s forward cost curve trajectories from the 2019 Annual Technology Baseline report. (This NREL ATB has since been updated in 2020, but the 2019 version was the most current at the time that the inputs for the reference plants were frozen.) Pumped storage and conventional geothermal are not de-escalated due to development being site specific. There is considerable variation in project costs as evidenced from the projects in development in the region, and the reference plant capital cost estimate takes that range into account. Forward cost curves can be applied to overnight capital cost, variable O&M, and fixed O&M, when applicable.
Performance Improvement Rates
Similar to a forward cost curve, reference plants with a given capacity factor or heat rate based off of 2019 technology vintage are assumed to improve if built in a future year due to technology innovations over time. If a reference plant is built in for example, 2025, it is assumed that the capacity factor has increase and heat rate has decreased (or become more efficient).
Methodology to Develop Maximum Buildout Assumptions
When developing generating resource reference plants for the 2021 Power Plan, the Council leveraged its transmission utilization analysis and created a new methodology for determining the maximum buildout potential of a given resource in a specific location. The maximum buildout is essentially an upper bound limit for potential selection by the Council’s power planning models. In other words, it is a ceiling that the model cannot surpass.
In the Seventh Power Plan, the maximum buildout was closely aligned with available commercial transmission inventory. This meant that in certain locations for some resources, there was very little potential buildout available for selection. In other locations with greater inventory, there was higher potential. However, as evidenced by the actual utilization of the system, there is often physical capacity available even on paths with limited long-term firm inventory. As clean policies and goals were adopted across the region and the cost of renewable resources dropped significantly, it became clear that the paradigm of requiring 24 hours/7 days a week/365 days a year firm, point-to-point transmission contracts is not sustainable going forward without changes to transmission access or significant and costly transmission expansion.
After significant outreach with advisory committees and stakeholders, the Council settled on a new maximum buildout methodology for the draft 2021 Power Plan. Rather than limit resource potential based on available transmission inventory or physical utilization of the transmission system, the maximum buildout for a reference plant is based on the aggregate regional load less any technical limitations. Technical limitations consist of limited potential based on: identified technical achievable potential, gas pipeline constraints, realistic build-rate of projects based on project development pipeline and/or manufacturer supply chain, etc. For example, the maximum buildout of conventional geothermal is limited to the technical potential in the region, as identified by the U.S. Geological Survey from 2008. This methodology is slightly different in the AURORA capacity expansion model which was used for the wholesale price forecast and WECC-wide buildout. Since AURORA operates within balancing authority bubbles, the maximum buildout is the balancing authority’s peak load + export capability. This new methodology allows the model to select resource acquisitions based on cost, policy requirements, and operational constraints – and allows for a lower cost new resource to potentially dispatch ahead of an existing resource.
When selecting this methodology, Council staff and stakeholders considered how it would affect the eventual buildout in the 2021 Power Plan. One question we heard was, would this methodology lead to overbuilds of resources that wouldn’t be realistic within the realm of the current transmission paradigm that we operate in? This methodology does not allow for an overbuild beyond the capabilities of the current system; rather, it allows for higher utilization of the current system with the model selecting based on economics, adequacy, and policies. There are also safeguards built into the modeling, for example curtailment penalties, declining capacity contribution of renewable resources that limits overbuild, and checks within the hourly models for operational feasibility within the transmission system. We also heard that many utilities already operate in this fashion, building and purchasing resources on non-firm contracts – either using conditional firm or assuming short-term firm availability.
Methodology for Determining Quantifiable Environmental Costs and Benefits and Due Consideration
The Northwest Power Act, Section 4(e)(3)(C), requires that the Council develop and apply a “methodology for determining [the] quantifiable environmental costs and benefits” of new electric generating and conservation resources. The methodology for determining quantifiable environmental costs and benefits is to consider a resources’ costs and benefits to the environment that are quantifiable and directly attributable to the resource (not incidental or indirect) – recognizing that not all environmental effects are quantifiable.
In the 2021 Power Plan, the Council’s methodology for determining quantifiable environmental costs and benefits is summarized as follows:
- Account for the financial costs of compliance with existing environmental regulations in the cost of new resources. See application of this below.
- Recognize that residual and unregulated environmental effects exist and describe them qualitatively in the plan. In addition, consider these effects when determining a resource strategy. See the Environmental Effects of Generating Resources for a high-level summary some of the primary environmental effects of generating resources. For an in-depth description of the lifecycle impacts associated with electricity generation, see Appendix I of the Seventh Power Plan.
- Address and consider costs of compliance with proposed regulations on a case-by-case basis. In the development of the 2021 Power Plan, there were no proposed environmental regulations that proposed stricter requirements that pertained to new resources and therefore there were no costs of compliance with proposed regulations added to any new resource costs.
- Not attempt to include quantified environmental benefits in new resource costs, beyond a few historic examples.
Therefore, the estimated costs of compliance with existing regulations is the primary component of the Council’s methodology for determining quantifiable environmental costs and benefits, and, when quantifiable, these costs are included as part of the total system cost of new resources.
See details on the Council’s development of the methodology for determining quantifiable environmental costs and benefits and description of how the Council gave due consideration (see Section 11) to environmental quality along with the other factors consistent with the requirements of Section 4(e)(2). In addition, see the quantifiable resource cost framework that summarizes and reflects how different costs and benefits are incorporated into the analysis.
The Council’s planning assumes that all new generating and conservation resource options will comply with existing federal, state, tribal, and local environmental regulations. Therefore, the estimated costs of compliance—when quantifiable—are included as part of the system cost of a new resource, and the cost of compliance is the primary method the Council has used to capture and quantify environmental costs in past plans. The cost of compliance includes, for example, the cost to comply with existing environmental regulations governing air and water emissions, siting regulations, waste disposal, fuel use (extraction and production), and fish and wildlife protection and mitigation costs when quantifiable and directly attributable to the new resource. Compliance with existing regulations is usually achieved via equipment or technology selections. Therefore, the costs of compliance with existing environmental regulations are generally factored in or accounted for within the resources’ capital costs. Unfortunately, it is often not possible to extract the compliance costs as a separate line item in the new generating resource reference plant cost estimates as they are rolled up in the equipment, siting and licensing, and operating costs.
The Council uses consistent global financial assumptions across the power plan – for example, a consistent discount rate and year dollars – as well as unique financial assumptions that pertain to certain inputs, like generating resource reference plants. The following table outlines the major financial assumptions used to calculate generating resource reference plant cost estimates.
Many of these financial assumptions are specific to MicroFin, the Council’s financial revenue requirements model. The financial assumptions which are input to MicroFin have an impact on the resulting levelized costs. For example, each generating resource reference plant has a set estimate for the overnight capital cost, regardless of who pays for the plant. However, the cost of capital to actually build the plant may vary based on the financial sponsor – such as a municipal or public utility, an investor-owned utility (IOU) or an independent power producer (IPP). Other important financial assumptions include the discount rate, rates of return, and investment tax credits.
|Financial Assumption||Investor-Owned Utility*|
|Federal Income Tax Rate||21 %|
|State Income Tax Rate||5 %|
|Property Tax||1.4 %|
|Debt Fraction||50 %|
|Debt Term||25 – 30 years|
|Debt Interest Rate (nominal)||6.69 %|
|Return on Equity (nominal)||10 %|
|Discount Rate||3.75 %|
*The financial assumptions used for calculating levelized costs were consistent with an IOU sponsor.
MicroFin is a Microsoft Excel-based financial revenue requirements tool that is used by the Council to calculate the levelized fixed cost (for planning and construction) and the full levelized cost of energy (LCOE) for generating resource reference plants. The levelized fixed costs are inputs to the Council’s power planning models (in particular, the RPM), however the levelized cost of energy is an external calculation that can be used as a metric for comparison between generating resource alternatives. For more information on the LCOE metric and the LCOE of 2021 Power Plan generating reference plants, see the “Levelized Cost of Energy” section.
MicroFin was redeveloped by staff in 2019 for use in the 2021 Power Plan. Staff presented a beta version of the tool to the Generating Resources Advisory Committee (GRAC) and select industry financial experts, seeking feedback and testing assistance. The current version of MicroFin is streamlined; for example, there is only one financial sponsor available for selection (investor-owned utility). Staff will continue to update and expand the features of MicroFin for use in the future.