Throughout the 2021 IRP, PSE will provide consultation updates to the public. Consultation updates are a brief summary of a consultation activity (e.g. webinar, workshop, etc.) and the feedback received. The consultation updates will demonstrate how PSE has responded to the feedback and if/how PSE has incorporated the feedback into the IRP activity discussed.
Webinar 4: Demand-side resources | July 14, 2020
Posted 8/4/2020 | Open in new window
The following consultation update is the result of stakeholder suggestions gathered through an online Feedback Form, collected between July 7 and July 21, 2020 and summarized in the July 28 Feedback Report. The report themes have been summarized and along with a response to the suggestions that have been implemented. If a suggestion was not implemented, the reason is provided.
PSE also thanks Joni Bosh, Fred Huette and Amy Wheeless of Northwest Energy Coalition (NWEC) for meeting with PSE staff on Juy 29 to help further clarify their questions and suggestions.
Electric Vehicles – Demand Response Program
PSE received feedback from Brian Grunkemeyer and Rob Briggs (Vashon Climate Action Group) concerning the high levelized cost assumption of the DR program for electric vehicles and requested Cadmus to provide more details on their estimate.
Cadmus’ EV estimate of $300 from the Regional Technical Forum (RTF) study is reasonably close to the cost data that Brian provided on July 31, 2020 of $250 per participant. The other costs that are included in the $362 levelized cost are detailed in the table below:
Assuming 1 FTE to set up the program.
$ per year
Assuming 1 FTE.
$ per new participant
The Regional Technical Forum’s researched incremental equipment cost of networked 240V level 2 charger compared to non-networked level 2 charger is $287 (Shum 2019).
$ per new participant
Assuming this product requires higher marketing cost than the BPA assumption (Cadmus 2018a) for DLC products: $25 per new participant.
$ per new participant
In line with incentives for residential DLC space heat products.
% of existing participants per year
In line with BPA assumption (Cadmus 2018a) for DLC products.
% of segment/
The number of EV owners is aligned with the study's assumptions for energy efficiency. The proportion of EV owners that already have a residential 240V AC level 2 charger (64%) is based on research by the Regional Technical Forum (Shum 2019).
Peak Load Impact
kW per participant (at meter)
Based on 2021 Plan Workbook "Inputs_Product_ResEVSEDLC-Winter" peak load impact assumption.
% of eligible segment/end-use load
In line with assumptions for DLC products.
Based on 2021 Plan Workbook "Inputs_Product_ResEVSEDLC-Winter" event participation assumption.
Transmission & Distribution Deferral Cost Update
PSE received feedback from Kyle Frankiewich (WUTC) and Fred Heutte (NWEC) requesting more details behind the numbers on slide 13: “Updates in 2021 CPA: T&D deferral benefit.” The costs that the Power Council is using in their 2021 Plan is significantly lower that the ones used in the 7th Plan . The Council updated its assumptions for the 2021 Plan: no new T&D development projects were included in the update, and for T&D upgrade projects, only capacity related costs were included. In past IRPs, PSE has used the Council’s T&D deferral numbers. Since the costs came down substantially in the Council’s 2021 plan, PSE decided to update their own system related costs. The PSE system estimates came close to the updated Power Council estimates, these were presented on slide 13 of the July 14 Webinar.
PSE reviewed projects going back to 2010 and included projects or portions of the projects that were related to the capacity upgrades on the T&D systems. The costs for reliability projects and routine O&M were excluded as conservation will not impact these costs.
Details of the projects used to estimate the new T&D deferral costs are in Appendix A of the full PDF.
Fuel Conversion from Gas to Electric
PSE received feedback from Kyle Frankiewich, Willard Westre, Rob Briggs and Court Olson concerning inclusion of measures or sensitivities to test the impact of converting some end uses from gas to electricity use. PSE has added fuel conversion as a sensitivity for further discussion with stakeholders at the August 11 webinar.
Distributed Solar pV
PSE received feedback from Fred Heutte (NWEC) and Kyle Frankiewich (WUTC) that the cost curve was not up to date, and that a sensitivity should be considered with a lower cost curve. Fred referenced to the recently released (July 2020) 2020 ATB data from NREL.
Cadmus had used the 2019 ATB data in their webinar slide, and has since updated the distributed solar pv market potential using the 2020 ATB data. As NWEC had suggested the costs are lower.
The figure below shows the results. The business as usual (BAU) case, which represents the current net metering program, updated with the 2020 MTB Moderate Cost forecast, now shows 24-year cumulative potential of 336 MW, which is about 10% higher than the program’s straight line projection of 300 MW, which was shown in the August 14 webinar.
Furthermore, the 2020 ATB Advanced Cost Decline forecast shows 24-year cumulative potential of 608 MW.
Based on these results and feedback from the stakeholders, PSE will:
- Update the business as usual (BAU) case to the 2020 ATB Moderate Cost forecast, and
- Replace the PSE incentive sensitivity with the 2020 ATB Advanced Cost decline as the sensitivity
There was also a request for historical acheivements to date with respect to PSE’s distributed solar pv program. The following is the historical data for all customer classes, including a breakdown by sector:
Total historical installations:
Number of Systems
Installations by customer class:
Equity in the IRP
PSE has scheduled a discussion with WUTC staff regarding an equity assessment in the IRP. Further details will be available by the end of September.
Load Forecast in the CPA
PSE received feedback from several stakeholders expressing concerns that the load forecast used to develop the CPA was a draft and what might happen if the final load forecast is considerably different. There was also a general perception that the changes in load forecast have a major impact on the conservation savings.
Changes in load forecast have a relatively minor impact on the total acehievable potential. The CPA will be updated with the final load forecast.
Demand Side Resource Sensitivities
PSE received feedback from several stakeholders to consider several sensitivities – see section below on “Summary of all updates” for details. All stakeholder suggested sensitivities have been added to the August 11 webinar for further discussion.
Summary of all updates
PSE appreciates the feedback provided by stakeholders. In summary, the following changes will be implemented:
- Workbooks requested by NWEC – PSE is working with Cadmus to provide a measure details workbook for their review. This will be provided towards the end of August.
- T&D deferral cost update details – details of the updated T&D numbers are presented in Appendix A below.
- PSE will include a discussion and provide historical data on acheivements to date for PSE’s net metered distributed solar pV program in the demand side resources report.
- Electric Vehicle levelized cost for the DR program is summarized on page 1 of this report.
- Several sensitivities listed below were suggested by stakeholders. PSE will review the list of proposed portfolio sensitivities with stakeholders at the August 11, 2020 webinar and will seek feedback around the details of these sensitivities and additional sensitivities:
- PSE will remove the PSE incentive and PSE ownership sensitivities and instead consider the one proposed by the stakeholders: sensitivity with a lower cost curve using the 2020 ATB Advanced scenario.
- Accelerated DSR 6 year ramp for discretionary measures
- Accelerated DSR 8 year ramp for discretionary measures
- Non Energy impacts using EPA estimates
- Social discount rate of 2.5% consistent with the social cost of carbon from the technical support document
- Fuel conversion gas to electric
- PSE will update the CPA with the final load forecast and a discussion of the changes will be provided in the demand side report.
- Consultation Update #4: Demand Side Resources [PDF, 370 KB]
Webinar 3: Transmission Contraints | June 30, 2020
Posted 7/21/2020 | Open in new window
The following consultation update is the result of stakeholder suggestions gathered through an online Feedback Form, collected between June 23 through July 7, 2020 and summarized in the July 14 Feedback Report. The report themes have been summarized and along with a response to the suggestions that have been implemented. If a suggestion was not implemented, the reason is provided.
PSE also thanks Fred Huette and Joni Bosh of Northwest Energy Coalition (NWEC for meeting with PSE staff to help further clarify their questions and suggestions in follow-up meetings. A meeting with WUTC staff is scheduled for later in the month.
Battery interconnection cost
PSE received feedback from James Adcock, Don March (CENSE) and Fred Heutte (NWEC) concerning the proposed interconnection cost for batteries. PSE has consistently applied the interconnection cost described in the 2019 HDR Report (linked below) for all generic resources. For all battery types, the assessment assumes a 115 kV, 5-mile tie line to the point of interconnection and a breaker and one half interconnection arrangement at the point of interconnection. These are fixed capital costs, regardless of resource nameplate capacity. The capital cost adder in dollars per kilowatt may appear inflated for smaller nameplate resources such as battery resources (25 MW nameplate) and biomass facilities (15 MW nameplate).
Given the expectation for significant quantities of battery energy storage systems in the 2021 IRP, PSE will include a 100 MW nameplate battery. The interconnection for a 100 MW nameplate battery would be $91.80/kW in real 2016 US dollars.
HDR Report available here.
Dual purposed transmission
PSE received feedback from Willard Westre (Union of Concerned Scientists), Bill Pascoe, Katie Ware (Renewable Northwest) and Kyle Frankiewich (WUTC) supporting the inclusion of dual purposed transmission in the 2021 IRP. PSE will incorporate dual-purposed transmission where possible in the 2021 IRP models, in particular, transmission from the Mid-C hub, Goldendale Generating Station and Mint Farm Generating Station.
Colstrip Unit 4 transmission
PSE received feedback from Willard Westre, Bill Pascoe, Katie Ware (Renewable Northwest) and Kyle Frankiewich (WUTC) concerning the inclusion of 185 MW of transmission associated with Colstrip Unit 4. However, the pending sale of Colstrip Unit 4 includes the sale of 185 MW of transmission on the Colstrip Transmission System soit will not be modeled as part of the 2021 IRP process.
Firm transmission as a fraction of nameplate capacity
PSE received feedback from Willard Westre, Bill Pascoe, Katie Ware (Renewable Northwest), Fred Heutte (NWEC) and Kyle Frankiewich (WUTC) suggesting the inclusion of a sensitivity which models firm transmission as a fraction of full nameplate capacity for renewable resources. PSE will be modeling this as a sensitivity.
Pumped storage hydro in Montana
PSE received feedback from Bill Pascoe, Katie Ware (Renewable Northwest) and Fred Heutte (NWEC) supporting inclusion of pumped storage hydro as a resource in the Montana region. PSE reviewed available literature concerning the siting of pumped storage hydro and concluded that Montana does have significant potential for a pumped storage hydro resource. Therefore PSE will include pumped storage hydro as a resource in the Montana transmission region.
Modeling transmission uncertainty
On slide 35, PSE requested stakeholder feedback on methods to model transmission uncertainty. PSE proposed two possible methods: Option 1, modeling confidence level tiers as discrete sensitivities and Option 2, modeling confidence level tiers as time-dependent factors.
PSE received feedback from Katie Ware (Renewable Northwest), Fred Heutte (NWEC) and Kyle Frankiewich (WUTC) concering this topic. Stakeholders suggested that both methods provide value to the IRP modeling process. PSE has elected to model method Option 1, modeling confidence level tiers as discrete sensitivities.
Regional Transmission Organization (RTO) sensitivity
PSE received feedback from Katie Ware (Renewable Northwest) suggesting inclusion of a sensitivity to model the adoption of a Regional Transmission Organization (RTO) in the Pacific Northwest. PSE is still evaluating how modeling an RTO as a sensitivity could be successfully accomplished. A decision on whether this sensitivity will be included is dependent on PSE’s models to accurately evaluate an RTO and will be made later in the IRP process.
Expanded cross-Cascade transmission
PSE received feedback from Fred Heutte (NWEC) inquiring about the possibility of modeling expanded cross-Cascade transmission alternatives. PSE is considering modeling expanding our cross-Cascade transmission as an option, but will not have sufficient cost information to model that alternative in the 2021 IRP.
Detailed PSE transmission assumptions
PSE received feedback from Kyle Frankiewich (WUTC) requesting a detailed breakdown to PSE’s transmission wheels considered for the 2021 IRP. PSE will be following up with Kyle Frankiewich on July 27, 2020 to further understand his request.
California transmission region
PSE received feedback from Kathi Scanlan (WUTC), Kyle Frankiewich (WUTC) and Fred Heutte (NWEC) concerning transmission capacity and potential modeling of California-based resources. During the Energy Delivery team’s review of plausible available transmission, it was found that transmission out of California is significantly constrained. Therefore, no California-based resources will be modeling for the 2021 IRP. However, PSE’s existing activity in the Califorina ISO Energy Imbalance Market (EIM) will continue to be modeled.
Transmission from Boardman to Hemingway Project to PSE
PSE received feedback from Bill Pascoe, Katie Ware (Renewable Northwest) and Kyle Frankiewich (WUTC) concerning delivery of power from the Boardman to Hemingway (B2H) projectto PSE’s system. This feedback concerns the possible acquisition of transmission on the B2H and Gateway West transmission projects to access Wyoming and Idaho-based resources. Stakeholders noted that an additional BPA transmission wheel is necessary to bring the power home to PSE territory from the northern terminus of the B2H project.
PSE will include Bonneville Power Authority (BPA) provided transmission from B2H to PSE using standard BPA rates. These rates are: $22.20/kW-year for firm transmission plus $11.16/kW-year for wind integration or $8.20/kW-year for solar integration. These costs are in addition to capital costs discussed during the webinar.
Summary of all updates
PSE appreciates the feedback provided by stakeholders. In summary, the following changes will be implemented into the portfolio model:
- Include a sensitivity to model firm transmission as a fraction of nameplate.
- Add pumped storage hydro to the Montana resource region.
- PSE has elected to model method Option 1, modeling confidence level tiers as discrete sensitivities.
- PSE is still evaluating how modeling an RTO as a sensitivity could be successfully accomplished. A decision on whether this sensitivity will be included is dependent on PSE’s models to accurately evaluate an RTO and will be made later in the process.
- PSE does not have sufficient cost information to model the cross Cascade transmission in the 2021 IRP.
- PSE will include Bonneville Power Authority (BPA) provided transmission from Hemmingway to PSE using standard BPA rates.
PSE is committed to keeping our stakeholders informed of our progress toward incorportating feedback into the IRP process. PSE will review the list of proposed portfolio sensitivities with stakeholders at the August 11, 2020 webinar and will seek feedback around the details of these sensitivities and additional sensitivities.
- Consultation Update #3: Transmission Constraints [PDF, 82 KB]
Webinar 2: Electric Price Forecast | June 10, 2020
Posted 7/1/2020 | Open in new window
The following consultation update is the result of stakeholder suggestions gathered through an online Feedback Form, collected between June 4 through June 17, 2020 and summarized in the June 24 Feedback Report. The report themes have been summarized and along with a response to the suggestions that have been implemented. If a suggestion was not implemented, the reason is provided.
PSE also thanks Fred Huette of Northwest Energy Coalition (NWEC), Vlad Gutman-Britten of Climate Solutions, Bill Pascoe of Pascoe Energy representing Absoroka Energy & Orion Renewables and Katie Ware of Renewables Northwest for meeting with PSE staff to help further clarify their questions and suggestions in follow-up meetings..
Gas price forecast
PSE received feedback from Kathi Scanlan, Washington Utilities and Transportation Commission (WUTC) Staff, requesting the use of an updated gas price forecast to reflect the socioeconomic changes of the COVID-19 pandemic. The PSE gas price forecast is an amalgam of two price forecasts incorporating forward marks for the short-term forecast (5 years in the future) and a Wood Mackenzie forecast for the long-term forecast (greater than 5 years into the future). PSE has updated the forward marks portion of the forecast as reflected on the chart below. The chart compares the January 2020 and June 2020 gas forward marks forecast for the Sumas hub. The chart shows a significant drop in prices in year 2020 and a slight increase in prices for year 2021, and a very similar projection in years 2022 through 2026. Given the 2021 IRP timeframe extends from 2022 to 2045, PSE does not anticipate the change in forward marks prices to have a meaningful impact on the power price forecast.
PSE has contacted Wood Mackenzie for an updated long-term gas price forecast and was informed the forecast would be released in the coming weeks. PSE will examine the magnitude of change of the updated long-term gas price forecast and, if deemed significant, incorporate the new forecast into the power price model. Further details will be provided upon receipt and analysis of the new long-term gas price forecast.
Regional demand forecast
PSE received feedback from James Adcock, Kathi Scanlan, WUTC Staff, and Joni Bosh and Fred Heutte, NWEC, concerning PSE’s use of the Northwest Power and Conservation Council’s (the Council) 7th Power Plan regional demand forecast. Since the 7th Power Plan was published in 2016, concerns were raised about the applicability of the regional demand forecast for PSE’s 2021 IRP power price forecast. PSE has contacted the Council to request an updated demand forecast. The Council responded that the regional demand forecast intended for use in the 2021 Power Plan is not available for release at this time. However, the Council was able to provide the regional demand forecast used in the 2019 Update of the 7th Power Plan. PSE is currently reviewing the “2019 Update” regional demand forecast and intends to incorporate the updated information into the 2021 IRP power price forecast. Further details will be provided upon analysis of the updated regional demand forecast.
On slide 38 of the Draft Electric Price Forecast presentation, PSE solicited feedback on how to model Washington State’s renewable need. Two scenarios were presented: 22.9 million MWh by 2030 which equates to 90% adoption of renewable resources (Scenario 1) and 12.2 million MWh by 2030 which equates to 80% adoption of renewable resources (Scenario 2).
PSE received feedback from Vlad Gutman-Britten, Climate Solutions, Katie Ware, Renewable Northwest, Kathi Scanlan, WUTC Staff, and Joni Bosh and Fred Heutte, NWEC, on this topic. The majority of stakeholders suggested that PSE move forward with modeling Scenario 1 (higher renewable resource implementation in 2030) for the 2021 power price forecast.
PSE received feedback from Vlad Gutman-Britten, Climate Solutions, and James Adcock regarding the starting point for the ramp used for Washington state CETA requirements, as shown on slide 21. The renewable need will be updated with the demand forecast and an adjusted starting point for the renewable need ramp to start at the existing amount of non-emitting/renewable resources in 2022 and then ramp to the 2030 need. The ramp rate and demand forecast will be updated and further details will be provided upon completion of this analysis alongside other updates to gas price forecast and regional demand forecast discussed above.
Electric price forecast scenario selection
On slide 43 of the Draft Electric Price Forecast presentation, PSE solicited feedback on power price scenarios to include as part of the 2021 IRP. PSE received feedback from Vlad Gutman-Britten, Climate Solutions, Katie Ware, Renewable Northwest, Bill Pascoe representing Absaroka Energy & Orion Renewables, Kathi Scanlan, WUTC Staff, and Joni Bosh and Fred Heutte of NWEC on this topic. The table in this PDF summarizes the stakeholder suggestions for power price forecast scenarios.
In the table, cells highlighted orange represent a change from Scenario 1 and dark grey cells represent scenarios proposed by stakeholders but will not be included in the 2021 IRP. The ‘Comments’ column provides an explanation of how the scenario may be applied in the 2021 IRP. The 2021 IRP Scenarios will include Scenarios 1, 2, 3, 6, 9, 10, 11, and 12.
Summary of all updates
PSE appreciates the feedback provided by stakeholders. In summary, the following changes will be implemented into the power price model:
- Updated gas price forecast to include recent socioeconomic impacts of COVID-19 pandemic
- Inclusion of the 2019 Update to the 7th Power Plan regional demand forecast • Modeling of higher Washington State clean energy implementation in 2030 (i.e. Scenario 1)
- The renewable need will be recalculated with the 2019 Update of the 7th Power Plan regional demand forecast and a Washington CETA requirement ramp starting point at the existing amount of non-emitting/renewable resources in 2022
When the 2021 IRP power price scenarios are completed, PSE will provide a spreadsheet with a conversion from nominal to real dollars. PSE is committed to keeping our stakeholders informed of our progress toward incorportating feedback into the IRP process. PSE will review the list of scenarios with stakeholders at the August 11, 2020 webinar and open for the floor for discussion around the details of these scenarios. Then the completed power price forecast scenarios will be presented at the October 20, 2020 webinar.
- Consultation update #2: Electric Price Forecast [PDF, 121 KB]
Webinar 1: Generic Resources Assumptions | May 28, 2020
Posted 6/18/2020 | Open in new window
The following consultion update is the result of stakeholder suggestions gathered through an online feedback form, collected between May 13 through June 4, 2020 and summarized in the June 11 feedback report. The report themes have been summarized and along with a response to the suggestions that have been implemented. If a suggestion was not implemented, the reason is provided.
Pumped Storage Hydro
PSE received feedback from Nate Sandvig, National Grid Ventures, Bill Pascoe, Pascoe Energy representing Absoroka Energy & Orion Renewables, Katie Ware and Max Greene, Renewable Northwest; Fred Huette and Joni Bosh, Northest Energy Coalition (NWEC); Kathi Scanlan, WUTC staff; and Vlad Gutman-Britten, Climate Solutions, on the cost and operating assumptions of pumped storage hydro. This feeback included:
1. Overnight capital cost (cost that does not include interest/cost of capital)
PSE has further reviewed other data sources for the capital cost of pumped storage hydro and has included the estimates from the Pacific Northwest National Laboratory (PNNL) report on energy storage. This estimate was already included as DOE Hydrowires 2019. Further, PSE has reviewed the assumptions for PacifiCorp’s cost estimate (PacifiCorp, 2019 IRP) and concluded that it is very similar to the Swan Lake project and removed the PacifiCorp estimate so it is not double counted. The capital cost has been updated in the revised summary workbook Excel file for the generic resources assumptions available on PSE’s IRP website under materials for Webinar 1 on pse.com/irp.
Katie Ware, Renewable Northwest, notes that the PacifiCorp’s draft IRP Pumped Storage Hydropower (PSH) generic resource looks to be based on Swan Lake. PSE read through PacifiCorp’s generic resource assumptions and agrees, that their generic PSH resource appears to be the same as Swan Lake. PacifiCorp’s draft IRP cost estimate was removed so that there isn’t any double counting. Renewable Northwest also recommended additional review of the 2019 NWE Draft IRP (High) value. PSE reviewed NWE’s costs and as a result will average NWE high and low cost estimates and then use the “mid” for the PSH capital cost average.
2. Operating characteristics
PSE has reviewed the feedback received and contacted certain stakeholders (for example, Nathan Sandvig, National Grid Ventures; Bill Pascoe, Absaroka Energy & Orion Renewables, Fred Huette, Northwest Energy Coalition (NWEC)) to further discuss operating characteristics of pumped storage hydro.
- Nameplate capacity. The nameplate capacity will be reduced to 50 MW to assume a joint ownership and the ability to size to need.
- Operating range. The operating range will be updated to use 0% to 100% as supplied by Bill Pascoe and recommended by NWEC.
- Ramp rate. Newer technology allow the units to ramp at 20 MW/seconds. This is an input into the Plexos flexilibty model.
- Discharge rate. The input into the Aurora is the total energy of storage and the model will optimize the hours and energy used.
Battery Energy Storage System
PSE received feedback from Kathi Scanlan, WUTC staff, on using the Pacific Northwest National Labs (PNNL) report on energy storage. PSE reviewed the document and has included the cost estimates in the revised summary workbook Excel file for the generic resources assumptions available on PSE’s IRP website under materials for Webinar 1 on pse.com/irp. PSE has also added the 2-hr Lithium Ion battery, and the 4-hr and 6-hr flow battery as resources options for the 2021 IRP.
Katie Ware, Renewable Northwest, and Vlad Gutman-Britten, Climate Solutions, provided feedback on using the Lazard levelized cost estimates. The discussion is provided below under captital costs, vintage year.
Vlad Gutman-Britten, Climate Solutions, provided feedback on on the PacifiCorp high battery storage capital cost. The high capital cost refers to a smaller 1 MW battery, so the cost was removed from the average and PSE will only use the cost estimate for the larger 15 MW battery.
PSE received feedback from Bill Pasco, Absoroka Energy & Orion Renewables, on battery degredation. The battery systems are assumed to have 0% degradation with an increased fixed O&M costs. This higher fixed costs are for maintenance over time to prevent the degredation.
PSE received feedback from Fred Huette and Joni Bosh, NWEC; Kathi Scanlan, WUTC staff; Vlad Gutmen-Britten, Climate Solutions; Katie Ware and Max Greene, Renewable Northwest, on modeling hybrid or co-located resources such as solar + battery and wind + battery. In the 2019 IRP process, a 100 MW solar PV plus a 25 MW 2hr Lithium Ion battery was modeled with a 10% benefit to costs for co-locating the resource. The benefit represents that the battery can use the same substation and interconnection as the solar project. Also the battery received the benefit of the solar Investiment Tax Credit (ITC) since it was connected to the solar project. This same resource will be modeled in the 2021 IRP and a wind + battery resource will be added as well. PSE will model a 100 MW wind project located in Washington with a 25 MW 2hr Lithium Ion battery. The costs will be modeled with a 10% reduction for the benefit of co-location. The revised summary excel file has been updated to include these resources.
Many stakeholders gave feedback on the data sources used for the capital cost average.
1. Dated information
PSE received feedback from Fred Huette and Joni Bosh, NWEC, and Vlad Gutman-Britten, Climate Solutions, about using dated sources. PSE has made sure that only the most current information is used for the cost averaging. The updated data is included in the revised summary Excel file. Older data from 2016/2017 is included in the file for comparison purposes, but is not used in the cost average cacluation.
2. Other utility cost estimates
Vlad Gutman-Britten, Climate Solutions, suggested that averaging data for capital costs should not be based on so many utility IRP projections. We feel this in an important data point since utilities usually hire a consulting firm to develop this information, as it gives an important perspective from the utility point of view. PSE will keep the other utility cost estimates in the cost average including PSE’s 2019 IRP process estimates from HDR (Generic Resource Costs of Integrated Planning, October 2018).
3. ATB low cost estimate
Fred Huette and Joni Bosh, NWEC, suggested to use both the low and mid National Renewable Energy Laboratory (NREL) ATB cost estimate. Per the NREL website, the mid case is the most likely scenario, so PSE will only include the mid cost estimate in the cost average and not add the low.
Three future scenarios (Constant, Mid, and Low technology cost) through 2050 to reflect a range of perspectives based on published literature:
- Constant Technology Cost Scenario: Base Year (or near-term estimates of projects under construction) equivalent through 2050 maintains current relative technology cost differences and assumes no further advancement in R&D.
- Mid Technology Cost Scenario: Technology advances through continued industry growth, public and private R&D investments, and market conditions relative to current levels that may be characterized as "likely" or "not surprising."
- Low Technology Cost Scenario: Technology advances that may occur with breakthroughs, increased public and private R&D investments, and/or other market conditions that lead to cost and performance levels that may be characterized as the "limit of surprise" but not necessarily the absolute low bound.”
4. Cost curves
At the suggestion of Fred Huette and Joni Bosh, NWEC, and Vlad Gutman-Britten, Climate Soluations, PSE has compared the Annual Energy Outlook (AEO) cost curves and the NREL ATB (NREL, 2019 Annual Technology Baseline) cost curves. PSE will use the NREL cost curves for future capital costs. This update has been reflected in the revised summary Excel file.
5. Owner’s costs
Vlad Gutman-Britten, Climate Solutions, requested additional information of the costs that go into owner’s costs. Owner’s costs are included in overnight costs and are different than Allowance for Funds Used During Construction (AFUDC). The capital costs shared with the IRP stakeholders on May 28 represent "Overnight Capital Costs" which estimate the cost of building the project "overnight" and therefore do not include extra costs incurred during construction. Capital costs are inclusive of the Engineering, Procurement and Construction (EPC) plus the Owner's costs (financing costs), but generally do not include interconnection costs.
6. Allowance for Funds Used During Construction (AFUDC)
PSE will assume a generic assumption of 10% to the overnight cost to reflect AFUDC from the 2019 IRP process. The revised summary Excel file has been updated to include the total all-in costs that include AFUDC.
7. Interconnection costs
The the assumption from the 2019 IRP process will be used for the 2021 IRP. This includes to cost of a substation, 5 miles of transnsmission lines, and 5 miles of gas pipline for the natural gas (NG) . A full discussion of the assumption is included in the HDR report (Generic Resource Costs of Integrated Planning, October 2018) on the PSE’s IRP website. The revised summary Excel file has been updated to include the total all-in costs that include interconnection costs.
8. Vintage year for average
Many of the data sources used provide costs for different vintage years. PSE used the year with the most data and averaged across data sources that provided costs for that particulat vintage year.This meant that certain data sources were left out because costs were provided for a different year. For example, the battery storage resource was averaged for the year 2020 since that had the most data points. But this meant that the costs for the Lazard report (2019 Levelized Cost of Energy) were left out since those were for a 2018 vintage plant. The different data sources did not provide any information on inflation to change the costs into a different vintage and PSE did not make any assumptions to change the vintage year. For the 2021 IRP, PSE will remain with this assumption, but is open to suggestions for how to handle it in future IRPs.
PSE received feedback from Kathi Sclanlan, WUTC staff, on the assumed economic life of resources stating the solar photovoltaics (PV) economic life has substatiantially increased. PSE has researched this and found that the current manufactors of solar PV will warranty the panels for up to 25 years. Given this information, PSE will update the economic life of solar from 20 to 25 years.
Bill Pascoe, Absaroka Energy & Orion Renewables, asked what is the assumed operating life for pumped stoage hydro (PSH) and battery storage. PSH is assumed to have a 30 year-life and batteries are assumed to have a 20-year life.
Hydrogen as Fuel
Many stakeholders, including Kevin Jones and Rob Briggs of Vashon Climate Action Group and Doug Howell of the Sierra Club, gave feedback on using hydrogen as a fuel source for the natural gas generators. PSE has consulted with industry experts and thermal plant engineers. This is an emerging fuel source and PSE will continue to monitor the progress of the technology and applications in the US and abroad, as well as continue our involvement in the development as a member of Renewable Hydrogen Alliance. Many companies are developing hydrogen ready gas turbines that can start with a blended hydrogen to NG fuel and in future years retrofit the combustor to run on 100% hydrogen. Though the technology for turbine exists today, the supply for 100% hydrogen does not. The current gas transportation pipelines can only handle a 3% - 10% hydrogen mix. To move to a higher concentration of hydrogen would require new pipelines or electrolyzer and storage on site. The cost to create the hydrogen fuel is currently unknown. PSE is researching the cost of a hydrogen ready gas turbine and the cost for future retrofits to handle 100% hydrogen along with the costs for the fuel supply. PSE will provide an update on our findings as we begin the portfolio modeling and if there is enough iformation to include it as a resource option in the 2021 IRP. Even if there is not enough information to include it as a resource option, the 2021 IRP will include a discussion of hydrogen as a fuel and the technology need for the fuel supply.
Summary of all Updates
PSE appreciates the feedback provided by stakeholders. In summary, the Excel summary workbook includes the following changes:
- Pumped Storage Hydro overnight capital costs revised to include more data sources and averaging across vintage year 2021 instead of 2020.
- Pumped Storage Hydro size assumption has been revised to 50 MW. PSE will also update operating characteristics for PSH to reflect newer techonology.
- Considering hybrid resources, certain changes have been made in the summary Excel file. Wind + battery resource as been added. PSE will model a 100 MW wind project located in Washington with a 25 MW 2 hr Lithium Ion battery.
- PSE has adopted the NREL data to generate cost curves.
- AFUDC and interconnection costs have been added in a new tab to calculate the all-in capital costs that will be used in the models.
- PSE will update the economic life of solar from 20 to 25 years.
- PSE will further develop costs concerning hydrogen as a fuel for application in the 2021 IRP analysis or if that is not feasible, the 2021 IRP book will include a robust discussion of the state of the industry concerning hydrogen.
- Lithium Ion 2-hr battery and flow 4-hr and 6-hr battery added. PSE was able to collect some other data sources from the PNNL energy storage report and some other utility IRPs besides the HDR report (Generic Resource Costs of Integrated Planning, October 2018).
Figure 1 below is a table comparing the costs from the 2019 IRP, the draft 2021 IRP as presented on May 28, and the updated capital costs after stakeholder feedback. The following table is also located in the revised Excel summary file under the tab “summary” and available for stakeholders can track the costs and calculations.
Figure 1: Overnight capital costs
(2021 Vintage, 2016 U.S. Dollars)
Overnight Capital Cost ($/kW)
2021 IRP draft
2021 IRP proposed
Battery (4hr, Li-Ion)
Battery (2hr, Li-Ion)
Battery (4hr, Flow)
Battery (6hr, Flow)
Solar + Battery
Wind + Battery
Figure 2 below is a table showing how the AFUDC and interconnection costs are added to the overnight for the final all-in costs that PSE will be using for portfolio modeling. The following table is also located in the revised Excel summary file under the tab “summary” and available for stakeholders can track the costs and calculations. The cost curve with costs by vintage year are also included with this table.
Figure 2: All-in capital costs
(2021 Vintage, 2016 U.S. Dollars)
Total All-In Capital cost
Battery (4hr, Li-Ion)
Battery (2hr, Li-Ion)
Battery (4hr, Flow)
Battery (6hr, Flow)
Solar + Battery
Wind + Battery
- Consultation update #1: Generic Resource Costs [PDF, 171 KB]
- Generic Resource Assumptions Workbook Summary with Feedback Incorporated [Excel, 1 MB]