3/3/2021

Webinar 12: Delivery System Planning 10-year Plan, Flexibility Analysis Results, Economic, Health and Environmental Benefit (EHEB) Assessment of Current Conditions Status Update, Portfolio Draft Results

February 10, 2021

Posted 3/3/2021 | Open in new tab

The following consultation update is the result of stakeholder suggestions gathered through an online Feedback Form, collected between February 3 and February 17, 2021 and summarized in the Feedback Report dated February 24. 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.

Stakeholder questions and suggestions spanned a wide variety of topics and not all are included in this Consultation Update. As always, line-by-line responses to each stakeholder comment are provided in the Feedback Report¹. Similarly, many stakeholder questions received from the December 15th Webinar have been answered in the Draft IRP, which is now available for review on the IRP website². PSE encourages stakeholders to review these materials in concert with this Consultation Update.

PSE has contacted the following stakeholders to clarify their comments:

• Bill Pascoe, Pascoe Energy, was contacted on February 12 to clarify his request for clarification concerning Pumped Hydro Energy Storage (PHES) and Montana Wind.  The correspondence was conducted outside of the feedback form, but the outcome is included in this Consultation Update to communicate the result of the inquiry for all stakeholders. 

Delivery System Planning 10-Year Plan

PSE received several clarifying questions from Kyle Frankiewich (WUTC) concerning the 10-year Plan developed by the Delivery System Planning group. PSE would direct stakeholders to the feedback report for specific line-by-line responses to these questions.

PSE would highlight one WUTC recommendation to incorporate a “tipping-point analysis” into the framework for determining the efficacy of non-wire alternatives. PSE’s Delivery System Planning group agrees a tipping-point analysis may be beneficial for decision making and will work to incorporate this methodology into future assessments.

Economic, Health and Environmental Benefit (EHEB) Assessment of Current Conditions Status Update

PSE received stakeholder feedback from Kyle Frankiewich (WUTC) concerning the Economic, Health and Environmental Benefits (EHEB) Assessment. PSE was able to incorporate some recommendations from WUTC staff into the Final IRP EHEB Assessment, but some recommendations will be incorporated at later date due to time constraints.

Recommendations incorporated into the Assessment are:

• Incorporation of tribes into the highly impacted communities named population
• Alignment of naming convention to switch “assessment metrics” to “customer benefit indicators” and “customer benefit indicators” to “customer benefit indicator areas”

Recommendations which will be incorporated at a later data include:

• Identification of vulnerable populations based on demographic, instead of geographic criteria
• Identification of vulnerable populations based on a binary criteria, instead of based on averages of multiple criteria
• Incorporation of customer input into customer benefit indicators and other components of the Assessment

Flexibility Analysis

PSE received feedback from Invenergy and Renewable Northwest concerning calculation of resource Flexibility Benefit. Further detail into the flexibility modeling process and results will be made available with the Final IRP filing. PSE also looks forward to continuing to develop our modeling procedures and will investigate inclusion of hybrid resources, fast-frequency response and voltage support in future IRP cycles.

Other Updates

1. Bill Pascoe, Pascoe Energy, asked for clarification concerning Pumped-Hydro Energy Storage (PHES) and Montana Wind.  A call was arranged between Bill Pasoce and Elizabeth Hossner, Manager, Resource Planning and Analysis.  This was also followed with a discussion with the developers of the Gordon Butte Pumped storage hydro project in Montana.  Both discussions suggested some updates to the operating characteristics of pumped storage hydro.  Since it was too late to incorporate this information in the 2021 IRP, PSE will update the pumped storage hydro operating characteristics for future IRPs.
2. During the webinar, Bill Pascoe asked about the updated transmission cost assumptions.  Since PSE did not have the table immediately available during the webinar, it is provided below. The following figure has been updated from the draft IRP with updated costs, and will also be available in the Final IRP (in Chapter 5):

Transmission Costs by Generic Resource Type (in 2020 $)

NOTE: a. Fixed transmission cost is not applied, because the resource is assumed to be built within PSE service territory.

¹ February 10, 2021 Webinar Feedback Report: https://oohpseirp.blob.core.windows.net/media/Default/2021/meetings/Feb_10_Webinar/Webinar%2012%20-%20Feedback%20Report.pdf 
² PSE 2021 Draft IRP: https://pse-irp.participate.online/2021-irp/reports 

Documents

• Webinar 12: Consultation Update [PDF, 166 KB]

1/19/2021

Webinar 11: Flexibility Analysis and Portfolio Draft Results

Posted 01/19/2021 | Open in new window

The following consultation update is the result of stakeholder suggestions gathered through an online Feedback Form, collected between December 8 and December 28, 2020 and summarized in the January 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.

Stakeholder questions and suggestions spanned a wide variety of topics and not all are included in this Consultation Update. As always, line-by-line responses to each stakeholder comment are provided in the Feedback Report[1]. Similarly, many stakeholder questions received from the December 15^th Webinar have been answered in the Draft IRP, which is now available for review on the IRP website[2]. PSE encourages stakeholders to review these materials in concert with this Consultation Update.

As referenced in the Feedback Report, PSE has contacted the following stakeholders to clarify their comments:

• Katie Ware, Renewable Northwest, was contacted on January 15, 2021 to clarify her request for an additional sensitivity which only allows non-emitting resoureces. This sensitivity is similar to sensitivity P: Must Take Battery or Pumped Hydro, where no new peaker plants are allowed until 2030 and the portfolio model optimization allows the solution to meet peak needs without peaker plants. The lowest cost option optimized to 2-hour lithium Ion batteries. PSE also ran a sensitivity P2 with pumped storage hydro. This request is to add a P3 with 4-hour Lithium Ion batteries.
• Kyle Frankiewich, WUTC, was contacted on January 15, 2021 to clarify his inquiry on the difference in portfolio cost (either net present value or levelized cost) for the Mid portfolio with and without DERs. PSE will add a No DSR portfolio to the portfolio sensitiviites to test.

Alternative Compliance Cost

PSE received feeback from James Adcock and Kyle Frankiewish (WUTC) concerning the use of of the California carbon price as a cost forecast for alternative compliance costs. PSE solicited stakeholder feedback on alternative compliance costs during the September 1 webinar and received a single response from the Northwest Renewable Energy Coalition (NWEC):

“In response to the question posed on prioritizing options for the 20% alternative compliance actions that might be addressed in the 2021 IRP, NWEC would urge PSE to model an aggressive amount of conservation and demand response. Beyond the required conservation and demand response required in sections .040 and .050 of CETA, additional innovative conservation, efficiency, storage and demand response should be considered for Energy Transformation Projects. Exploring those has the double impact of further reducing/managing load and achieving additional GHG reductions.”

PSE acted upon NWEC’s suggestions by creating Senstivities V (Balanced Portfolio) and W (Balanced Portfolio with Alterative Fuel for Peaking Capacity) which increase quantities of demand response, storage and distributed resources. PSE still required an alternative compliance price to model and decided the California carbon price is a suitable, real-world example of carbon pricing and therefore a sound starting point. PSE is open to feedback on possible alternatice compliance cost sensitivities to include in future models.

Flexibility Analyis

PSE received feedback from a Katie Ware (Renewable Northwest) and Kyle Frankiewich (WUTC) regarding PSE’s intial approach for the flexibility analysis.

Renewable Northwest has suggested that PSE incorporate four dimensions of flexibility into the flexibility assessment: absolute power output capacity, speed of power output change, duration of energy levels and carbon intensity. This suggestion will be taken under advisement

Renewable Northwest further suggests that the flexibility value of the reciprocating peaker plant ($417.25/kW-yr) may be articifically inflated due to the facilities small nameplate capacity. PSE has adjusted the nameplate capacity of the reciprocating peaker to 216 MW which has changed the flexibility benefit to $35/kW-yr.

Both the WUTC and Renewable Northwest suggest that PSE examine the flexibility benefit and assessment approaches of the CAISO Energy Imbalance Market (EIM).

PSE thanks stakeholders for their thoughtful review and suggestions.

ELCC Values

PSE received feedback from Katie Ware (Renewable Northwest) and Kyle Frankiewich (WUTC) that the effective load carrying capability (ELCC) of storage resources may be low. PSE would direct stakeholders to Chapter 7 of the 2021 Draft IRP for a full discusccion on PSE’s ELCC methodology and results. In brief, storage resources are energy limited resources which are assessed with a different set of resource adequacy meterics (expected unserved energy, instead of loss of load probability). Therefore, long-term (i.e. multi-day) peak events which are common in winter months may not be well served by short-duration storage resources. Kyle Frankiewich suggested that saturation curves for storage resources may reveal increased ELCC with added capacity. PSE will attempt incorporate this suggestion into future IRP cycles.

Portfolio Draft Results

Katie Ware (Renewable Northwest), James Adock, Elyette Weinstein, Nathan Sandvig (Rye Development LLC) and Kyle Frankiewich (WUTC Staff) provided feedback of concerns regarding PSE’s portfolio draft results.

Katie Ware and Nate Sandvig requested PSE model a sensitivity which prevent additions of new emitting resources. The Final IRP will include Sensitivities N: 100% renewable by 2030, O: Gas Generation Out by 2045 and P: Must Take Battery or Pumped Hydro Storage which limit new peaking capacity builds and relaying on energy storage resources such as batteries and pumped storage hydro. PSE will also add a portfolio sensitivity that evaluates Montana Wind plus pumped storage hydro and a hybrid resource in 2026.

PSE feels these sensitivities adequately reflect possible zero-emission portfolios and can therefore assess the viability of including peaking capacity resources into the preferred portfolio.

Further work as part of Clean Energy Action Plan and Clean Energy Implementation Plan will further assess non-energy benefits and burdens of including peaking capacity resources into PSE’s clean energy future.

Other Updates

The following items have been updated after the Webinar 11:

1. Willard Westre (Union of Concerned Scientists) asked for clarification on the emissions chart on Slide 17. In the Feedback Report, PSE released a revised version of the chart which addresses Willard’s questions. PSE would note that the reduction in greenhouse gas emissions from 2019 to 2029 is 75%.

2. Kyle Frankiewich (WUTC) requested a chart comparing the greenhouse gas emissions for each sensitivity portfolio. PSE has produced this chart as part of Chapter 8 in the Draft IRP. The figure is also provided below on the next page.

3. Kyle Frankiewich (WUTC) requested a table comparing the 4-yr (2022-2025), 9-yr (2022-2030), 20-yr (2022-2041) and 24-yr (2022-2045) portfolio levels costs for the scenarios and sensitivities presented in during the webinar. The table is provided on the next page.

Summary of all updates

PSE appreciates the feedback provided by stakeholders. In summary, the following changes will be implemented:

• PSE updated the emissions chart and provided table comparing the 4-yr (2022-2025), 9-yr (2022-2030), 20-yr (2022-2041) and 24-yr (2022-2045) portfolio levels costs for the scenarios and sensitivities presented in during the webinar in this Consultation Update based on stakeholder inquiries.
• PSE has updated the nameplate capacity of reciprocating peakers from 18 MW to 216 MW to obtain a more reasonable flexibility benefit.
• PSE is open to incorporating a range of possible carbon prices to better understand costs of alternative compliance.
• PSE will add the following sensitivities to the list - P3: Must Take Battery or Pumped Hydro with 4-hour lithium Ion battery, X: No DSR, and Y: include MT Wind + Pumped Storage Hydro in 2026.

[1] December 15, 2020 Webinar Feedback Report: https://oohpseirp.blob.core.windows.net/media/Default/2021/meetings/December_15_Webinar/Webinar%2011%20-%20Feedback%20Report.pdf

[2] PSE 2021 Draft IRP: https://pse-irp.participate.online/2021-irp/reports

12/14/2020

Webinar 10: Clean Energy Action Plan (CEAP) and Clean Energy Implementation Plan, Economic, Health and Environmental Benefit Assessment of Current Conditions and Delivery System and Grid Modernization Needs

Posted 12/14/2020 | Open in new window

The following consultation update is the result of stakeholder suggestions gathered through an online Feedback Form, collected between November 9 and November 30, 2020 and summarized in the December 7 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.

Economic, Health and Environmental Benefits Assessment

PSE received feedback from Don Marsh (CENSE), Brian Grunkemeyer (FlexCharging), David Perk (350 Seattle) and Kyle Frankiewich (WUTC Staff) regarding PSE’s intial approach for the Economic, Health and Environmental Benefits Assessment.

PSE has reached out to Brian Grunkemeyer to discuss some of the details of the avoided tailpipe emissions dataset and some intitial information was exchanged on December 8. A meeting will be arranged for later in December or early January to learn more. 

PSE thanks stakeholders for their thoughtful review and suggestions and will endeavor to adopt the following suggestions in development of the Economic, Health and Evironmental Benefits Assessment:

1. Coordination with local advocacy groups
2. Inclusion of air quality metrics in the assessment
3. Parallel assessment of named communities and metric evaluation
4. Continued evaluation and refinement of assessment metrics and metholologies to best capture distributions of named communities

Scope of PSE’s Draft IRP

James Adock and Kyle Frankiewich (WUTC Staff) provided feedback of concerns regarding the scope of PSE’s 2021 Draft IRP, due January 4, 2021. While not all the analysis will be completed for the draft IRP, PSE is confident that stakeholders will have meaningful content for review and feedback. PSE fully intends to incorporate stakeholder feedback on the draft IRP received during the WUTC comment period that is expected to begin in early January. In addition, PSE will continue with its public participation process and stakeholders will have opportunity to provide feedback on analysis that is completed after the draft IRP is filed. PSE is committed to documenting stakeholder feedback and demonstrating its application in the IRP analyses.

Summary of all updates

PSE appreciates the feedback provided by stakeholders. In summary, the following changes will be implemented:

• PSE will work to adopt the four stakeholder suggestions above in the Economic, Health and Evironmental Benefits Assessment as practical.
• PSE will work to develop a draft IRP with key analyses, scenarios and sensitivies completed for stakeholder review and feedback. The draft IRP will be available at pse.com/irp on January 4, 2021.

10/20/2020

Webinar 9: CETA Assumptions, Demand Forecast, Resource Adequacy, Resource Need

Posted 10/20/2020 | Open in new window

The following consultation update is the result of stakeholder suggestions gathered through an online Feedback Form, collected between October 13 and October 27, 2020 and summarized in the November 3 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 thanks Kare Ware and Sashwat Roy (Renewable Northwest) for follow-up discussions concerning the loss of load probability question on November 6, 2020.

Temperature trends and temperature sensitivity

PSE received feedback from James Adcock, Katie Ware (Renewable Northwest), Kyle Frankiewich (WUTC Staff) and Don Marsh (CENSE) regarding the temperature years used to model PSE’s load forecast and in the resource adequacy model. Stakeholders suggest that more recent temperature data (i.e. most recent 20 years) should be used to inform PSE models to limit the impact of colder weather observed in older records and accentuate warming trends present in more recent records.

PSE has committed to completing a temperature sensitivity for the 2021 IRP which will address the concerns raised by stakeholders. PSE has proposed three options for modeling temperature data for the temperature sensitivity:

1. Trended normal based on historical observed trends (trended normal analysis completed by Itron Inc.)
2. Temperature normal based on most recent 15 years of temperature data
3. Northwest Power and Conservation Council’s climate model temperature assumption

More information on these options is available for review in the October 20 Webinar presentation. A stakeholder survey was conducted between October 19 and October 27 to collect feedback on which temperature option was of greatest interest. The results of the survey indicate the stakeholders suggest using the Northwest Power and Conservation Council (“NPCC” or “the Council”) climate model temperature assumption (option 3). The full results of the survey are presented below.

Don Marsh and a group of stakeholders also prepared and presented an additional temperature sensitivity methodology as part of the feedback process. During this IRP process, many stakeholders provided recommendations in IRP meetings, feedback forms and e-mails to IRP staff requesting that PSE use the most recent 15 or 20-years of temperature data. PSE listened to stakeholders and included the most recent 15 years of temperature data as one of the options for stakeholder consideration. In addition to this stakeholder request, PSE has hired a consulting firm, Itron, to perform a separate temperature analysis and PSE also researched the work done by the Council on climate change modeling. Both of these analyses were included as additional options for temperature sensitivity analysis during the October 20 Webinar and in the sensitivity survey. Over 140 stakeholders responded to the sensitivity survey and 93 stakeholders selected the Council’s climate change model temperature assumptions. PSE will follow the stakeholders’ recommendation to use the Council’s climate change model tempertuare assumptions and will consider the materials presented by Don Marsh et al for future IRP cycles.

The Northwest Power Conservation Council (the “Council”) is using global climate models that are downscaled to forecast temperatures for many locations within the Pacific Northwest. PSE has chosen to look at one of these models. The Council weighs temperatures by population from metropolitan regions throughout the Northwest.  However, PSE received data from the Council that is representative of SeaTac airport.  This data is, therefore, consistent with how PSE plans for its service area and this data is not mixed with temperatures from Idaho, Oregon or Eastern Washington.  The climate model data provided by the Council is hourly data from 2020 through 2049.  This data resembles a weather pattern where the temperatures fluctuate over time, but generally trend upward.  For the load forecast portion of the temperature sensitivity, PSE proposes to smooth out the fluctuations in the temperatures and increase the heating degree days (HDDs) and cooling degree days (CDDs) over time at 0.9 degrees/decade, which is the rate of temperature increase found in the Council’s climate model.

Montana transmission capacity

PSE received feedback from Willard Westre (Union of Concerned Scientists), Kyle Frankiewich (WUTC Staff) and Brian Fadie (Northwest Energy Coalition) concerning the transmission capacity between PSE service territory and the Colstrip region of Montana. In the June 30 Webinar, and again in the October 20 Webinar, PSE presented an upper transmission capacity limit of 565 MW to Montana. At the time these values represented the most-likely transmission capacity available to PSE in the region. Since the presentation of these materials, negotiations for sale of PSE’s portion of Colstrip Unit 4 have ceased. Therefore, PSE will model 750 MW of available transmission capacity to Montana for the 2021 IRP process as the base assumption.

PSE has also proposed modeling of several transmission constrained sensitivities for the 2021 IRP process. These sensitivities are structured around transmission tiers, which represent uncertainty of availability of transmission capacity. The change in Montana transmission capacity will influence BPA transmission redirect assumptions for the Eastern Washington region. These changes are summarized in the table below.

(a) Not including the PSE IP Line (cross Cascades) or Kittitas area transmission which is fully subscribed

Sensitivity survey and selection

PSE received questions from Virginia Lohr (Vashon Climate Action Group), Kyle Frankiewich (WUTC Staff) and Nate Sandvig (Rye Development) concerning how the sensitivity prioritization survey would be used. PSE considers the sensitivity survey a tool to help collect stakeholder sentiment on each of the many sensitivities purposed over the course of the 2021 IRP process. PSE intends to use the results as a guideline for prioritizing which sensitivities to run as part of the IRP modeling process. Other factors such as difficulty, length of time and value to the entire IRP process will also be considered as sensitivities are processed.

The full results of the survey are provided below.

ELCC values

PSE received feedback from Willard Westre (Union of Concerned Scientists), Katie Ware (Renewable Northwest), Kyle Frankiewich (WUTC Staff) and Nate Sandvig (Rye Development) concerning the ELCC values presented in the October 20 Webinar. As PSE indicated during the webinar, the ELCC values presented are draft and subject to change over the course of the IRP modeling process. Furthermore, more refined values, including saturation curves, will be provided at a later date.

Specific concerns on the relative value of battery energy storage systems to pumped hydroelectric storage will be addressed with publication of ELCC values for both resources at a nameplate of 100 MW at a later date.

Summer loss of load events

PSE received feedback from Katie Ware (Renewable Northwest), Kyle Frankiewich (WUTC Staff) and Don Marsh (CENSE) concerning summer loss of load events. PSE would like to clarify that the demand forecast for the 2021 IRP process has not changed since its presentation during the September 1 Webinar. However, an inconsistency with the demand forecast dataset used for Resource Adequacy modeling was identified and aligned. PSE regrets that our comments in the meeting, which only related to the Resource Adequacy dataset, gave the appearance that the demand forecast was changed.

The summer-time loss of load events discussed during the meeting represent a very small fraction of the total loss of load events encountered over the course of a full year as shown in the tables below for the two test case years 2027 and 2031. A loss of load event can be caused by many factors which include temperature, demand, hydro conditions, plant forced outages, and variation in wind and solar generation. All of the factors are modeled as stochastic inputs simulated for 7,040 iterations. As mentioned previously, the data shared at the October 20 webinar are draft. PSE has been reviewing the data used for the resource adequacy model and found an inconsistency with the correlations for wind and solar data. PSE has fixed the correlations and is working on updating the peak capacity need and effective load carrying capability (ELCC) values. The table below has been updated since the November 3 feedback report to include the updates to the wind and solar correlations.

Notes: Tables represent the results of 7,040 simulations where each simulation is composed of 8760 operating hours. Tables do not describe the magnitude of any loss of load event, just that the event occurred.

Katie Ware (Renewable Northwest) had also requested a 12x24 of the loss of load probability as part of this feedback cycle. Given the methodology of the Resource Adequacy Model, PSE is not able to produce hour by hour probabilities, so instead these plots represent a relative heat map of the number hours of lost load binned by month and hour of day.

Sensitivity prioritization survey results

Thank you for your active engagement in the IRP process, PSE collected results from over 140 individual respondents with this survey.

Sensitivity Selection Results

Sensitivity #25 Alternative fuel #1, fuel selection

Sensitivity #31 Temperature sensitivity, temperature methodology

Summary of all updates

PSE appreciates the feedback provided by stakeholders. In summary, the following changes will be implemented:

• The temperature sensitivity will be modeled using the Council’s methodology.
• The Montana transmission capacity will be set to 750 MW.
• Sensitivity prioritization has been informed by the stakeholder survey results, as shown above.
• Hydrogen will be included as an alternate fuel choice in the Alternative Fuel #1 sensitivity (sensitivity #25, must-run).

Documents

• Webinar 9: Consultation Update [PDF, 601 KB]

10/14/2020

Webinar 8: Natural Gas IRP

Posted 11/4/2020 | Open in new window

The following consultation update is the result of stakeholder suggestions gathered through an online Feedback Form, collected between October 7 and October 21, 2020 and summarized in the October 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.

Temperature Sensitivities, planning standard and recent peak load data

PSE received a request to share the most recent 10 years of peak day load experienced by the gas system. The graph below includes the highest load days over the last 10 years along with the gas system load and associated HDD.

Natural gas for electric versus gas sales

PSE received feedback from Kyle Frankiewich (WUTC staff) as to how much of the electric line of business (LOB) is factored into the company’s gas LOB, and whether the electric LOB is a gas transportation customer.

All of PSE gas-fired generation is connected directly to an upstream pipeline (either Northwest or Westcoast) or to Cascade Natural Gas Co. distribution system. Because the gas-fired generation and gas distribution system can have simultaneous peak design conditions, there is no opportunity for shared design day resources. The only opportunity for synergy between the two lines of business is that generation can utilize unused gas LOB pipeline or storage capacity in the low demand summer months (with compensation at fair-market value). In addition, the gas system can rely on the power generaton fleet to curtail gas generation use (and rely on power market supply instead) in an emergency pipeline failure event (e.g.: Enbridge/Westcoast event) in order to maintain pressure in the pipeline.

Gas customer defections

PSE received feedback from Court Olson and Kyle Frankiewich (WUTC) asking if PSE could share the rate of voluntary cancellations of service for natural gas customers and if there was evidence of “defection” away from natural gas service.

PSE has not seen evidence of customer defection. Our most recent 10K shows natural gas customer counts growing over the past there years. Relevant table from the 10K for the fiscal year ending December 31, 2019 (page 19) is provided below:

Natural gas conservation potential assessment (CPA)

PSE received feedback from Kyle Frankiewich (WUTC staff) concerning the the release of the draft CPA report and underlying CPA data for the natural gas IRP.

The draft CPA report will be included with the draft IRP filing on January 4, 2021. The CPA data used in the natural gas IRP is posted along with the Consultation Update in native file format as requested (MS Excel). The file is available on the IRP website.

Natural gas sensitivities

PSE received feedback from several stakeholders on their preferences for the natural gas sensitivities. These along with the response to the sensitivity survey from Webinar 9 will be used to develop the list of sensitivities.

Summary of all updates

PSE appreciates the feedback provided by stakeholders. In summary, the following changes will be implemented:

• PSE will post CPA data files on pse.com/irp and provide the draft CPA report as part of the 2021 IRP draft available on January 4, 2021.
• Based on the stakeholder feedback, PSE will analyze the following sensitivities for the natural gas IRP:

21 - Use AR5 to model upstream emissions

14 - 6-yr ramp rate

17 - Social discount rate for DSR

42 - Equity-focused portfolio

• PSE has also tentatively included the sensitivity number 16 titled Non-Energy Impacts in the list of ‘must-run’ sensitivities. The list of ‘must-run’ sensitivities for the Gas Portfolio is as follows:

1 – Mid Economic Conditions

2 – Low Economic Conditions

3 – High Economic Conditions

12 – Fuel Switching form gas to electric

16 – Non-Energy Impacts

31 – Temperature sensitivity on load

Documents

• Webinar 8: Gas IRP Consultation Update (on the main page) [PDF, 194 KB]

9/22/2020

Webinar 7: Load Forecast, Resource Adequacy, Resource Need and CETA

Posted 9/22/2020 |  Open in new window

The following consultation update is the result of stakeholder suggestions gathered through an online Feedback Form, collected between August 25 through September 8, 2020 and summarized in the August 15, 2020 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.

Alternative compliance actions

PSE received feedback from Joni Bosh of Northwest Energy Coalition (NWEC) concerning increased use of conservation and demand response programs to meet the 20% alternative compliance metric as stated in CETA. PSE will add a sensitivity on increased conservation and demand response programs for the 2021 IRP.

PSE summer load forecast

PSE received feedback from Don Marsh of CENSE and Robert Briggs of Vashon Climate Action Group concerning PSE’s summer load forecast. PSE is working on pulling the data together and a graphic of the 2021 IRP peak for both the summer and winter seasons.  This graphic will be will be included in the IRP draft available on pse.irp/com to be submitted January 4, 2021 and/or the final IRP available on pse.com/irp to be filed with the WUTC on April 1, 2021. PSE realizes that its status as a winter peaking utility is relatively unique in the WECC region, and therefore performs all resource adequacy calculations for the entire year to take into consideration impacts of other regions on market conditions.

Temperature years

PSE received feedback from Don Marsh of CENSE, Joni Bosh of NWEC and Robert Briggs of Vashon Climate Action Group concerning the number of years of temperature data used to generate load forecasts and perform resource adequacy calculations. PSE would like to clarify that the temperature data used in these two aspects of IRP modeling are distinct, serve different purposes and, therefore, should not be indiscriminately grouped together.

Temperature data for the load forecasting purposes is used to understand and project climate trends over the modeling horizon. To address the impact of temperature data on the load forecast PSE will analyze a sensitivity on temperature and the demand forecast, as compared to the 30-year average normal used in the presented load forecast.

Temperature data for the resource adequacy model (RAM) is used to generate simulations over a range of conditions which could plausibly occur in the PSE service territory. The RAM requires many, many simulations to ensure statistically significant results in modeling highly stochastic processes. Therefore, the number of temperature years of data must be large enough to cover the range of temperature conditions likely to occur in the PSE service territory and generate enough simulations for accurate results. PSE currently uses 88 temperature years of data for the RAM model. PSE is researching peak temperatures and extreme weather conditions as part of the temperature sensitivity.

Washington Utilities and Transportation Commission feedback

Commission Staff provided feedback for the Webinar #7: Scenarios and Sensitivities on September 10.  Due to the missed deadline, PSE is addressing the questions submitted on September 10 in this Consultation Update. The feedback, questions and comments from the WUTC concerning the Webinar #7 are presented below, followed by the PSE responses: 

WUTC Staff: Slide 12: I’m curious about whether PSE is assessing CETA alternative compliance payments as a route to CETA compliance on a least-cost basis. Are the alternative compliance payments included as something like resource options in the portfolio expansion model? How is PSE modeling the various options – RECs, energy transformation projects, alternative compliance payments and additional generation?

PSE response:  PSE plans to model a price forecast as a stand in for CETA alternative compliance unbundled RECs or Energy transformation projects.  Some options can be either a CO2 price forecast such as the California price or a REC price.  PSE is seeking stakeholder feedback on the price forecast as the stand-in cost.

WUTC Staff: Slide 17: What goes into PSE’s decision to change IAP2 participation levels from topic to topic? If stakeholders see potential problems with the information presented by PSE during an “INFORM” topic, is the company still open to receiving feedback?

PSE response:  PSE determined the International Association for Public Participation (IAP2) participation level to the level on the spectrum PSE can commit to in the 2021 IRP process. The measure of success for IAP2 is not the level one chooses on the spectrum, but the level that can be achieved by PSE and the level PSE can maintain our promise to stakeholders.  PSE greatly appreciates the feedback and participation of our stakeholders.  For example, “INFORM” topics, PSE provides opportunities for questions and comments in the chat feature of GoToMeeting, during the meeting, as well as answering questions in the feedback report and addressing any follow-up in the consultation update. 

WUTC Staff: Slide 27: It seems difficult to guess at whether some COVID-prompted energy usage shifts may persist, but it also seems unlikely that the post-COVID normal will be identical to the pre-COVID normal. Does PSE intend to adjust its long term energy usage pattern estimates based on a pre- and post-COVID analysis?

PSE response: PSE agrees that the COVID-19 pandemic event is significant and there is potential for a “new normal” regarding energy usage patterns.  At this time, PSE has not yet observed what could be considered long-term usage pattern differences due to the pandemic. Once PSE determines that there has been a permanent shift in usage patterns, PSE will incorporate those into the forecast.

WUTC Staff: Slide 29: The table shows that a shorter timeframe for defining ‘normal’ has an outsized impact on cooling estimates. Warmer and dryer summers may not yet have an impact on PSE’s resource adequacy in the summer months, but could have a dramatic impact on the price of electricity. PSE discussed the RA component of its market reliance in this presentation, but did not cover the cost risk. How is that represented in the IRP? Does the IRP consider the prospect of escalating costs for market power as summers get hotter, and as thermal generators retire? 

PSE responses: 

To date concerning the modeling, no loss of load events occurs in the summer months in the Resource Adequacy Model (RAM). RAM only evaluates the capacity need with the balance between the supply and demand; cost is not included.

The cost risk of market reliance be will addressed in PSE’s stochastic modeling.  PSE is still working on the cost risk around market reliance and the stochastic model will be presented at the December 9, 2020 IRP meeting.

WUTC Staff: Slide 60: Is GENESYS and the WPCM both run 7040 times, once for each RAM run?

PSE response: Yes, GENSYS and WPCM both consider the 88 temperature years and 80 hydro years, so there are 7040 simulations (88 x 80 = 7,040) in total.

WUTC Staff: Slide 61: Please refresh my memory about the COB import limit. What is the nature of the 3400 MW limit? Are there any plans to increase (or decrease) this limit? Also, how are connections to other regions – BC to NW, MT to NW, SW (AZ/NV/CA) to NW – modeled?

PSE response: Regional interties are part of the regional GENESYS model and PSE relies on the Northwest Power and Conservation Council’s assumption of 3400 MW limit.  PSE then interconnects to the regional model with the 1500 MW limit to the Mid-C market.

WUTC Staff: Slide 63: What does temperature do in the RA model? Does temperature impact load or thermal performance?

PSE response: RAM considers 88 temperature years in the load forecast. Thermal plant outages are modeled in AURORA using the Frequency Duration.  This takes into account the forced outage rate (%) and mean time to repair (hours).  The outages are model for each generating unit individually with a probability of failure (FOR) and run for 260 different simulations of outages.  The probability of an outage is not based on temperature.

WUTC Staff: Slide 63 (cont): What data does GENESYS need? Is that data provided in the software? Can it be modified? Can it be made publicly available?

PSE response: GENESYS uses the data from the Northwest Power and Conservation Council (NPCC), which is publicly available. The PNW regional generation and load forecast data relevant for the years 2022-2045 is publicly available. For the study years 2027 and 2031, PSE considers the load growth and retirements of units, which is obtained from NPCC staff.

WUTC Staff: Slide 63 (cont): What new resources are included as inputs into the RAM?

PSE response: In 2021 IRP, PSE will include the new resources and contracts obtained through the 2018 RFP.

WUTC Staff: Please provide some examples what is meant by “regional curtailment” and explain how these affect a model run.

PSE response:  With the expected load growth and generation retirements, the capacity of supply will be, at times, less than the demand. That is the physical meaning of load curtailment. For example, during a peak hour, the regional resource capacity is 3000 MW but the regional load is 3001 MW, then a regional load curtailment occurs. During a PNW load curtailment event, there is not enough physical power supply available in the region, including available imports from California, for all of the region’s utilities to meet their loads plus operating reserves. The Wholesale Purchase Curtailment Model (WPCM) will “allocate” the regional capacity deficiency to the individual utilities. These individual capacity shortages are reflected through a reduction in the forecasted level of wholesale market purchases. On an hourly basis, the WPCM translates a regional load-curtailment event into a reduction in PSE’s wholesale market purchases.

WUTC Staff: Slide 71: What other contracts are expiring in 2026 and 2027 to cause the contraction of the “Contract” portion of the bars representing those years?

PSE response:  Please see below table.

NOTES

     The capacity of the TransAlta Centralia PPA is designed to ramp up over time to help meet PSE's resource needs. According to the contract, PSE will receive 280 MW from 12/1/2015 to 11/30/2016, 380 MW from 12/1/2016 to 12/31/2024 and 300 MW from 1/1/2025 to 12/31/2025.

     Does not include the sale of unit 4.

For the 2021 IRP, all contracts are expected to retire on the contract expiration date except for the Mid-C hydro contracts. In light of meeting the requirements of CETA, PSE assumes an extension of the Mid-C contracts and uses the current share as proxy to the extension. Terms and/or the possibility a contract extension will be determined closer to the actual expiration of the contracts.

WUTC Staff: Slide 71: Do PSE’s existing hydro contracts include some contract mechanism that ensures PSE can obtain a renewal of the contracts as represented starting in 2028? Or is the company presuming that, whatever the negotiated cost ends up being, it’s safe to assume that PSE will renew?

PSE response: 

For the 2021 IRP, all contracts are expected to retire on the contract expiration date except for the Mid-C hydro contracts. In light of meeting the requirements of CETA, PSE assumes an extension of the Mid-C contracts and uses the current share as proxy to the extension. Terms and/or the possibility a contract extension will be determined closer to the actual expiration of the contracts.

Summary of all updates

PSE appreciates the feedback provided by stakeholders. In summary, the following changes will be implemented into the portfolio model or included in the proposed portfolio sensitivities:

• An increased conservation and demand response program sensitivity will be analyzed to explore the impact of using these measures to meet the CETA alternative compliance metrics.
• Summer peak demand forecasts will be included in IRP documentation as reference material.
• A temperature sensitivity will be analyzed which examines the impact to the demand forecast.

PSE is committed to keeping our stakeholders informed of our progress toward incorporating feedback into the 2021 IRP process.

Documents

• Webinar 7: Consultation Update [PDF, 186 KB]

8/11/2020

Webinar 6: Portfolio Sensitivities | August 11, 2020

Posted 9/01/2020 | Open in new window

The following consultation update is the result of stakeholder suggestions gathered through the IRP online Feedback Form, collected between August 4 through August 18 and summarized in the August 25, 2020 Feedback Report. The report themes have been summarized along with responses to the suggestions that have been implemented. If a suggestion was not implemented, the reason is provided.

PSE thanks Kyle Frankiewich (WUTC Staff) for follow-up discussions concerning his questions on August 27, 2020.

PSE thanks Katie Ware (Renewable Northwest) for being available for a clarification call concerning her suggestion for a sensitivity; a call will be arranged well before the October 20 IRP Meeting.
Certain responses were not included in the August 25, 2020 Feedback Report. Those questions have been addressed in the Webinar 6 Feedback Form Addendum, also dated and uploaded to pse.com on September 1, 2020.

Feedback Report Addendum

The feedback received from Kyle Frankiewich (WUTC Staff) regarding non-energy benfits on slide 21, questions regarding slide 54, and questions on slides 57-58 on distributed solar and batteries was not answered in the Feedback Report posted on August 25, so an addendum to answer the questions has been posted.

Summary of Stakeholder Feedback on Portfolio Sensitivities

PSE appreciates the feedback provided by stakeholders. In summary, the following list of sensitivities has been added to the list:

Portfolio sensitivities added during the August 11 webinar:

1. Social cost of carbon only (as a planning adder), no CETA renewable requirement
2. Social cost of carbon only (as a dispatch cost), no CETA renewable requirement
3. Add 185 MW to MT transmission from Colstrip transmission line
4. Fuel switching from electric to gas
5. High economic conditions with SCC as a dispatch cost in the portfolio model only
6. Electric vehicle battery to grid available as a distributed energy resource
7. Time of use pricing for conservation and demand response
8. Wholistic conservation approach

Portfolio sensitivities added from the feedback report for the August 11 webinar:

1. Municipal bans on new natural gas
2. Refinements to resource cost assumptions
3. Private solar input testing
4. Equity focused portfolio
5. 2% Cost threshold
6. 2% Cost threshold - Must take DR and Battery storage first, then optimize other builds
7. 2% Cost threshold - Renewable Overgeneration Test
8. Virtual Power Plants (VPP)
9. Hydrogen as an alternative fuel for NG plants

Notes received from stakeholders regarding sensitivities already on the list:
Sensitivity #22 - Mid economic conditions with SCC as a fixed cost plus a federal CO2 tax
Virginia Lohr suggested to use a higher cost than $15, more consistent with proposed federal legislation

Sensitivity #31 - Temperature sensitivity on load
Don Marsh suggested to use most recent 10-15 years of temperature data to capture recent trends

PSE will make best efforts to complete as many portfolio sensitivities as possible for the 2021 IRP. However, given that the list has over 50 different portfolio sensitivities, PSE will ask stakeholders to prioritize the list. PSE will begin with the analysis with portfolios 1-3 (Mid, Low, and High economic conditions). The draft portfolios will be presented at the October 14 meeting for natural gas and the October 20 meeting for electricity. Once the stakeholders have an opportunity to view the draft results, PSE will will re-evaluate the list of sensitivities with the stakehodlers, then prioritize list of portfolio sensitivities.

PSE is committed to keeping our stakeholders informed of our progress toward incorportating feedback into the 2021 IRP process.

Update on the Electric Price Forecast - follow-up from June 10 Webinar as referenced in the August 11 Webinar 6 and related updates

On June 10, 2020, PSE presented the draft electric price forecast and incorporated stakeholder feedback regarding the electric price forecast.

1. 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.
        PSE response: PSE contacted the Council and included the demand forecast from the 2019 Policy Update to the 2018 Wholesale Electricity Forecast, which is the latest available demand forecast.

2. Washington Renewable Need

PSE received feedback from Vlad Gutman-Britten (Climate Solutions) and James Adcock regarding the starting point for the renewable ramp used for meeting the Washington state CETA requirements.
        PSE response: PSE updated the Washington renewable need for the updated demand forecast and started the ramp in 2022.

3. Natural Gas Price Forecast

PSE received feedback from Kathi Scanlan (WUTC Staff), requesting the use of an updated gas price forecast to reflect the socioeconomic changes of the COVID-19 pandemic.
        PSE response: PSE updated to the most recent natural gas price forecast from Wood Mackenzie.

The final electric price forecast was presented at the August 21 webinar as an update for stakeholders. James Adcock requested to see the updated Washington renewable need chart used for the electric price forecast during the webinar. PSE replied that it will be included in the constulation update for the webinar. The chart below is the renewable need for Washington state (MWh).

Documents

• Consultation Update #6: Portfolio Sensitivities [PDF, 85 KB]
• WUTC Updated Inflation Adjustment of the Social Cost of Carbon Pursuant To Docket U-190730 Order 01 [PDF, 59 KB]
• NWEC Comments on the Social Cost of Carbon in IRP [PDF, 436 KB]

7/21/2020

Webinar 5: Social Cost of Carbon | July 21, 2020

Posted 8/12/2020 | Open in new window

The following consultation update is the result of stakeholder suggestions gathered through an online Feedback Form, collected between July 14 through July 28, 2020 and summarized in the August 4, 2020 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 thanks Kyle Frankiewich (WUTC) for providing the recently updated inflation adjustment of the social cost of carbon pursuant to docket U-190730 Order 01 referenced below.

PSE also thanks Charlie Black and Orijit Ghosal of Invenergy, Joni Bosh of Northwest Energy Coalition (NWEC), Rob Briggs of Vashon Climate Action Group and Eleanor Bastion of Washington Environmental Council for meeting with PSE on August 10 to help further clarify their questions and suggestions concerning Invenergy's proposal for an environmental externalities approach to the modeling of the social cost of carbon in the 2021 IRP.

Special thanks to Joni Bosh of NWEC who alerted PSE that we missed the feedback form submitted by NWEC in the feedback report. The letter from Joni Bosh and Fred Huette of NWEC has been uploaded to the PSE IRP website and will be addressed separately via addendums to the feedback report and this consultation update. The referenced letter is available here [PDF].

Social cost of carbon inflation adjustment

An inflation adjustment of the social cost of carbon was referenced by Kathi Scanlan of the WUTC at the July 21 meeting. On July 30, the commission published docket U-190730 Order 01 “Adopting an Adjusted Cost of Greenhouse Gas Emissions Reflecting the Effect of Inflation”. The Order is attached to this consultation update. PSE will update the numbers used for the 2021 IRP modeling. The “Emission Price Calculations workbook.xls” spreadsheet has been updated on the PSE IRP website to reflect this latest guidance from the WUTC. The updated spreadsheet name is “Emission Price Calculations workbook (Inflation Update)” and is available here.

Upstream emissions

PSE received feedback from Rob Briggs and Virginia Lohr of the Vashon Climate Action Group, Joni Bosh and Fred Heutte of NEWC and Doug Howell of Sierra Club concerning PSE’s assumptions around upstream natural gas emissions. PSE appreciated the feedback. The modeling protocols described during the webinar will remain consistent with prior modeling efforts and accepted regulatory criteria, and in addition PSE proposes to model a portfolio sensitivity which utilizes the Intergovernmental Panel on Climate Change (IPCC) Fifth Assessment Report (AR5) global warming potential (GWP) for greenhouse gas emissions included in upstream emissions.

Social cost of carbon modeling approach

PSE received feedback from James Adcock, Vlad Gutman-Britten (Climate Solutions), Kevin Jones, Virginia Lohr and Rob Briggs (Vashon Climate Action Group), Charlie Black and Orijit Ghosal (Invenergy), Doug Howell (Sierra Club), Joni Bosh and Fred Heutte (NWEC) and Kyle Frankiewich (WUTC) concerning the social cost of carbon modeling approach.

PSE is modeling the social cost of carbon (SCC) as a post-economic dispatch cost. However, PSE proposes to model several portfolio sensitivities and electric price scenarios modeling the SCC as a variable dispatch cost as requested by stakeholders.

PSE models the SCC as a fixed cost adder using the following methodology (also described during the July 30th webinar):

1. A long-term capacity expansion (LTCE) model is run to determine portfolio build decisions over the modeling timeframe. Within the LTCE model, the SCC is applied as a penalty to emitting resources (i.e. fossil-fuel fired resources) during each build decision.
   1. The fixed cost adder is calculated as such:
      1. AURORA generates a forecast of dispatch for the economic life of the emitting resource. This dispatch forecast is not impacted by the SCC to simulate real-world dispatch conditions.
      2. The emissions of this dispatch forecast are summed for the economic life of the emitting resource and the SCC is applied to the total lifetime emissions.
      3. The lifetime SCC is then applied as fixed cost amortized over the life of the project.
      4. A new build decision is made based on the total lifetime cost of the resource.
2. The LTCE model results in a portfolio of new builds and retirements. Since the LTCE runs through many simulations a sampling method is used to decrease run, so the final step is to pass the portfolio to the hourly dispatch model, which is capable of modeling dispatch decisions at a much higher time resolution. The hourly dispatch model is not capable of making build decisions, but will more accurately assess total portfolio cost to rate payers. Since the SCC is not a cost passed to rate payers, the SCC is not included as part of this modelling step.

The strengths of this modeling approach include:

• accurate representation of real-world emitting resource dispatch as defined by current regulation
• accurate representation of cost to customers in the build decision
• inclusion of the SCC in all long-term planning build decisions
• distinction between build decisions and dispatch decisions (SCC is not double counted)

The weaknesses of this modeling approach include:

• emissions from thermal resources are not reduced but total portfolio emissions are reduced by less thermal resource builds

Stakeholders have requested that the SCC be included as a dispatch cost at all modeling levels. PSE understands this approach as:

1. A long-term capacity expansion (LTCE) model is run to determine portfolio build decisions over the modeling timeframe. Within the LTCE model, the SCC is applied as a penalty to emitting resources during each build decision as a dispatch cost.
   1. The variable dispatch cost is calculated as such:
      1. AURORA generates a forecast of dispatch for the economic life of the emitting resource. This dispatch forecast is impacted by the SCC which would increase the cost to dispatch the emitting resource, thereby reducing the number of dispatches of the emitting resource.
      2. The emission costs of this dispatch forecast which already contain the SCC are summed for the economic life of the emitting resource.
      3. A build decision is made based on the lifetime cost of the resource.
2. The LTCE model results in a portfolio of new builds and retirements. Since the LTCE runs through many simulations a sampling method is used to decrease run, so the final step is to pass the portfolio to the hourly dispatch model, which is capable of modeling dispatch decisions at a much higher time resolution. The hourly dispatch model is not capable of making build decisions, but will more accurately assess total portfolio cost to rate payers. The SCC can either
   1. be included in dispatch decisions to remain consistent with the LTCE model, or
   2. not be included in the hourly dispatch.

The strengths of this modeling approach include:

• inclusion of the SCC in all long-term planning build decisions

The weaknesses of this modeling approach include:

• possible double counting of SCC as both a build and a dispatch decision
• the dispatch of the resources will be optimized to minimize total costs which will result in a change in dispatch that is lower than expected in the real-world
• not reflective of real-world dispatch decisions which can result in a sub-optimal portfolio by underestimating the resource costs
• increased cost to customers

Given the strengths and weaknesses of each modeling approach PSE proposes to model several sensitivities to diagnose the impact of modeling approach on the social cost of carbon. PSE recognizes that there are several variations on these two general approaches and looks forward to discussion with stakeholders on the August 11th webinar to clarify details various sensitivities.

Summary of all updates

PSE appreciates the feedback provided by stakeholders. In summary, the following changes will be implemented into the portfolio model or included in the proposed portfolio sensitivities with stakeholders at the August 11, 2020 webinar:

• Update inflation adjustment of the social cost of carbon consistent with docket U-190730 Order 01 published by the WUTC on July 30, 2020.
• Proposed inclusion of a portfolio sensitivity to model upstream emissions consistent with AR5.
• Proposed inclusion of several portfolio sensitivities to diagnose impacts of various social cost of carbon modeling approached (e.g. cost adder, dispatch cost, externality, tax).

PSE is committed to keeping our stakeholders informed of our progress toward incorportating feedback into the 2021 IRP process.

Documents

• Consultation Update #5: Social Cost of Carbon [PDF, 106 KB]
• WUTC Updated Inflation Adjustment of the Social Cost of Carbon Pursuant To Docket U-190730 Order 01 [PDF, 59 KB]
• NWEC Comments on the Social Cost of Carbon in IRP [PDF, 436 KB]

7/14/2020

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:

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:

1. Update the business as usual (BAU) case to the 2020 ATB Moderate Cost forecast, and
2. 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:

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.

[1] https://www.nwcouncil.org/sites/default/files/2019_0312_p3.pdf

Documents

• Consultation Update #4: Demand Side Resources [PDF, 370 KB]

6/30/2020

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.

Documents

• Consultation Update #3: Transmission Constraints [PDF, 82 KB]

6/10/2020

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.

Renewable need

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.

Documents

• Consultation update #2: Electric Price Forecast [PDF, 121 KB]