PROC 00001 Published On: 02/23/2021
Question: Will all the questions be answered on the website, or just the ones not covered live? And when do you estimate those will be available on the website?
Answer: All questions received during Stakeholder Sessions will be posted to the website. We intend to answer and post as many questions as possible within one week of the Stakeholder Advisory Group meeting and continue to post answers until all questions have been addressed.
PROC 00002 Published On: 02/23/2021
Question: Will DESC send out the model requirements matrix included in the Session I Advisory Group materials? Will there be a follow up meeting to discuss the model selection?
Answer: Yes. We will upload the model requirements matrix in an editable format to the “Stakeholder Materials” section of the Stakeholder website on or around 2/24/21. Also, DESC intends to address Stakeholder feedback as well as our own findings regarding the model capabilities during Stakeholder Advisory Group Session II.
PROC 00003 Published On: 02/23/2021
Question: Will the presentation slides be sent out to Stakeholders after the meeting?
Answer: Yes, all material presented at Stakeholder Advisory Group Sessions will be posted to the “Meeting Presentations and Materials” section of the Stakeholder website.
PROC 00004 Published On: 05/11/2021
Question: Sierra Club requests that the timeline for coal plant retirement studies and energy efficiency programs be included in the next agenda.
Answer: The EE programs will continue to be discussed as inputs to the IRP, but the actual design, modification, and planning of DSM programs will continue to be addressed within DESC’s Energy Efficiency Advisory Group. The coal plant retirement analysis will be included as a topic for Session III of DESC IRP Stakeholder Advisory Group meeting.
PROC 00005 Published On: 12/21/2021
Question: Are there any other current plans, efforts, or projects within DESC that will alter the magnitude of resources available to the system, but are not included in the modeling that has been filed with the Commission or will be shared with Stakeholders?
Answer: No.
PROC 00006 Published On: 12/21/2021
Question: How are we accurately modeling, given the extreme and unprecedented weather we are experiencing, resulting in bitterly cold winters and unseasonably hot summers? Does the system have the ability to respond to changes in capacity needs?
Answer: Our reserve margin study is now about 2 years old, but it does consider the contribution of extreme weather and how much these events contribute to peak load compared to a normal winter peak. We take this into account and set the reserve margin accordingly.
PROC 00007 Published On: 12/21/2021
Question: An all-source RFP is very involved and is an opportunity learn how the market is pricing other resources as well. Your response raises a concern of whether the structure of the RFP will be limiting so DESC will not receive as many responses since it is difficult to define how DESC wants a resource to operate in an RFP and ensure you receive the series you want and need. What is the timeframe to evaluate this?
Answer: The planned All-Source Peaker Replacement RFP process is intended to inform the current need for replacement resources and not to gain a perspective on all new resources that will be considered in future IRPs. We know the services that these existing resources already provide, and we seek to define them neutrally. Technology neutrality is the overarching goal of the RFP development, since DESC would like to evaluate how we can replace the resources effectively. The timeframe to evaluate this will be in early 2022.
PROC 00008 Published On: 03/18/2022
Question: How/why was the Canadys location selected? Were any cases evaluated with ESS or CTs located in or near the Charleston load center?
Answer: The Canadys site formerly hosted a significant amount of generation and there is a large network transmission substation at that location (both at 115 KV and 230 KV voltage levels). The site is also served by the CGT system. DESC did not have enough time to evaluate CTs or any new systems at Williams or somewhere closer. CTs or storage could defer transmission upgrades, but a study would need to be conducted.
PROC 00009 Published On: 03/18/2022
Question: Haven’t the uprates at Jasper and Columbia already occurred? Are they the same uprates that were already in the Modified IRP modeling?
Answer: The uprates are in progress over the past and upcoming outage seasons. They were not in the transmission planning model during the study. These uprates were included in the 2021 IRP Update (Advanced Gas Path upgrades at Jasper and Columbia Energy Center) as were the simple cycle CT replacements at Bushy Park, Parr, and Urquhart. The Urquhart replacements will be subject to the All Source RFP process per the Partial Settlement Agreement in PSC Docket 2021-93-E.
PROC 00010 Published On: 03/18/2022
Question: Are you performing that dispatch in a spreadsheet or in Power World? Are you doing this for both Santee Cooper analyses?
Answer: The dispatch is being conducted in Power World. No.
PROC 00011 Published On: 03/18/2022
Question: What RFP data does DESC intend to use to inform those cost inputs?
Answer: Technology costs provided in the green sheets are based on actual bids and the company’s actual costs of building new generation. DESC may be able to use submissions to the Urquhart RFP depending on the type of resources that are presented. However, it’s doubtful that any new generation cost information from this RFP will be available in time for the Retirement Study or for use in the 2022 IRP Update.
PROC 00012 Published On: 04/20/2022
Question: Would the next TIA results be incorporated into the 2023 IRP?
Answer: This is DESC’s intention, but it depends on when the 2023 IRP will need to be filed.
PROC 00013 Published On: 06/17/2022
Question: Stakeholders are seeking time to reflect on what is and is not working about the stakeholder process and how to ensure it can capture all the important aspects of the analyses DESC is working on before they are completed.
Answer: DESC continues to welcome Stakeholder feedback on the IRP Advisory Group process. Please provide written comments at any time with suggestions on how to improve the Stakeholder process.
PROC 00014 Published On: 06/17/2022
Question: Session VII discussed the Reserve Margin Study that will be incorporated into the 2023 IRP. This is a critical study that will determine the planning reserve margin, resource capacity accreditation, and how portfolios are measured for reliability. Due to the importance of this study, we kindly request this be a focal point of the next stakeholder session.
Answer: DESC is still working toward these goals and will continue to work with Stakeholders on these issues. DESC intends to focus the next Stakeholder Meeting on the 2022 IRP Update, but will provide an update on progress at that meeting. The Company will revisit these topics for more detailed discussion with Stakeholders at future meetings.
PROC 00015 Published On: 06/17/2022
Question: Because of the apparent switch to LT Plan for the 2022 IRP Update, PLEXOS’s capacity optimization module, we would also welcome a discussion of the tunneling and other constraints DESC intends to apply to its analysis.
Answer: DESC understands “tunneling” as the effect of constraints like annual limits on the amount of new resource that can be added in a single model year. DESC believes there are reasonable limits on the pace at which new resources can be added to the system and will discuss this information with Stakeholders in Section VI.
MODL 00001 Published On: 02/23/2021
Question: What feedback is DESC seeking on the model requirements matrix?
Answer: DESC is primarily seeking feedback on the evaluation criteria and the models to be evaluated, that is the columns and rows of the matrix. DESC also welcomes Stakeholder input on how the models presented rank against the defined criteria. Please see further details under the "Stakeholder Materials" page of the website.
MODL 00002 Published On: 02/23/2021
Question: It sounds like Dominion Virginia does not currently use Partial Chronology in PLEXOS (please confirm), do they currently use Fitted or Sample Chronology and how many blocks per month do they use?
Answer: DESC intends to use PLEXOS in a chronological configuration, if selected, through the Fitted Chronology methodology. DESC and Dominion VA are currently using between 6-12 blocks per day to solve PLEXOS.
MODL 00003 Published On: 02/23/2021
Question: In addition to capacity expansion modeling, will production cost modeling be performed to assess the portfolios identified by the capacity expansion model? If so, which production cost model?
Answer: DESC and many utilities use PLEXOS for both capabilities. The LT module sets the optimal resource portfolio and then the ST module is used to determine the optimized production costs.
MODL 00004 Published On: 02/23/2021
Question: What are Energy Exemplar's licensing terms? Are any restrictions on use of the license, is it the same version of PLEXOS that DESC is using, do you still need a license to view the manual?
Answer: We will need to discuss this question with Energy Exemplar to get a specific description of the licensing restrictions or lack thereof. Our presumption is that they are offering the same model as is being used by DESC.
MODL 00005 Published On: 02/23/2021
Question: When does DESC anticipate deploying PLEXOS or another chosen model, the 2023 IRP?
Answer: We anticipate PLEXOS to be fully implemented by the 2022 IRP Update as directed in the Commission Order. If another model is selected, PLEXOS may have to be used as an interim solution for the 2022 IRP Update in which case the new model would be adopted for 2023 IRP.
MODL 00006 (revised 02/25/2021) Published On: 02/23/2021
Question: Slide 37 of the Session I Advisory Group Presentation states that inputs to PLEXOS can be an equation. Are inputs limited to vectors that change over time or can DSM cost and availability change dynamically based on the model’s selection?
Answer: The DSM inputs can be set as a constant or input as time series of values in a datafile. DESC will work with ICF to evaluate combinations of DSM measures and estimate the cost of those measures needed to achieve various levels of reductions in load. These load reductions will be modeled as load scenarios or DSM resources in PLEXOS as appropriate.
MODL 00007 Published On: 02/23/2021
Question: When modeling DSM as resources, can PLEXOS and does DESC plan to use supply curves based on penetration rates, or does the model have to use a set cost similar to a generation asset?
Answer: PLEXOS can model resources based on characteristics like energy and cost, but not specific types of DSM measures. Adding more than a few DSM resource options is likely to increase solver complexity greatly and reduce the ability to find a solution. Much like a turbine or combined cycle, there will be a limited set of DSM resource options and costs that represent entire suites of measures at different penetration levels. Currently, DESC plans to model DSM portfolios with different cost and reduction potentials such as 1%, 1,25%, 1.5%, etc. The model will have DSM candidate resources with progressive cost and energy reductions.
MODL 00008 Published On: 02/23/2021
Question: Can you review all the models that were considered by DESC for use in the IRP, not just PLEXOS?
Answer: DESC and the Stakeholder Advisory Group will be reviewing a wide range of models for potential use in future IRPs. See Slide 42 of the Stakeholder Advisory Materials from Session I for a full list of the models considered. Stakeholders will also have an opportunity to suggest additional models as part of the Session I homework.
MODL 00009 Published On: 03/01/2021
Question: What are the hardware and software requirements for the version of PLEXOS that intervenors will license?
Answer: Energy Exemplar provides the system requirements for PLEXOS on its website here: https://www.plexosproject.com/articulo-download-plexos
MODL 00010 Published On: 03/02/2021
Question: The Commission's IRP order requires DESC to file contemporaneously with each future IRP, the modeling inputs, outputs, assumptions, and any post-processing spreadsheets, as well as the model manual. How will DESC provide this access to those intervenors who do not want to or cannot devote resources to utilizing a PLEXOS license?
Answer: The data will be made available in the same manner to all Stakeholders. Excel spreadsheets will be provided for all input and output data in addition to any native PLEXOS formats. The PLEXOS manual cannot be provided without a license.
MODL 00011 Published On: 04/26/2021
Question: A few concerns were raised pertaining to the examples provided on how PLEXOS was used in other IRP processes, which are listed below: 1. Exhibit A says that the license may only be used "for the purpose of reviewing or analyzing the electric price or power cost forecasts developed by the Client." That would exclude its use for IRP purposes. 2. Section 8 and the "Base Fees" section of Exhibit A say that no training or support are covered except as specified in Exhibit A. And Exhibit A says a fee of $2500 per day is required. That seems inconsistent with the provision of unlimited support and training that was encompassed in the $8000 option discussed during the IRP workshop. 3. The agreement is written as if someone other than DESC is the licensee and therefore, that someone other than DESC is paying the license fees. 4. The agreement would seem to restrict use of the license to an employee of licensee (Exhibit A), which would be problematic. A consultant to an intervenor would not be able to use it. 5. The agreement also prevents more than one employee from using the license. Consumers is providing two-seat Aurora licenses to intervenors, so EE should do the same here or let more than one person access the license, so that we can work as a team to set up runs. 6. The agreement also states, "License granted by this Agreement shall be for the duration of the Proceeding, but in no event longer than twelve months." The current IRP has gone on for longer than twelve months from the date it was filed, this provision would potentially restrict us from using the license during the duration of the proceeding.
Answer: The DESC team had raised these concerns with Energy Exemplar (EE).
MODL 00012 Published On: 04/26/2021
Question: Provision of the model manual is not a "nice to have." It is required on page 29 of Order No. 2020-832.
Answer: The DESC IRP team agrees that the minimum requirement includes that Stakeholders or other intervenors have access to all the model documentation. With that understanding, the team evaluated access to the manual as part of the Commission scorecard, which was composed of “need-to-have” requirements. The team was not attempting to determine the exact threshold of what qualifies as a manual, whether that would be a collection of files or a standalone document.
MODL 00013 Published On: 04/26/2021
Question: Slides 39-40 provide an overview of how PLEXOS is used in other IRP processes. Do you have similar information for the other four models?
Answer: Our analysis approach focused on assessing the functionality of other options and whether PLEXOS met certain criteria. We did not perform the same review of intervenor use for the other models were assessed.
MODL 00014 Published On: 04/26/2021
Question: Typically, I think of "support" as the ability to ask questions of the vendor if we encounter an issue executing runs, e.g. the model isn't interpreting cost inputs in the way you intend. Is that kind of support available through Energy Exemplar for PLEXOS?
Answer: Yes. PLEXOS has a support email that is used by DESC to address the types of issues that you describe in a timely manner.
MODL 00015 Published On: 12/21/2021
Question: Is DESC proposing that the "requirement levels for each Reliability Factor" would be constraints in the capacity expansion model? If so, does this apply to all the RFs, Including e.g., fast start, AGC, black start?
Answer: Not all factors will be included in the optimization analysis. Some will be evaluated separately. Slide 18 of the Session V Stakeholder slides indicates the reliability elements that will be modeled explicitly in PLEXOS and those that will be considered outside of the PLEXOS model.
MODL 00016 Published On: 12/21/2021
Question: Did DESC consider stochastic ST runs, instead of using PASA, to calculate LOLE? If not, would DESC consider testing both approaches in a portfolio with increased wind, solar, and storage. I ask because PASA does not do sequential Monte Carlo 8760 analysis, and the storage will be scheduled against the average capacity reserves rather than the specific needs in a particular sample (i.e., one weather year and one outage draw).
Answer: In the past, DESC used a peak hour study for calculating the reserve margin requirement and for calculating the contribution of solar resource towards meeting the reserve margin. Based on prior feedback provided by Stakeholders and DESC, the Commission has ordered DESC to use an LOLE-based reserve margin analysis and ELCC-based assessment of resource capacity value. DESC will comply with the Commission’s orders and use LOLE and ELCC methods through the 2023 IRP. To DESC’s knowledge, Energy Exemplar has not directly promoted PLEXOS ST Plan for reliability studies. Energy Exemplar has instead recommended relying upon the purpose-built PASA for performing system reliability studies. However, DESC is interested in better understanding the method recently proposed by Stakeholders at IRP Advisory Group Session V. DESC requests that you send any available reference materials to the DESC-IRP-Group at DESC-IRP-Group@crai.com. Following the review of this material, DESC will schedule a follow up call to discuss the proposed approach as well as any benefits or draw-backs relative to the LOLE method ordered by the Commission.
MODL 00017 Published On: 12/21/2021
Question: Is DESC proposing to use Marginal ELCC of each resource or the Average ELCC? Will portfolio effects of ELCC be considered?
Answer: DESC uses average ELCC when evaluating existing units on the system and marginal ELCC when evaluating incremental units.
MODL 00018 Published On: 12/21/2021
Question: How are PPA costs modeled?
Answer: Unfortunately, PLEXOS does not have the option to input a PPA with price flexibility from one year to the next. Therefore, we represent the annual cost of those resources as the levelized cost of the contract over the life of the PPA. Additionally, when PLEXOS adds new units, the model wants to simulate a utility-owned asset that will be depreciated, rather than a PPA for which these treatments are not needed. As a workaround, we take the levelized cost of the PPA and input it as a build cost. This solution was also faced by the Richmond team, and they use a similar solution which we developed independently of one another.
MODL 00019 Published On: 12/21/2021
Question: We'd love to see the replacement cost assumptions in specifics and the spreadsheets that would be used to translate those into PLEXOS inputs.
Answer: DESC will share the cost and performance assumptions for new utility-scale resources with interested Stakeholders as requested. However, DESC cautions that these initial values may be subject to modification as new information is gathered through the All-Source RFP or when Dominion updates its internal assessment of new resource costs.
MODL 00020 Published On: 06/17/2022
Question: Stakeholders are seeking descriptions of model settings for the PLEXOS LT capacity expansion module. Of particular interest is the model horizon, any splits in the horizon, and how the model is handling chronology and week/day sampling.
Answer: In all models, LT Plan was run in a single 30- year step. Per written recommendation of Energy Exemplar, DESC found that run times improved and the model converged regularly using the global slicing blocks with five time slices per day, as recommended for systems with higher percentages of solar. This creates a mini load duration curve each day, does not maintain chronology within the day, has better results than a fitted solution when high levels of solar are included, and does maintain chronology daily, weekly and monthly.
MODL 00021 Published On: 06/17/2022
Question: For the modelling battery storage operations, charging constraints for solar investment tax credit (ITC) can be included, but DESC should avoid over constraining the model. PLEXOS has the option to make these constraints a “soft constraint,” incurring an economic penalty to violate. We recommend including a PLEXOS parameter for “RHS Penalty” of $500/MWh for any grid charging.
Answer: Expansion candidates are generic units and DESC will continue to evaluate paired resources as being charged by the solar component. DESC will model PPAs in configurations that are presented to the company through the RFP process.
LOAD 00001 Published On: 04/26/2021
Question: There is volatility in load year-to-year, and the magnitude of the peak is highly volatile. What method is used to try and assign a capacity value due to volatility in load? Could we get more detail on ELCC methodology?
Answer: In DESC’s service territory, the greatest firm load potential is in the winter and so this is when we forecast peaks to be highest. Previously in the 2020 IRP, DESC evaluated a number of different peak hours and the respective contribution of resources on the system during those peaks. The Commission rejected this method and mandated the ELCC at 4.25% of nameplate capacity. See Appendix F of the 2020 Modified IRP for descriptions and calculation of the ELCC used.
LOAD 00002 Published On: 12/21/2021
Question: If DESC is having a day when load is high and have forced outages on the system, and you’re in trouble, and you’ve exhausted everything on your system and still in trouble, and need to shed load, is it part of protocol to call neighbor utilities and ask them if they have power that they can sell? Is this included in the LOLE study?
Answer: Yes, this is part of our operational procedure. However, these reserves are not always available even when called. For example, in January 2014 DESC called for reserves from neighboring utilities and these resources were not available. For operations this is part of the protocol. For the purpose of the LOLE study, it is not necessary to thoroughly assess neighboring utilities since DESC’s goal is to maintain reliability for our own customers.
DSM 00001 Published On: 02/23/2021
Question: It's my understanding that the prior characterization of energy efficiency savings relied on load shapes for a subset of measures in DESC's energy efficiency portfolio and that at least two of those measures had significant negative savings, meaning that somehow they cause participants consume more energy not less. Is that the same shape that DESC will use to characterize energy efficiency for purposes of its Modified IRP filing?
Answer: The EE profile was developed for use in the ICF Planning Model for the development of the DSM Potential Study and 5-year Program plans. Six of the sixteen measures used in the EE profile, specifically heating and cooling measures, did have some negative impacts. The negative savings are asynchronous cycling of the baseline and upgrade system. Meaning, some hours when the baseline system is “off” the upgrade system would be “on” resulting in negative savings. However, overall, these measures do provide energy savings. It should be noted that the original heat gain/heat loss simulation model used in the development of these load shapes were derived from an ICF developed tool, Beacon Residential Energy Modeling, which uses a DOE-2 engine.
DSM 00002 Published On: 02/23/2021
Question: Can you please provide the DSM program cost effectiveness calculations, including all incentive and non-incentive cost components?
Answer: We addressed the incentive and non-incentive components for cost-effectiveness testing. “Incentive costs” include payments DESC makes in the form of rebates and incentives, instant rebated, and direct installation of measures in low-income communities and small businesses. "Non incentive costs" would include utility administration, third party implementation, marketing, and evaluation costs. Incentive costs are payments made to customers or contractors. See Slide 17 of the Stakeholder Advisory Materials from Session I for more information.
DSM 00003 Published On: 02/23/2021
Question: Through your new building envelope focus, for how many homes per year do you plan to ensure that the home receives attic insulation plus leak sealing in the envelope plus duct sealing? Can you supply that number from your plan please?
Answer: During the current program year, PY11, DESC has forecasted that the Home Energy Check-up Tier 2 will provide building envelope incentives for 359 homes and the low income program will provide the direct install of weatherization measures in 100 mobile homes.
DSM 00004 Published On: 05/11/2021
Question: Can you provide more specifics on how you arrived at such low impacts of NEEP and HVAC improvements in energy efficiency interventions? How can these programs be prioritized?
Answer: Thank you for this feedback. We forwarded this question onto the DSM staff where it can be more appropriately be addressed. The DESC IRP team will be using efficiency assumptions developed as part of that process as well as any cases specified by the Commission. The EE programs will continue to be discussed as inputs to the IRP, but the actual design, modification, and planning of DSM programs will continue to be addressed within DESC’s Energy Efficiency Advisory Group. For your information: During the 2019 DESC DSM Potential Study both existing housing stock and low-income customers were identified as priorities and will continue to be priorities with the new DSM potential study that will get underway this year. As such, the current portfolio includes doubling the participation in the low-income program, the Neighborhood Energy Efficiency Program. In addition, NEEP will again double under the Rapid Assessment recommendations. NEEP is also in process of undergoing an expansion of the installed measures that customers will receive to include a limited number of refrigerator replacements. For the HVAC program, rebates were increased to encourage 15 SEER adoption and the addition of a rebate to incentivize the removal of electric furnaces and the installation of EnergyStar heat pumps.
DSM 00005 Published On: 05/11/2021
Question: How can DESC realistically reach a 1% energy efficiency target with primarily only energy audits? Energy audits alone cannot achieve energy real efficiency gains without implementation of audit recommendations.
Answer: Thank you for this feedback. We forwarded this question onto the DESC DSM department where it can more appropriately be addressed. The DESC IRP team will be using efficiency assumptions developed as part of that process as well as any cases specified by the Commission. The EE programs will continue to be discussed as inputs to the IRP, but the actual design, modification, and planning of DSM programs will continue to be addressed within DESC’s Energy Efficiency Advisory Group. DESC has not stated that a 1% energy efficiency target could be achieved only with energy audits. The DESC DSM portfolio of programs consists of 10 programs – 7 residential and 3 C&I. The Home Energy Check-up program, which is a residential audit, is just one of the DSM programs. For eligible customers, Tier 2 of the Home Energy Check-up allows customers to follow through on the recommendations made during the residential audit. Four of the DSM programs include the direct installation of measures: Home Energy Check-up Tier 1 and 2; the Neighborhood Energy Efficiency Program (core program and weatherization measures for mobile homes), the Multifamily Program (residential units and common areas) and the Small Business Energy Solutions Program.
DSM 00006 Published On: 06/11/2021
Question: Several DSM measures can provide some of the "reliability" criteria, e.g. Volt-VAR optimization, demand response, etc. are you accounting for the benefits that can be provided by demand-side resources?
Answer: DESC models DR as a general program that reduces demand at a certain cost. The reliability benefits of DSM are captured in the reserve margin as DR can meet portions of the reserve margin requirements.
DSM 00007 Published On: 10/12/2021
Question: How did DESC determine the levelized costs of DSM bundles in the 2021 IRP Update?
Answer: In order to provide more transparency about which programs are driving the portfolio level levelized costs up or down, please see the DSM Levelized Cost Calculation file on the Stakeholder Materials section of the website. Together, the residential and non-residential portfolios have a levelized cost of $0.0378/kWh.
DSM 00008 Published On: 10/12/2021
Question: The DSM bundles used by DESC in the 2021 IRP Update appear to show negative savings in certain hours. Why is this, and how do these negative hours impact the expected cost of the DSM bundles?
Answer: It’s important to note that the measure level load shapes were used to develop an avoided energy cost. They are weighted to develop one DSM load shape that is then used to model a DSM resource and attach an avoided energy cost for the purpose of cost-effectiveness testing.
In order to understand what the impact on avoided energy cost would be if ICF used updated load shapes for the heating and cooling measures (the ones that had negative hours), ICF produced new load shapes for these measures that do not have negative hours associated with them. The purpose was to compare what the resulting avoided energy cost would be if these load shapes were used in the analysis
Because the previous model used by DESC for this purpose is no longer in use or available, DESC used both the previous load shapes and the new load shapes within its new modeling environment to assess the change. The result of this analysis was done in two ways in order to make sure all of the implications were understood.
DSM 00009 Published On: 12/21/2021
Question: Most of these resources by themselves won't replace the coal units, so why eliminate DSM on that basis? It could be a cost-effective component of a replacement portfolio.
Answer: DESC agrees that DSM can be a cost-effective resource for meeting customer requirements and proposes to model DSM in all Retirement Study Scenarios at the 1% level.
DSM 00010 Published On: 03/18/2022
Question: It appears that EE and DSM are consistent across all these market scenarios, can you talk about the justification for not evaluating different levels of EE/DSM?
Answer: The purpose of the retirement study is to evaluate the impacts of early retirement - and the scale of EE / DSM is not large enough to serve as an effective replacement of the units.
DSM 00011 Published On: 06/17/2022
Question: The lack of weather adjusted EE profiles is an area of significant interest. Though we acknowledge that there is no readily available source for this data and that this is a limitation of all LOLE studies, we suggest that the Company invite input from its DSM consultant, ICF, who has the capability to do building energy modeling under different weather conditions.
Answer: Please submit this comment to DESC’s Energy Efficiency Advisory Group, which has been working with Stakeholders to develop the Company’s upcoming Market Potential Study and has a meeting scheduled on June 29th to seek input on the EE profile. The findings of this study, once complete, will be used to develop inputs to future IRPs.
DSM 00012 Published On: 06/17/2022
Question: To our knowledge, the DSM Advisory Group has not worked with DESC to create the DSM assumptions outlined in the Commission’s 2020 IRP Order and these would need to be delivered in advance of completing the ongoing Market Potential Study.
Answer: DESC has consulted with the Energy Efficiency Advisory Group (EEAG) concerning the scope and timetable for the DSM potential study. The Company has consulted with the EEAG concerning key inputs, definitions, and shared a draft list of measures for EEAG feedback. DESC continues to provide updates to the EEAG concerning the preliminary findings and status of the market potential study and plans to share the results of the study with the EEAG once it is finalized.
NRES 00001 Published On: 04/26/2021
Question: For Dispatchability and Operational Flexibility, inverter-based resources can be dispatched downward incredibly quickly and can ramp upwards just as quickly if you hold headroom. Multiple studies have been conducted as well as real-world operations of solar providing Automatic Generation Control. You should consider a class of inverter-based resources that are procured to provide dispatch flexibility rather than just must-take. Inverter-based resources are required to be capable of providing VAR support and have a broader range of reactive power that can be provided compared to fossil. Are you capturing this in your reliability criteria?
Answer: DESC is aware of operational projects where solar provides Automatic Generation Control that is beneficial for other utilities. Traditionally, DESC models the resources that have been proposed and offered on the DESC system, and those proposed assets did not include solar providing AGC. DESC recognizes that part of the Stakeholder process is gaining feedback on the type of assets modeled and will consider these suggestions.
NRES 00002 Published On: 12/21/2021
Question: In which modeling were the uprates evaluated?
Answer: The associated modeling was performed for DESC’s Power Generation group to determine whether the uprates were a cost-effective upgrade.
NRES 00003 Published On: 12/21/2021
Question: The cost function analyzes carrying time, not revenue requirements. Is that not accurate?
Answer: With the associated financial variables, DESC can calculate the revenue requirement values from our output.
NRES 00004 Published On: 12/21/2021
Question: Do you mind commenting on potential gas transmission expansion associated with potential replacement resources and whether/how those gas transmission capital costs will be factored in?
Answer: Each candidate resource in the Retirement Study will have firm transportation costs associated with it. These will be part of the cost of resources as we build the model inputs.
NRES 00005 Published On: 03/18/2022
Question: In discussion of case 1, 4, and the conclusion new tie lines with SOCO interface are identified but not explored or price estimated in any way. Does DESC have plans to further explore the feasibility of additional tie lines with SOCO to potentially accommodate an incremental power purchase option?
Answer: Presumably replacing the existing capacity at Williams Station would not incur significant electric transmission costs, so this wasn’t seen as a scenario that needed to be studied as part of the TIA. New ties are being studied.
NRES 00006 Published On: 03/18/2022
Question: Were any n-1-1 violations rerun in powerworld for those dispatches?
Answer: DESC takes into account these violations and solves n-1-1 contingencies when possible.
NRES 00007 Published On: 03/18/2022
Question: So, in the summer, solar capacity is being dispatched at 100%?
Answer: Solar capacity was dispatched at approximately 81% of maximum rating.
NRES 00008 Published On: 03/18/2022
Question: What assumptions were used for dispatch of PV and BESS for each SUM Pk, WIN Pk, Spring cases?
Answer: In general, the peak cases assume all new resources will be fully dispatched, including solar and storage resources at Wateree. In the winter case, little to no dispatch of solar was included.
NRES 00009 Published On: 03/18/2022
Question: How were the power flow cases redispatched with the new generation mix?
Answer: Given that these units are new combine cycles, they are fully dispatched. At peak, all of the traditional baseload resources are dispatched. In the summer all contracted solar is also dispatched. Furthermore, all new CTs were dispatched first ahead of older technologies.
NRES 00010 Published On: 04/20/2022
Question: Solar/storage modeling, does this mean that you would assume the storage must be charged by the paired solar for the life of the project?
Answer: Paired solar and storage units are modeled only as a PPA. For these units, the battery is assumed to be charged only by the paired solar resource. DESC also models utility-owned battery storage units that are not under these constraints.
NRES 00011 Published On: 04/20/2022
Question: Does DESC plan to maintain the hard limit on battery charging for the lifetime of the paired solar + storage asset in their generic expansion plans?
Answer: Yes. For the purposes of modeling generic resource in the PLEXOS capacity expansion model, DESC intends to model paired solar plus storage PPAs under the configuration that the energy for the storage component is sourced from the paired solar component.
NRES 00012 Published On: 04/20/2022
Question: Does DESC plan on using the data set from the KCHS station to calibrate its models if it chooses not to use the NSRDB data?
Answer: No. DESC requests further input from Stakeholders on how these differences can be reconciled, but currently intends to use the data collected at actual solar sites on the system over a fewer number of years to inform the reliability study
NRES 00013 Published On: 04/20/2022
Question: Using PASA and LOLE to determine ELCC of resource. Does DESC plan to use this approach to determine a PRM? If so, how does DESC take into account battery storage charge and discharge scheduling, ITC constraints, etc.?
Answer: This process is a work in progress. The PASA model may not accurately reflect the contribution of storage resources as currently modeled and is exploring use the ST model to better characterize these units.
NRES 00014 Published On: 04/20/2022
Question: When is DESC likely to decide which ELCC method it goes with?
Answer: At this time, DESC intends to use a planning reserve margin for the 2023 IRP informed by the ongoing LOLE study. DESC also intends to use the LOLE analysis to inform the ELCC for solar and storage units for the 2023 IRP. However, DESC is committed to continuing to evaluate reliability approaches with Stakeholders through the IRP Advisory Group process.
NRES 00015 Published On: 04/20/2022
Question: Does DESC have plans to compare the NREL data to actual GHI values at other locations?
Answer: No. DESC requests further input from Stakeholders on how these differences can be reconciled, but currently intends to use the data collected at actual solar sites on the system over a fewer number of years to inform the reliability study.
NRES 00016 Published On: 06/17/2022
Question: While the Stakeholder Session VII provided some preliminary results for the portfolio LNPVs, it did not provide any information on selected candidate technologies for replacement. In the next stakeholder session, please provide this information, along with a discussion on why DESC believes each technology was selected (or not selected) by the model.
Answer: DESC provided the list of candidate resources in Session VI. A small number of specifications used in the actual PLEXOS retirement study have changed, these exact resource definitions will be provided to Stakeholders. Because of the nature of a resource optimization, it can be positively stated that the model chose each resource to meet the energy, demand, and reliability criteria at the lowest cost.
NRES 00017 Published On: 06/17/2022
Question: We have some concerns about the manner in which solar and storage are being treated. Specifically, the ITC should be applied regardless of ownership and hybrid batteries should not be constrained to be charged from the paired solar resource for the lifetime of the asset, but rather follow the ITC rules that require renewable charging for only the first five years.
Answer: In the Retirement Study both Company owned resources and PPAs include the benefit of the ITC. Expansion candidates are generic units and DESC will continue to evaluate paired resources as being charged by the solar component. DESC will model PPAs in configurations that are presented to the company through the RFP process.
NRES 00018 Published On: 06/17/2022
Question: DESC should analyze generation options for which no (or minimal) amount of transmission reinforcements would be required.
Answer: DESC will consider evaluating the option to replace some of Williams existing generation with some form of on-site resources in a future TIA scenario.
NRES 00019 Published On: 06/17/2022
Question: We are generally supportive of using the NREL ATB Advanced Technology Cost Scenario for solar and battery storage resources, provided it is updated to the latest available version. However, it is unclear from DESC’s stakeholder session material what the source will be for thermal resources.
Answer: As described in Stakeholder Session V and VI, the inputs for thermal units are sourced from the Company’s “green sheets”.
NRES 00020 Published On: 06/17/2022
Question: At higher levels of thermal unit retirements and increased solar + storage, resource adequacy becomes more energy constrained rather than capacity constrained. As a result, solar can provide significant resource adequacy benefits when combined with other resources. In the winter, solar can provide additional energy mid-day to recharge batteries in time for the second peak demand period in the evening.
Answer: DESC’s current inputs and optimization approach for paired PV solar and battery units allows for mid day charging in the manner described by Stakeholders. The model also has standalone PV solar and grid charged batteries available.
NRES 00021 Published On: 06/17/2022
Question: We agree that DESC should model a saturation effect for battery storage. In our experience, 4-hour storage saturation starts to occur between 15 20% of peak load. As a result, we recommend the following temporary ELCC values for storage: 100% Marginal ELCC at 750 MW ICAP, 80% at 1000MW, 60% at 1250MW, and 40% at 1500 MW. In addition, it is also important to provide PLEXOS with an 8-hour storage candidate with 100% ELCC.
Answer: Thank you for this feedback. DESC intends to employ a temporary schedule of declining ELCC as storage units are added to the system and will use these recommendations to influence the specifications of the 4 hour battery candidates for the 2022 IRP Update though some modifications may be made. DESC is also open to evaluating the ELCC value of an 8 hour battery as proposed by Stakeholders. DESC intends to use the results of the ELCC study to inform the 2023 IRP.
NRES 00022 Published On: 06/17/2022
Question: We recommend ex-post resource adequacy analysis on resulting battery storage portfolios to ensure they meet the reliability criteria of 0.1 days per year (or equivalent metric used by DESC). This “round trip” modeling can identify potential shortfalls or surplus capacity and better design a coal replacement portfolio.
Answer: Based on prior feedback provided by Stakeholders and DESC, the Commission has ordered DESC to use an LOLE based reserve margin analysis and ELCC based assessment of resource capacity value. DESC will comply with the Commission’s orders and use LOLE and ELCC methods through the 2023 IRP.
NRES 00023 Published On: 06/17/2022
Question: DESC does not include a proposal for ELCC or equivalent capacity accreditation for thermal resources. This introduces an implicit bias favoring new CT and CC resources. At a minimum, these resources should be discounted by the unforced capacity (UCAP), as is done in many jurisdictions. In addition, these resources should be reduced further due to the probability of correlated outages. We recommend new CT and CC resources have a 90% ELCC for firm capacity until a more detailed ELCC study can be conducted.
Answer: It’s correct that DESC does not include a value for ELCC or equivalent accreditation for thermal resources. Thermal resources are accredited with their summer and winter capacity. DESC disagrees that these units should be discounted and that there is a bias. Solar and battery resources have forced outage rates that are not used to discount their capacity contribution. The ELCC for solar and battery resources is based on their limited dispatchability. Thermal resource don’t share this limited dispatchability.
NRES 00024 Published On: 06/17/2022
Question: While the NSRDB data may not be perfect, we believe that the limitations of using historical observations from a select number of plants, as proposed by DESC, is significantly less robust. Historical observations would provide a short historical sample (as opposed to 23 years provided by the NREL NSRDB), amplify variability by not capturing geographic diversity and new resource configurations with much higher inverter loading rations (DC:AC ratios) that increase capacity factors and project economics.
Answer: DESC continues to be open to using NSRDB data if it can be validated as consistent with observed values. The Company welcomes Stakeholder suggestions on how this can be accomplished. There is limited geographic diversity in the service territory. DESC’s service area is relatively compact and prospective locations for new solar are concentrated between Columbia and Charleston.
NRES 00025 Published On: 06/17/2022
Question: We request that DESC provide stakeholders with either the full set of historical solar radiation observations taken from KCHS (Charleston International Airport) or direct stakeholders to the source data if it is publicly available.
Answer: This data is proprietary to DTN and cannot be shared publicly. Interested Stakeholders are encouraged to procure solar radiation observation data directly from DTN.
SCEN 00001 Published On: 02/24/2021
Question: Can DESC elaborate on the definition of "expected conditions?" as described in slide 44 of the Session I Stakeholder Advisory Group presentation?
Answer: Expected conditions reflect DESC’s most likely view of the future. This view, for example, contemplates the low gas price scenario, energy efficiency reductions of 1% and a $12/ton carbon price. Please see the 2020 Modified IRP, page 75 for additional details.
SCEN 00002 Published On: 04/26/2021
Question: I agree the use of scenarios can be effective to identify risks but depends on if scenarios are crafted as "likely" futures or possible "extreme" futures designed to test potential resource plans. I wouldn’t consider a $35 carbon fee as “extreme” since these extreme measures should truly test the system. Additionally, if there is a need to get to 80% clean energy by 2030, it would be helpful to know in advance, under the current situation, how that is possible before any regulation is created.
Answer: DESC agrees that it is important to consider history and potential future events that are realistic boundaries when doing scenario testing. To clarify, in all CO2 pricing scenarios DESC also escalates the carbon fees over time. In the $35/ton scenario, for example, the CO2 price rises to over $300/ton by 2050. This may or may not constitute an “extreme” scenario but has significant impacts on the system. Thank you for your comment regarding the 2030 target.
SCEN 00003 Published On: 04/26/2021
Question: If approved, might SEEM change DESC's market access assumptions for energy purchases?
Answer: SEEM is focused on the inter-hour 15-minute non-firm market. Therefore, it does not contribute to the reserve margin, and will not be used in reserve margin planning. It is more likely to facilitate real-time balancing and renewable integration. Implementation of SEEM could impact the cost effectiveness of different resources if they are able to sell energy into this market at favorable cost.
SCEN 00004 Published On: 04/26/2021
Question: Will you be doing a scenario for the administration's clean energy standard of 80% by 2030 and 100% clean energy by 2035?
Answer: DESC has not yet investigated this proposal in detail and will take the suggestion into consideration.
SCEN 00005 Published On: 04/26/2021
Question: Given that there is a proposal to extend the ITC out in time, and expand it to stand-alone storage, have you considered a scenario that models those ITC changes? A few bills proposed stand-alone storage or storage getting the ITC at the same level. Grid charging is no longer a detriment. There's been momentum and a couple of bills. In terms of timing, we may see these get passed at some point this summer. Timing - could there be an upside that looked at these?
Answer: The 2021 IRP Update will utilize the same resource plans as the 2020 Modified IRP, with a potential additional low carbon plan. DESC will monitor changes to the federal ITC as appropriate in future IRP updates.
SCEN 00006 Published On: 06/11/2021
Question: Is there a liquid hub available for significant reliance on market purchases/sales?
Answer: DESC does not participate in an organized capacity or energy market, so we limit our reliance on purchases and sales and energy and capacity.
SCEN 00007 Published On: 12/21/2021
Question: If the resource adequacy analysis is properly evaluating many weather years of data, why does the solar-limited design week criteria need to be evaluated separately? Shouldn't this be explicitly included in the resource adequacy analysis?
Answer: Even if DESC utilizes a LOLE comparison study, it does not necessarily mean that the energy will be sufficient to maintain reliability for the solar-limit design week. Even so, DESC does not object to considering your suggestion but has already considered a separate evaluation.
SCEN 00008 Published On: 12/21/2021
Question: Is DESC planning to incorporate imports from neighboring utilities into the LOLE study? Also, in the LOLE study, will thermal unit outages be modeled as occurring uniformly across the year or varying based on season/weather?
Answer: DESC does not count on neighbors for reliability, since we believe that reliability of the system is our responsibility. Further, there have been events, for example in January 2014, where DESC has called for reserves from neighboring regions and these resources were not available. Maintenance outages are planned, and forced outages are spread randomly across the year. These are not based on seasonal weather, since DESC has not been able to find a strong correlation between seasonal weather and outages.
SCEN 00009 Published On: 12/21/2021
Question: Are neighboring utilities a part of regional reserve sharing group, and how does that factor?
Answer: Neighboring utilities are only factored in as an effect on the reserve margin. Due to the restrictions of using those resources, we have not included them as part of the LOLE study, since we recognize the need to carry additional reserves ourselves.
SCEN 00010 Published On: 03/18/2022
Question: On the different configurations of battery storages, do you have a way to impose constraints in PLEXOS or otherwise assign value to these services, e.g., grid support? Otherwise, the model is just going to take the lowest cost battery, if any at all. Could you provide us more information about how you intend to do that? We don't want to make configuration recommendations that address something that can't be captured in the model.
Answer: We found PLEXOS that in an expansion plan, modelling these resources is not straightforward. However, we do have a way of modelling these resources and putting a value on them. We will continue to discuss reliability modeling with the Stakeholders as part of the IRP Advisory Group Process.
SCEN 00011 Published On: 03/18/2022
Question: For the case where Wateree and Williams are kept on online until the 2040s (i.e., not retired early), what does DESC assume replaces their capacity when they do retire in the 2040s? And does DESC incorporate any associated transmission or other costs associated with these eventual retirements?
Answer: The transmission upgrade costs are included when the units are retired in the 2040’s. In addition, the $309 million in upgrade costs are scaled up according to inflation.
SCEN 00012 Published On: 03/18/2022
Question: For Wateree and Williams, are your modeled forced outage rates reflective of actual forced outage rates? On a related note, do your modeled planned outage rates reflect the time required for major capital and/or maintenance work?
Answer: The outage rates are based on actual maintenance.
SCEN 00013 Published On: 03/18/2022
Question: I thought on the backend you would need to translate project costs back into revenue requirements. Wouldn’t you need to translate new capital costs into the revenue requirements?
Answer: The revenue requirements require multiple factors. We have to use the proper inputs into new capital into PLEXOS so that it can make a decision. It is not necessary to switch back into the fixed charge revenue requirements. There may be a need if we have to get very accurate measures of the rate impacts, but we believe the fixed charges will be a good estimate for the retirements study.
SCEN 00014 Published On: 03/18/2022
Question: To translate the capital costs of each LT Plan are you planning to use the same depreciation schedules/assumptions that you've used to calculate revenue requirements to date?
Answer: Yes.
SCEN 00015 Published On: 03/18/2022
Question: RE: the full loading of most/all the thermal units, was that a product of needing to meet a specific peak number or was it just assumed that a peak scenario would imply full dispatch of most/all thermal units?
Answer: A peak scenario would imply full dispatch of most or all thermal units.
SCEN 00016 Published On: 03/18/2022
Question: Has the production cost (PLEXOS) modeling team considered including a nodal (N-1 DCOPF) model and/or a "Charleston Import Interface" to represent the transmission limits going into Charleston?
Answer: No, we do not model the transmission system in PLEXOS.
SCEN 00017 Published On: 03/18/2022
Question: Does that mean that the upgrade costs of Case 3 as well as the specific generator additions in Case 3 were the only case against which the coal retirements were evaluated? Were the transmission upgrade costs from Case 3 ones that had to be added?
Answer: The TIA is not the same as the retirement study. DESC modeled the upgrade costs you see in case 3, however PLEXOS was allowed to select the any of replacement options. Most of the upgrades were triggered because we were moving generation out of the Williams area.
SCEN 00018 Published On: 03/18/2022
Question: Was that a product of needing to meet a specific peak number or was it just assumed that a peak scenario would imply full dispatch of most/all thermal units?
SCEN 00019 Published On: 03/18/2022
Question: Is it fair to say that the transmission upgrades needed at Canadys under Case 3 are mostly upgrades to the path from Canadys to the coastal load center? Also, I believe putting 1000+ MW of gas at Canadys significantly exceeds the 400+ MW of coal generation that was previously at that location. Is that why such extensive upgrades (133 miles) would be needed?
Answer: Yes. We need to go back with larger conductors to host what was previously sited there as well as the new unit.
SCEN 00020 Published On: 03/18/2022
Question: Is there enough natural gas transmission capacity to supply hypothetical gas plants at both Williams and Winyah? Our understanding is that these locations would be served by the same CGT pipeline?
Answer: There is no existing CGT capacity for these projects. A project would be needed for both proposals.
SCEN 00021 Published On: 03/18/2022
Question: What was the most challenging Santee Cooper scenario?
Answer: The most challenging Santee Cooper scenario was the replacement of Winyah with off-system purchases only.
SCEN 00022 Published On: 03/18/2022
Question: What was the source of the generation production data used in the study? It is my understanding that we need a dataset to account for power flow. I was wondering where that dataset was coming from?
Answer: We were studying peak conditions across three seasons. Units on the system are dispatched based on resource economics.
SCEN 00023 Published On: 04/20/2022
Question: I totally agree and understand that you can't model everything, but I do think part of the point of IRP modeling is to identify whether value can be derived from resource decisions that are differentiated in some way, i.e., location. From the TIA description, it sounds like a major reason for the upgrade costs is congestion into the Charleston load pocket, wouldn't that naturally lead one to consider the value of putting resources in that load pocket?
Answer: DESC plans on looking into this in a subsequent TIA and has requested Stakeholder input on future TIA scenarios as part of the Stakeholder homework.
SCEN 00024 Published On: 04/20/2022
Question: The prior scenarios included the most unfavorable Winyah retirement mitigation, with respect to transmission right?
Answer: In the coordinated transmission planning process, Santee Cooper provided several scenarios including the scenario chosen for use in the DESC TIA. This scenario is the most unfavorable Winyah retirement/resource replacement scenario considering its impact on the DESC transmission system.
SCEN 00025 Published On: 04/20/2022
Question: RE: Retirement Option 1 Were any PLEXOS LT cases run that 1) Assumed the ELG upgrades were not a sunk cost and could be avoided by retirement, and 2) assumed no transmission upgrade costs attributed to Williams because replacement resources could be added there. What is the current ELG methodology?
Answer: ELG upgrade costs were assumed to be sunk costs at the Williams station, but not for Wateree where they were treated as avoidable. There have not been any PLEXOS scenarios of resources cited at Williams and that replacement resources can avoid transmission upgrade costs. There are two technology pathways for ELG compliance. One is wastewater treatment, which is used at Williams. The other is near zero discharge of flue-gas treatment and de-sulfurization liquids using membrane technology, which is being considered at Wateree.
SCEN 00026 Published On: 04/20/2022
Question: 3.5% of total system costs over what period of years?
Answer: The 3.5% is the difference in the annual levelized NPV. The analysis includes costs for 30 years with end effects.
SCEN 00027 Published On: 04/20/2022
Question: Where the anticipated costs of new gas transmission capacity assigned to any gas alternatives?
Answer: Yes, all thermal candidates have gas interconnection costs included in the build costs to reflect needed pipeline expansions and interconnections.
SCEN 00028 Published On: 06/17/2022
Question: We remain very concerned about the proposed approach of evaluating reliability as if DESC’s system were an island. This ignores the physical interlinkages between DESC’s system and those of surrounding utilities. If DESC does not account for interactions with neighboring regions, we think it is likely that the study will conclude that DESC’s reserve margin should be much higher than is needed because the model will be more likely to see shortfalls of brief periods.
Answer: DESC does not count on neighbors for reliability, since we believe that reliability of the system is our responsibility. Further, there have been events, for example in January 2014, where DESC has called for reserves from neighboring regions and these resources were not available.
SCEN 00029 Published On: 06/17/2022
Question: We recommend DESC to consider implementing modeling of neighboring balancing authorities with consideration of their generation supply, load, LOLE and reserve margin targets. Ample public data is available for adequate modeling of neighbor’s resources and a combined model allows for the benefits of diversity of load and diversity of resources to be understood using stochastic modeling of outages and generation.
PLANS 00001 Published On: 02/24/2021
Question: In the Session I Advisory Group Presentation, DESC explains that it has verified the capability to optimally retire units and replace them with efficient mix of resource additions. How was this verified and how were "optimal" retirement and "efficient mix" defined in this process?
Answer: Optimal and most efficient mix are based solely on lowest NPV of all utility related costs. Reliability is handled outside the model. DESC has not independently verified the “optimal” results produced by PLEXOS, rather it is relying on the credibility of the model in the public domain at this point in time.
PLANS 00002 Published On: 03/05/2021
Question: Could Stakeholders get written follow-up on the ability to use the DSM cost curve? How are you collaborating on the retirement studies?
Answer: The DSM cost curve was not used in the IRP. No collaboration on retirement studies has taken place but this is expected to take place as we move forward with our studies over the next two years.
PLANS 00003 Published On: 04/26/2021
Question: Help me understand how replacement assumptions impacts analysis on the front end? Would it be better to deploy this at this stage?
Answer: Due to required process for evaluating transmission impacts, we have to describe exactly what changes to the system we want the transmission group to study. We have added the request letter to the Stakeholder Website for your review.
PLANS 00004 Published On: 04/26/2021
Question: Why is DESC already laying out the retirement order rather than allow the study to determine the order? Part of doing the analysis is to optimize the order. What criteria are you using to determine Wateree, then Williams, and then Cope? For the replacement cases on Slide 63, wouldn't the use of a capacity expansion model provide a more robust set of replacement options for retired units?
Answer: DESC decided on the retirement order according to plant characteristics. Cope is ordered last since it is the youngest, newest, most reliable, and has dual fuel capability with gas. Wateree has lowest capacity factor and lowest site cost. Finally, due to its location on the transmission system, outages at Williams result in the most operational difficulty meaning it may be more complicated to replace.
PLANS 00005 Published On: 04/26/2021
Question: Why will this retirement study take years? Last year, Dominion completed a retirement study in Virginia in a few months. Can you give a more specific timeline?
Answer: DESC aims to have the Wateree retirement study completed by the end of 2021.
PLANS 00006 Published On: 04/26/2021
Question: The peaking proposal does not appear to be a one-for-one replacement. It proposes an additional 85 MW. Can you explain?
Answer: The turbine replacement is a one for one replacement of like kind vital resources at the end of their useful life. The 85 MW being questioned appears to compare winter and summer ratings inappropriately.
PLANS 00007 Published On: 04/26/2021
Question: Why were certain retirements presented here omitted from the IRP?
Answer: The retirements were not omitted in the IRP. RP3 considered retirement of Wateree, RP4 evaluated retirement of McMeekin and Urquhart, and retirements of both Wateree and Williams were in RP 8. DESC still needs to do a full study of the retirements to understand the full impacts of their retirements.
PLANS 00008 Published On: 04/26/2021
Question: For cost implications, will a securitization option be considered as part of any sensitivity analysis included in these studies?
Answer: Securitization requires legislation from the General Assembly, and we don’t have it in South Carolina. Without legislation, securitization is not an available option at this time. There is no enabling legislation giving the Commission the authority to approve or order securitization of any retired plants.
PLANS 00009 Published On: 04/26/2021
Question: A one-for-one replacement seems to be built-in assumptions across scenarios. Given that DESC already has excess capacity and Wateree 2 is already offline for a significant period, are you considering scenarios that do not include 1 for 1 replacement of coal plants?
Answer: DESC dos not assume a 1-for-1 replacement standard. Rather, resources are added to meet the required reserve margin in MW.
PLANS 00010 Published On: 04/26/2021
Question: About reliability: where does the possibility of planned and unplanned outages fit in?
Answer: DESC does build in planned outages to modeling, and updates forced outage rates while considering generation units. If a unit has a high forced outage rate, this value will count against the generating unit.
PLANS 00011 Published On: 05/11/2021
Question: Why is the timeline for the coal plant retirement studies so unnecessarily and unjustifiably long?
Answer: The timeline for a comprehensive coal retirement study (“Retirement Study”) is neither unnecessarily nor unjustifiably long. A Retirement Study involves the coordinated efforts of multiple Dominion Energy functions. DESC Resource Planning will lead the overall effort and perform resource adequacy, reserve margin calculations, reliability, and system cost/resource optimization studies. To meet the pace of implementation required by SC PSC Order No. 2020-832, DESC Transmission will now perform a transmission impact analysis (“TIA”) for the coincident retirements of both the Wateree Station and the A.M. Williams Station. The TIA will show if the electrical impacts of the retirements are technically achievable and identify transmission cost estimates at the retirement site as well as upgrades at the replacement capacity study sites. DESC Power Generation will plan for the community impact including employee relations and will develop plans and costs for demolition, site restoration and any site re-use, and develop plans and costs for DE-owned replacement projects. The DE Environmental Department will study and report on environmental impact/benefits, areas of continuing compliance, and closure costs with special attention toward ash ponds and ash landfills. Performing the TIA has been identified as the longest lead time item and is required to inform other activities mentioned above for the timely and successful completion of the Retirement Study.
PLANS 00012 Published On: 05/28/2021
Question: How will your long, two-year schedule for coal retirement studies align with your decision due by October 2021 to select an ELG compliance pathway for each coal plant? How will you avoid committing DESC and its shareholders and ratepayers to unnecessary ELG upgrade costs?
Answer:
With respect to the October 2021 ELG “decision” referenced in the question – this is a deadline for the Company to make a regulatory filing with SC DHEC regarding its compliance plans with the ELG rule, not an actual expenditure.
The Company is actively undertaking the coal retirement studies prior to committing to the substantial ELG compliance project costs while also continuing with engineering and pilot study activities such that it can quickly move into compliance project implementation, if required for continued system reliability.
PLANS 00013 Published On: 07/14/2021
Question: As to the additional near term solar and storage modeling for RP8 that DESC plans to model [described in 7/7 email as a response to Stakeholders], can you provide additional details as to what exactly DESC plans to model? Our reading of the PSC's order requires DESC to model near term solar and storage additions for RP8 that were previously ordered by the PSC and modeled for RP7a and RP7b.
Answer: We are pleased to inform Stakeholders that based on the comments filed in response to the 2020 Modified IRP and feedback received during the Session III IRP Stakeholder Advisory Group, DESC intends to model an additional resource plan in its 2021 IRP Update that introduces nearer term solar and storage resources to its approved Resource Plan 8. DESC appreciates the feedback from its Stakeholders.
In development of the 2021 IRP Update resource plan specifications and in response to feedback from the DESC IRP Stakeholder Advisory Group, DESC will introduce a resource plan that incorporates near term renewables which is the addition of solar and storage in 2023. The new resource plan will be RP8a and will be based on the preferred plan, RP8, but will also include the near-term renewables from RP7b, RP7b2, and RP7b3 which were the better performing plans as compared to the RP7a plans. Like the RP7b plans, RP8a will include PPA Solar and PPA battery energy storage in the amounts of 400 MW and 100 MW respectively starting in 2023. Results will be shown for three levels of solar PPA pricing, $34/MWh, $36/MWh, and $38.94/MWh, as previously specified for the Modified 2020 IRP (RP8a, RP8a2, and RP8a3). The cost of the PPA battery storage will be based on the “4Hr Battery Storage – Advanced” case of the NREL 2020 Annual Technology Baseline (ATB).
PLANS 00014 Published On: 12/21/2021
Question: Whether you are talking about concurrent vs. competing attributes or whether a resource can provide a service vs. whether it does provide that service, those are all problems that can often be solved through contracting, e.g., through requiring new storage to maintain a SOC that allows it to provide AGC. So will DESC be able to articulate why these services are needed?
Answer: DESC is proposing reliability factors that describe what services are needed to maintain reliability at the portfolio level. DESC is working with its Transmission Planning group to define the level(s) of each service that are needed and will communicate this information to interested Stakeholders.
PLANS 00015 Published On: 12/21/2021
Question: Did DESC consider modeling "Fast Start" explicitly in PLEXOS as a Non-Spin reserve, either a function of the largest contingency or wind/solar uncertainty?
Answer: Yes, we will include it in the modeling. Since it is a minimum requirement, DESC may not indicate the total number of fast start resources on the system. Despite this, we will want to understand whether a candidate resource plan negatively impacts the number of and amount of fast start resources.
PLANS 00016 Published On: 12/21/2021
Question: For those factors that you are scoring outside of PLEXOS, will there be any way to answer the question of whether that service is needed for any given factor? I.e., whether you will need additional black start capability? Because if you are scoring each portfolio for each of these factors, I am assuming you intend these as incremental needs to the system?
PLANS 00017 Published On: 12/21/2021
Question: Can DESC clarify how it is treating: 1. inertial response; 2. primary frequency response; 3. secondary frequency response (i.e., frequency regulation, usually provided by units on AGC).
Answer: DESC does not propose to reflect inertial response as a reliability factor in future IRP analyses. Primary frequency response may be provided by frequency controllers, but DESC does not plan to consider this factor explicitly as part of the IRP analysis. AGC and ramping will be addressed in the DESC reliability analysis and future IRPs.
PLANS 00018 Published On: 12/21/2021
Question: How will DESC characterize renewables for the 2022 IRP Update?
Answer: Typically for an IRP, DESC takes the load profile of a year with substantial solar potential and builds the profiles using those data. We do this this for 30 years. As part of the LOLE study, DESC sees that the difficulty lies in syncing the load profile to 20 years of weather data. DESC is looking back at the weather data to assess periods when there was little to no solar resource. Unfortunately, we do not have actual solar data going back 20 years.
PLANS 00019 Published On: 12/21/2021
Question: There are reasons to limit service and IRPs are not used to determine energy adequacy, but if there are non-firm off system transactions being transacted in the IRP simulation, then why wouldn’t it be part of the resource adequacy study?
PLANS 00020 Published On: 12/21/2021
Question: To clarify, is 2028 likely to be the earliest date that Williams or Wateree could retire, or were you merely giving that as an example?
Answer: It is DESC’s viewpoint that 2028 is likely the first possible retirement date for Williams. This view is informed by previous experiences with replacing a similar MW amount and knowing the Williams plant is critical for voltage support. The Wateree plant may have more latitude, but additional research is necessary to confirm this inclination. This evaluation will be informed by the TIA and the selection of the first feasible retirement date will be substantiated with that study.
PLANS 00021 Published On: 12/21/2021
Question: I think it's important to derive scenario assumptions based on an internally consistent methodology and not match up a Low Gas price and a High CO2 price just because they are available. Put another way, can we confirm what market conditions would result in a Low Gas and High CO2 price and what else would that implicate about what you model?
Answer: Thank you for this feedback. DESC will evaluate the proposed scenarios and determine whether any changes are warranted in light of this comment prior to proceeding with the Retirement Study analysis.
PLANS 00022 Published On: 12/21/2021
Question: Is there a reason there's no option listed for utility-owned solar plus storage?
Answer: Historically, DESC has credited third-party developers with lower cost renewable resources. We are re-evaluating the cost of ownership and are considering the inclusion of utility-owned solar and storage in the Retirement Study and IRP.
PLANS 00023 Published On: 12/21/2021
Question: How does DESC propose using the outputs of the Retirement Study? What decisions will be made based on those outputs and how do these decisions feed into the IRP?
Answer: The goal is to recommend the retirement of one or both of the Wateree or Williams sites and better understand the expected impact of these retirements on system operation and the cost to serve customers.
PLANS 00024 Published On: 12/21/2021
Question: If you are going to do the work of issuing an all-source RFP is there a reason to limit it to CT replacements? Can DESC instead also use it to inform how you characterize all resource costs in the IRP?
Answer: DESC is reviewing Docket 2021-93-E and waiting for final decisions to see if there are alternative resources that could compete on our system. Depending on the bids that are received, the responses may impact the resource cost assumptions used in future analyses.
PLANS 00025 Published On: 12/21/2021
Question: When do you expect to issue the RFP, and can we offer comments on the RFP after the briefing session and review of the documents?
Answer: DESC intends to issue the All-Source Peaker Replacement RFP in mid-November. We reserve the right to amend this following the briefing session on November 1 and based on the feedback that arises out of Session V.
PLANS 00026 Published On: 12/21/2021
Question: How will maintenance capex of Williams and Wateree be treated based on retirement date, i.e., will it vary based on costs that can be avoided by retirement? Will the ELG costs in the retirement analysis as well?
Answer: The model will be populated with a schedule of costs that can be avoided if the unit retires. These “avoidable” costs will include ongoing operational costs and any capital projects, including ELG projects, that are needed to keep the plant operating reliably. DESC will also consider how the ongoing maintenance capital schedule would be affected in instances where DESC knows that the plants are going to retire in a specific year. In other words, if you’re going to retire the plant early, you might operate and maintain it differently than if you plan to keep operating it through the end of its useful life. DESC may also reach one step further and run with the lower capex first before considering other options when comparing the results to determine the ideal retirement date.
PLANS 00027 Published On: 03/18/2022
Question: Is there a general range of early retirement dates selected?
Answer: The model can select a variety of different retirement dates depending on the market conditions. For Wateree 1 and 2, retirements can be selected after 12/31/2028. For the Williams unit retirement can be selected after 12/31/2031.
PLANS 00028 Published On: 03/18/2022
Question: Could DESC by itself meeting a 55% reduction by 2035 without retirements?
Answer: No. Without early coal retirements, the 2021 IRP Update modeling projects that DESC will only reduce CO2 by approximately 32% by 2035, with the exact amount depending on the market conditions that are studied.
PLANS 00029 Published On: 03/18/2022
Question: Why were there changes from the 2020 IRP to the 2021 IRP? When you consider the high case inputs, there was a change in both costs and shape of savings?
Answer: We were required in the 2020 modified IRP update to incorporate marginal line losses in calculations. So, there was a per MWh change and energy change, but cost didn’t change.
PLANS 00030 Published On: 03/18/2022
Question: Are you quite certain that the EE inputs have been discussed in the EE Advisory Group? For example, they changed somewhat from the Modified 2020 IRP to the 2021 IRP Update but I don't believe the EE Advisory Group discussed them. Our primary concern relates back to the Modified 2020 IRP order which states, "DESC is required to use "cost effective, reasonable and achievable" as the standard going forward for evaluating the potential for higher savings portfolios in future IRPs and updates beginning with the 2021 IRP Update.
Answer: The 2019 Potential Study and the 2020 High Case Rapid Assessment form the basis for inputs to the 2020 and 2021 IRPs. This will also be the case for the 2022 IRP. The rapid assessment determined that the DSM portfolio could achieve the 1% high case and met the standard of cost effective, reasonable, and achievable. The potential study underway will allow stakeholders to engaged in deeper discussions about how the standard of cost effective, reasonable, and achievable will be applied for inputs to the 2023 IRP.
PLANS 00031 Published On: 04/20/2022
Question: RE: Retirement Option 2 Does "DESC optimized" relate only to the forced earliest possible date retirements for Wateree and Williams? Also, were these runs only conducted in LT or was ST used as well?
Answer: The retirement dates were selected by DESC in Retirement Options 2-4. Then PLEXOS was allowed to optimized replacements in each of the five Market Scenarios around these assumed retirement dates. The ST model was used to estimate portfolio operational costs.
PLANS 00032 Published On: 04/20/2022
Question: Additional general question for the retirement options. Was NPV calculated from the LT (or ST if run) outputs and was the Revenue Requirements model from the IRP used?
Answer: The output of the both the LT and ST Plan was used to inform a revenue requirement calculation. Fixed costs were loaded from the output of the LT build plan and the variable costs were loaded from the ST Plan. The revenue requirement spreadsheet used is similar to the one used in the IRP.
PLANS 00033 Published On: 04/20/2022
Question: What was the rationale for end of 2028 (Wateree) and end of 2031 (Williams) as the earliest retirement dates?
Answer: The transmission project lead times in the TIA were a factor. The earliest retirement dates were also informed by the expected timeline for developing new gas pipelines in the service territory as well as time needed for regulatory review and approvals. After additional analysis, DESC has determined that a 12/31/2030 date for Williams will be modeled and will adjust the Retirement Study inputs accordingly.
PLANS 00034 Published On: 04/20/2022
Question: While we understand the hesitation in sharing actual values during preliminary results, can DESC provide an indicative summary of what types of replacement resources were selected by the PLEXOS LT simulations?
Answer: DESC wants to emphasize that the point of the retirement study is to evaluate the impact of different retirement dates, not to indicate a preferred path forward for replacements. However, DESC will share the build plan results once the study has been finalized.
PLANS 00035 Published On: 06/17/2022
Question: It remains unclear why DESC is assuming Williams cannot retire by 12/31/2028 and avoid the ELG upgrade requirements. We request that in a future stakeholder session DESC clearly discuss the ELG compliance options available to both Williams and Wateree, and discuss any determinations the company has made regarding those options.
Answer: DESC will provide a schedule detailing the critical path and required duration of the replacement project. DESC will also provide the commitments, constraints and determinations for ELGs as presented in the Retirement Study.
PLANS 00036 Published On: 06/17/2022
Question: To our knowledge Canadys was the site of a 490 MW coal generator, but most replacement resources evaluated at this location were larger than the previous coal plant (1057 MW in Case 3 and 534 MW in Case 4). It is unclear from the results how much of the network upgrade costs are attributed to the increased capacity sited at the location. An alternative scenario should evaluate a like-for-like capacity replacement of the 490 MW plant to avoid additional network upgrades.
Answer: Case 4 of the original TIA already examined the installation of a similarly sized unit (534 MW) at the former Canadys site. The system has changed significantly over the last 10 years. While Canadys had 230 and 115 kV interconnection capability the conductors must be uprated and/or additional lines must be built to accommodate new generation at the site. There are no longer existing interconnection rights at the site. DESC is considering options to take advantage of the existing equipment to the maximum extent reasonably possible.
PLANS 00037 Published On: 06/17/2022
Question: A scenario should explicitly evaluate the proposed Winyah coal retirement in neighboring Santee Cooper region. There may be either increased transmission costs or potential cost savings associated with interregional transmission planning.
Answer: Thank you for that insight. That is one of the reasons a joint study with Santee was undertaken. Together, the two companies make up the South Carolina Regional Transmission Planning regional planning entity. For this reason, and the highly integrated nature of the two systems, joint planning must continue to occur. The Winyah retirement was assumed to occur in the first five TIA cases that was performed by DESC.
PLANS 00038 Published On: 06/17/2022
Question: The preliminary results of the retirement study presented to stakeholders do not comply with the Commission’s order on the Company’s 2020 IRP. The Company has decided that it is simply not feasible to avoid ELG costs at Williams, despite having requested a December 31, 2025 ELG compliance date to Williams. We have some serious concerns about the quality and validity of the TIA, including its ability to speak to the transmission upgrades that are universally necessary to facilitate retirement of this unit.
Answer: The Company has serious concerns about maintaining reliability in the greater Charleston area without the Williams plant. DESC has seen the importance of the unit in the day-to-day operation of the system, not just planning models. DESC must ensure that reliability of the grid in all instances including peak loads with loss of multiple transmission elements. The TIA and future studies are evaluating the upgrades needed to meet the Company’s responsibilities under all conditions.
PLANS 00039 Published On: 06/17/2022
Question: The absence of a baseline study for the TIA analysis raises the question of how many system reinforcements would be necessary or prudent independent of coal retirement.
Answer: The DESC system is assessed annually for the 10 year planning horizon. All reinforcements that were identified as part of that assessment by year-end 2020 were included as part of the of the base TIA cases.
PLANS 00040 Published On: 06/17/2022
Question: Given current macroeconomic conditions, inflationary pressure and supply chain constraints are likely across the industry in the short term. DESC should avoid applying any additional costs solely to renewable or storage resources. While these challenges have been a topic of concern across the industry, these disruptions will be true for conventional thermal technologies and transmission investment as well - including for replacement parts and plant upgrades.
Answer: DESC has a basis for the costs applied to all candidate resources, regardless of technology.
PLANS 00041 Published On: 06/17/2022
Question: Similar to the proposed TIA scenario, we propose DESC evaluate a scenario that assumes an early retirement (12/31/2028 at the latest) for both Williams and Wateree. This is consistent with the 2021 IRP Update preferred portfolio RP8. In addition, this scenario should not include transmission upgrades for the Williams retirement, on the assumption that replacement resources are located at or near the Williams site.
Answer: DESC does not believe that the replacement generation needed to maintain system reliability can be brought online by 12/31/2028. This finding is supported by the Retirement Study.
PLANS 00042 Published On: 06/17/2022
Question: While the DESC proposed scenario matrix includes base and high load forecasts, a low load forecast scenario is not evaluated. As a result, we recommend a scenario that assumes lower load growth.
Answer: The market scenarios included in the Retirement Study were developed in consultation with Stakeholders. A low load scenario is not expected to materially change the within 10 years, and DESC’s intent was to focus on the most impactful scenarios.
PLANS 00043 Published On: 06/17/2022
Question: We propose scenarios (both PLEXOS LT and ST) that assume coal retirements and no new gas resources are available. This will properly bookend the analysis to show the costs, benefits, emissions, and operations with a clean energy replacement portfolio.
Answer: DESC is open to exploring such a scenario in the 2022 IRP Update. The Company also intends to include new carbon-free options, such as nuclear SMRs, in future IRP studies.
PLANS 00044 Published On: 06/17/2022
Question: Stakeholders continue to recommend that DESC use NRELs SAM tool and NSRDB dataset for estimate contribution of solar units as part of the reliability evaluation. Stakeholders suggest that DESC could further validate the NRSDB solar radiation data by comparing estimates of solar unit output using NRELs SAM tool and NSRDB dataset at 10 or more solar sites over a significant period of measurement with the actual outputs at existing units on the DESC system.
Answer: DESC continues to be open to using NSRDB data if it can be validated as consistent with observed values. DESC will validate hourly outputs provided by Stakeholders using the proposed data and methods against actual outputs at solar sites operating on the DESC system. DESC requests that Stakeholders provide a description the approach taken and supporting assumptions used to estimate unit outputs.
RISK 00001 Published On: 02/23/2021
Question: Can DESC elaborate on the updated quantitative risk analysis and how it is applied to the company's preferred plan?
Answer: Please see the 2020 Modified IRP for further details. This should be publicly available prior to the next Stakeholder Advisory Group Meeting.
RISK 00002 Published On: 02/23/2021
Question: On slide 44 of the Session I Stakeholder Advisory Group presentation, why is levelized cost a metric instead of net present value? Can you define all of the metrics on this slide, e.g. reliability?
Answer: This is an error on the slide, levelized cost should be replaced with levelized net present value. DESC defines the metrics on slide 44 of the Session I presentation as follows:
RISK 00003 Published On: 04/26/2021
Question: Although I don’t have a strong opinion on which risk metric approach is preferable, I do feel strongly that stochastic analysis is often not the best way to capture risk. I prefer a scenario analysis with a range of scenario-based outcomes. I’m not a fan of the technology risk metric. This metric comes from the need to be concerned with fuel risk, but as we move away from that, it’s less necessary. I believe the diversity of resources is a better metric.
Answer: The DESC IRP team agrees that stochastic analysis has to be properly implemented to be significant. We also agree that risk associated with some technologies are fuel related, which is a factor often considered in stochastic analysis, but some related to technology risk are often not considered. DESC’s IRP analysis uses scenarios, consistent with this observation, to consider a wide range of factors
RISK 00004 Published On: 04/26/2021
Question: Doesn't reliance on purchases also reduce the risk of being reliant on stranded assets?
Answer: We recognize that there are potential risks and benefits of reliance on purchased power. With a greater reliance on the market comes less reliance on owned assets. Therefore, if DESC owns assets that operate below the cost of the market there can be advantages. On the other hand, if DESC owns assets that are above the costs of the market, this can strand assets.
RISK 00005 Published On: 04/26/2021
Question: Is commodity price risk specific to fuel costs only or are you considering broader commodity risk (steel as an example)?
Answer: The Commodity price risk metric is used to evaluate the cost risk associated with fuels burned; it does not include steel. DESC assumes new generator costs, including steel prices, rise based on a Handy-Whitman index when evaluating portfolios in the IRP.
RISK 00006 Published On: 06/11/2021
Question: Given recent events in Texas, are potential fuel supply interruptions part of the reliability analysis?
Answer: Yes. Our natural gas units rely on multiple pipelines from shale gas sources from the Gulf coast and several have oil fuel backup. Additionally, coal maintains a 60 to 90-day fuel supply.
RISK 00007 Published On: 06/11/2021
Question: Are you using 2049 as a 1-year snapshot on carbon emissions? Because cumulative emissions throughout the period will cause cost risks to ratepayers if CO2 is regulated.
Answer: The impact of cumulative emissions are captured in the CO2 costs incurred by each different portfolio. DESC will consider reporting a cumulative CO2 table into the outputs.
The impact of cumulative emissions are captured in the CO2 costs incurred by each different portfolio. DESC will consider reporting a cumulative CO2 table into the outputs.
RISK 00008 Published On: 06/11/2021
Question: Is the CO2 metric cumulative over the entire planning period or just in the year of 2049?
Answer: The CO2 emissions metric measures the portfolio’s 2049 emissions as a measure of progress towards DESC’s 2050 target.
RISK 00009 Published On: 06/11/2021
Question: Have you considered tracking water intensity as a core metric?
Answer: DESC does not consider the water intensity of the portfolio as a core metric but will take that suggestion into consideration.
RISK 00010 Published On: 12/21/2021
Question: Are forced outages more likely to occur when load is high-- i.e., when more units are required to be online and are more likely to be running flat out?
Answer: The company is not aware of a study that forced outages at individual units are more likely to occur during periods of high load. We welcome any further information that Stakeholders would like to provide on this topic. DESC reports forced outages in the NERC GADS database, some of which are weather related.
RISK 00011 Published On: 03/18/2022
Question: Is the new expected Vogtle output any significant part of the transmission constraints at Jasper? I assume that new output is included as baseload.
Answer: All Vogtle units are dispatched during peak summer and winter cases and that has an impact on the Dominion system.
RISK 00012 Published On: 04/20/2022
Question: Including interchange in the reliability study, I think it's important to make the distinction between relying on your neighbors for reliability and accurately modeling the flow of power. For example, if there has historically been trading with other BAs then why wouldn't you include that in this analysis? And you could explicit model other BAs or otherwise set up constraints so that there wouldn't be interchange unless power is actually available. The concern is that NERC requirements are on a 30-min interval, whereas DESC might be over constraining the system with 5 min intervals, resulting in more unserved energy events if looking purely in isolation. We typically don’t have generation inadequacies on 5-min intervals.
Answer: If DESC was planning on using off system resources to maintain reliability, they would be included in the study. DESC found that resource adequacy reliability events tend to impact its neighbors at the same time as they impact the Company. So that when DESC has had to call on resources in the past to deal with reliability issues, it was unable to rely upon them. DESC is currently studying the system at an hourly interval within PLEXOS.
RISK 00013 Published On: 04/20/2022
Question: Thermal forced outage rates are not one of the variables tested, they are assumed to be static?
Answer: Yes, the outage rates at thermal units are assumed to be static. DESC uses a rolling 5-year average, which is not dissimilar to the reserve margin contribution assigned to energy limited resources.
RISK 00014 Published On: 04/20/2022
Question: Did Dominion rely on imports recently when its nuclear plant had an unplanned outage?
Answer: VCSNS came offline at 5:28 p.m. on November 15, 2021 and remain offline until 7:48 p.m. on December 10, 2021. DESC did import energy for many of the days during the outage period. These purchases were due to several factors that are explained in testimony, rebuttal testimony, and responses to audits and requests in South Carolina PSC Docket No. 2022-002-E.
RISK 00015 Published On: 04/20/2022
Question: Are the reliability considerations in the retirement study different than the metrics you've used previously?
Answer: DESC may use different reliability considerations in the retirement study than it does in future IRPs. This is because the retirement study is attempting to evaluate whether reliability can be maintained in the short term, while the IRP is for long term planning.
RISK 00016 Published On: 06/17/2022
Question: It would also be useful to explore how many of the minor violations could be mitigated with other NWA, such as dynamic rating, operate around, selective reinforcements, and other grid enhancing technologies.
Answer: The TIA was a preliminary assessment indicating the contingencies shown to be the most severe for each limiting element listed. Evaluation of many more contingencies that created overloads or high loading of transmission elements would be needed for op guides, etc. This all takes time and will ultimate be addressed in future System Impact studies. Winter ratings were included as part of the winter season studies. Dynamic ratings are a short-term operational tool. Operations will use dynamic ratings as appropriate facing often conditions worse than N-1-1 contingencies.
RISK 00017 Published On: 06/17/2022
Question: We recommend that DESC provide detailed heat rate modeling assumptions for all units at the next stakeholder session. In the case of the new ICT and CC generators, the Company’s specific heat rate curve was not properly refit to the polynomial curve. To avoid this change – and use the Company’s heat rate curve directly, the model’s “Production object” setting for “Max Tranches” must be set to less than three so that the simulator used the marginal heat rate function provided in the input data verbatim.
Answer: DESC has corrected the issue and is specifying efficiency with an average heat rate curve.
RISK 00018 Published On: 06/17/2022
Question: We would like to understand if and how DESC is evaluating the variability of outages across time, correlation between outages at thermal generators, the effects of weather on outages, and fuel supply related outages on its thermal units. We ask DESC to accredit thermal generators at their seasonal rating less their forced outage rates (an approximation of unforced capacity or UCAP).
Answer: Forced outages are spread randomly across the year. These are not based on seasonal weather, since DESC has not been able to find a strong correlation between seasonal weather and outages. Thermal resources are accredited with their summer and winter capacity. DESC disagrees that these units should be discounted and that there is a bias. Solar and battery resources have forced outage rates that are not used to discount their capacity contribution. The ELCC for solar and battery resources is based on their limited dispatchability. Thermal resource don’t share this limited dispatchability.
MISC 00001 Published On: 02/23/2021
Question: At any point during the stakeholder process will DESC make its modeling files available to stakeholders who have signed the NDA?
Answer: Yes, DESC will make the modeling files available that are used to support future IRP filings at the time those future IRPs are filed.
MISC 00002 Published On: 03/01/2021
Question: Will DESC also be using Strategist's Differential Cost Effectiveness module? If so, how will it provide Strategist licenses to intervenors?
Answer: Strategist is an ABB software. DESC does not currently have licenses to use Strategist and will not be using Strategist's Differential Cost Effectiveness module in its future modeling.
MISC 00003 Published On: 03/02/2021
Question: Please provide the license agreement that Energy Exemplar will require intervenor licensees to sign.
Answer: Energy Exemplar requires that stakeholders that wish to view the utility's model within PLEXOS sign a limited license. Please contact Energy Exemplar at: dana.harris@energyexemplar.com for a copy of the limited license.
MISC 00004 Published On: 03/05/2021
Question: The Commission's IRP order requires DESC to absorb the cost of intervenor license fees, does DESC plan to do so?
Answer: Whatever cost DESC incurs to comply with the Commission’s order will be charged to the Company’s customers.
MISC 00005 Published On: 04/26/2021
Question: Does DESC consider 2022 to be a full IRP update year? Rather than an annual update?
Answer: DESC understands that 2022 will be an update year and that the next full IRP will be in 2023.
MISC 00006 Published On: 04/26/2021
Question: The footnote on slide 35 says that companion financial models are used for revenue requirement modeling. Has Dominion chosen a specific financial model?
Answer: PLEXOS has a financial model in their LT plan which models revenue requirements. It also has financial models. In the past, DESC created spreadsheet models to create total cost models outside of the modeling software, but this will be less necessary while using PLEXOS. There will still be some aspects that DESC will have to model in external spreadsheets to accurately reflect the way that the Commission requires revenue requirement reporting.
MISC 00007 Published On: 04/26/2021
Question: SWEPCO created a Stakeholder working group that can develop and create a limited number of sensitivities or cases. Then, the utility ran it on their behalf. Would DESC be willing to do that?
Answer: The team’s first aim is to reach a consensus on the model that will be used. We intend to be responsive to Stakeholder feedback but how the model will be used is a discussion for future Stakeholder meetings.
MISC 00008 Published On: 06/11/2021
Question: I am unaware of any other markets that measure inertia, and there is no need for this metric. As electric utility technology develops, there will be no need for this metric.
Answer: DESC chose to include inertia in the study since the factor is still relevant to the reliable operation of the current generating system. DESC will continue to evaluate the factors and contributions to those factors by each resource type.
MISC 00009 Published On: 03/18/2022
Question: Can you remind us what the base year is for the corporate goal is?
Answer: 2005 is the base year for Dominion Energy’s corporate targets.
MISC 00010 Published On: 04/20/2022
Question: How was the exact dispatch provided? In a discovery response? If so, which one?
Answer: Yes, it was provided in a discovery response. The dispatch in the TIA was provided in Sierra Club Discovery Request 2-3 in Docket 2021-192-E.
MISC 00011 Published On: 06/17/2022
Question: DESC should include portfolios with full and partial replacement resources at or near Williams station. Because the Charleston area is a load pocket on the transmission system, retiring a large amount of generation in the area without local replacement is likely to be a large driver of the transmission upgrade costs.
Answer: DESC will request scenarios with full and/or partial replacement of resources at or near Williams station, as requested by Stakeholders, as part the next TIA study expected to commence in Q3 of 2022.