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.