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June 18, 2020
Ms. Lisa Felice Executive Secretary Michigan Public Service Commission 7109 West Saginaw Highway Lansing, MI 48917 RE: In the matter of the Application of DTE Electric Company for approval of its Integrated Resource Plan pursuant to MCL 460.6t, and for other relief MPSC Case No: U-20471 Dear Ms. Felice: Attached for electronic filing in the above referenced matter is DTE Electric Company’s Integrated Resource Plan Modeling Software Collaborative Summary Report. Very truly yours, Lauren D. Donofrio LDD/erb Enclosure c: Service List
DTE Electric’s InteIntegrated
Lauren D. Donofrio (313) 235-4017 [email protected]
DTE Electric Company One Energy Plaza, 1635 WCB Detroit, MI 48226-1279
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DTE Electric’s Integrated Resource Plan (IRP)
Modeling Software Collaborative Summary Report
Case U-20471
June 18, 2020
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Contents Background ................................................................................................................................................... 4
Order Requirements ..................................................................................................................................... 4
Executive Summary ....................................................................................................................................... 4
Summary of Content ..................................................................................................................................... 5
DTE Presented Content ............................................................................................................................. 5
Third Party Presented Content ..................................................................................................................... 5
EPRI ........................................................................................................................................................... 5
Vendor Presented Content ....................................................................................................................... 6
Anchor Power: Encompass ................................................................................................................... 6
Energy Exemplar: Plexos ....................................................................................................................... 6
Energy Exemplar: Aurora ...................................................................................................................... 6
ABB: Capacity Expansion ....................................................................................................................... 7
Utility Discussion ........................................................................................................................................... 7
Consumers Energy ................................................................................................................................ 7
Xcel Energy ............................................................................................................................................ 7
UPPCO Energy ....................................................................................................................................... 7
DTE ........................................................................................................................................................ 8
Q&A transcript ............................................................................................................................................ 10
Introductions Day 1 ................................................................................................................................. 10
DTE introduction, Laura Mikulan ............................................................................................................ 10
EPRI Presentation, Nidhi Santen ............................................................................................................. 12
Encompass Presentation, Norm Richardson ........................................................................................... 12
Plexos Presentation, Charles Graf, Chuck Fan, Harika Kuppa ................................................................. 13
Stakeholder roundtable .......................................................................................................................... 14
ABB Presentation, Eric Hughes ............................................................................................................... 15
Aurora Presentation, Charles Graf, Chuck Fan, Harika Kuppa ................................................................ 17
Utility Approach ...................................................................................................................................... 18
Consumers Energy .............................................................................................................................. 18
Xcel Energy .......................................................................................................................................... 19
UPPCO ................................................................................................................................................. 20
DTE ...................................................................................................................................................... 20
Closing remarks ....................................................................................................................................... 20
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Stakeholder Follow Up Comments received by email ............................................................................ 22
MPSC Staff ........................................................................................................................................... 22
ELPC, et al ............................................................................................................................................ 22
Stakeholder Follow Up Comments received verbally ............................................................................. 22
DTE Response .......................................................................................................................................... 23
Attendee List ............................................................................................................................................... 24
Appendix ..................................................................................................................................................... 25
Day 1 Slides ............................................................................................................................................. 25
EPRI: Energy Systems Modeling for Integrated Resource Planning .................................................... 34
Anchor Power: Encompass ................................................................................................................. 39
Energy Exemplar: Plexos ..................................................................................................................... 53
Day 2 Slides ............................................................................................................................................. 68
ABB: Capacity Expansion ..................................................................................................................... 78
Energy Exemplar: Aurora .................................................................................................................... 84
Attachments ................................................................................................................................................ 91
Attachment 1: Comments from MPSC Staff ........................................................................................... 91
Attachment 2: Comments from ELPC, Earthjustice; The Ecology Center; The Environmental Law & Policy Center; The Michigan Environmental Council; The Natural Resources Defense Council; The Sierra Club; Solar Energy Industries Association; the Union of Concerned Scientists, and; Vote Solar . 93
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Background DTE Electric (DTE or the Company) filed case U-20471, the 2019 Integrated Resource Plan (IRP), on March 29, 2019, with the Michigan Public Service Commission (MPSC). An interim order in this case was issued from the MPSC on February 20, 2020. The Company then filed a pleading accepting the Commission’s changes to the IRP on March 20, 2020. The MPSC’s final order on the IRP in Case U-20471 was issued on April 15, 2020. Among the recommendations in the order, DTE was required to host a two-day technical conference discussing IRP modeling software programs.
Order Requirements The final order from Case No. U-20417 stated the following: “Within 90 days from the date of this order, DTE Electric Company shall convene a technical conference with interested stakeholders for the purpose of identifying and evaluating alternative modeling software for use in developing integrated resource plans, and shall, within 120 days from the date of this order, file a report on the results of the conference in this docket.”
Executive Summary DTE Energy hosted a two-day software collaborative on May 11 and May 12, 2020. The collaborative was scheduled from 9:00am to 12:30pm each day. Due to the stay at home orders in effect at the time, the collaborative was hosted virtually on Microsoft Teams. All attendees were sent copies of the slides presented.
Attendees included the following:
• Michigan Public Service Commission Staff • Stakeholders in DTE Energy’s most recent IRP case including Michigan Environmental Council
(MEC), Environment, Law and Policy Center (ELPC), and Environment, Great Lakes and Energy (EGLE)
• Employees of Michigan utilities including Consumers Energy, Upper Peninsula Power Company (UPPCO), and Xcel Energy (Northern States Power-Wisconsin, serving 10,000 customers in the Upper Peninsula)
• Software vendor representatives from Energy Exemplar, ABB, and Anchor Power • Representative from Electric Power Research Institute (EPRI), an independent, nonprofit
organization for public interest energy and environmental research focusing on electricity generation, delivery, and use in collaboration with the electricity sector, its stakeholders and others to enhance the quality of life by making electric power safe, reliable, affordable, and environmentally responsible
Please refer to the detailed attendance list included in a later section.
DTE Electric greatly appreciated the input from all parties over the two days and the subsequent follow up communications. DTE Electric, Software suppliers, and Michigan stakeholders had an open robust dialogue that will inform our final selection of a new IRP modeling software. The next steps for the Company are as follows:
• File this report on the collaborative with MPSC on or before June 19
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• Incorporate stakeholder’s feedback into our model selection approach • Finalize the model selection • Review the criteria and selection with Staff and intervenor parties • Begin transitioning to new modeling tool in September • File the next IRP by September 1, 2023 using this new modeling software
Summary of Content DTE Presented Content Laura Mikulan, Manager IRP, presented an overview of IRP modeling, the nine software programs considered by DTE Electric, and how the nine were narrowed to four software programs. The four modeling software programs are: Plexos, Aurora, Encompass, and Capacity Expansion. She also presented a list of 33 attributes that DTE is considering in a new IRP model. These were categorized into five categories: 1) Model Capabilities, 2) Model Transparency, 3) Functionality, 4) Value and IRP process efficiency, and 5) Nice to Have. Model Capabilities and Model Transparency were discussed in more detail. See Day 1 Deck, slides 8-10 for more detail. A question and answer period followed. The questions covered the topics of Chronological modeling, server use, consistency between utilities, model testing, and next steps. For details on the Q&A, please refer to Q&A transcript starting on page 10.
Third Party Presented Content EPRI Nidhi Santen, Ph.D. from EPRI’s Energy Systems and Climate Analysis group, presented, “Energy Systems Modeling for Integrated Resource Planning: Modeling Considerations & Challenges.” She provided an overview of challenges that arise while planning and modeling an electric power system like in an integrated resource plan. The eight challenges presented include:
1. Representing Time, requires high temporal granularity to represent storage, renewables, demand side management, and ancillary markets
2. Representing Space, pertaining to modeling of the transmission network and environmental policies
3. Representing Uncertainty; how to capture dynamic technical changes, planning goals, and market design with a deterministic model
4. Representing End-Use, modeling efficiency-enhancing opportunities and feedbacks between consumer behaviors and electric loads
5. Representing Emerging Technologies and Technological Change, or the unknown pace of technology advances in terms of performance and costs
6. Representing Changes in Energy Markets and Energy Market Design; emerging technologies specifically may require new market designs
7. Representing Expanding System Boundaries, including, distribution as well as non-energy sector systems (e.g. natural gas, water, transportation)
8. Representing Multiple Goals and Objectives, or planning beyond simply minimizing cost – including, goals for environment, resiliency, and consumer choice
Additional considerations for IRP modeling include:
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1. All modeling – including IRP modeling – is a balancing act, tradeoffs between model simplifications 2. Good IRP modeling finds balance between model fidelity and model tractability for the specific
questions and systems being studied 3. IRP models do not provide forecasts 4. IRP modeling is about decision-support, not decision-making
Follow up questions included more discussion on capturing changes to market design and Resource Adequacy (RA) constructs in IRP models. For details on the Q&A, please refer to Q&A transcript starting on page 10.
Vendor Presented Content Anchor Power: Encompass Norm Richardson, President of Anchor Power, joined us for a presentation of the Encompass software. Encompass is a single optimization model that can be used for Integrated Resource Planning, Market Price Forecasting, and Detailed Production Costs & Risk Analysis. For the purposes of our collaborative, Norm described how Encompass is used for an IRP. He went over the different costs that could be modeled as well as other parameters such as ancillary services and storage. The automatic capacity expansion feature within the model was explained, as well as the typical day options included in the model. Follow up questions included questions on output files and intervener licenses. For details on the Q&A, please refer to Q&A transcript starting on page 10.
Energy Exemplar: Plexos Three speakers from Energy Exemplar, Charles Graf, Senior Sales Executive, Chuck Fan, Director of Implementation and Harika Kuppa, Senior Energy Market Analyst, presented on the Plexos software. The presentation included an overview of Energy Exemplar, which provides customer support, training, implementation, Sim-ready datasets and software platforms. There was also an overview on Plexos and how it can integrate short-and long-term analysis through its long-term integrated resource planning, medium term planning and short-term operations.
During the Q&A section, several questions were asked about Plexos related to exporting input files, load duration vs. chronological, decreasing capital costs, and intervener license costs. For details on the Q&A, please refer to Q&A transcript starting on page 10.
Energy Exemplar: Aurora Three speakers from Energy Exemplar, Charles Graf, Senior Sales Executive, Chuck Fan, Director of Implementation and Harika Kuppa, Senior Energy Market Analyst presented on the Aurora software. The presentation included an overview of Energy Exemplar which provides customer support, training, implementation, Sim-ready datasets and software platforms. There was also an overview on the Aurora model, including an explanation on nodal and zonal capabilities as well as the long-term capacity expansion features, and a breakdown of run times for various studies.
Several questions were asked about Aurora. The subjects included modeling of ancillary services, user manual accessibility, and unit commitments. For details on the Q&A, please refer to Q&A transcript starting on page 10.
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ABB: Capacity Expansion Eric Hughes, Product Manager from ABB, presented on the Capacity Expansion software. This presentation included a model overview and indicated Capacity Expansion attributes that meet DTE Energy’s must have list. Additional features of the software were discussed including Renewable Portfolio Standards (RPS) modeling, Renewable Energy Credit (REC) modeling and Demand Side Management (DSM) modeling enhancements.
During the Q&A section, several questions were asked about ABB Capacity Expansion on the subjects of storage, model modes, Linear programming vs. Mixed integer linear programming, exporting input files, and intervener license costs. For details on the Q&A, please refer to Q&A transcript starting on page 10.
Utility Discussion During the collaborative, representatives from Consumers Energy, UPPCO, Xcel Energy, and DTE Energy spoke to the group about their experiences with selecting new modeling software.
Consumers Energy Sara Walz, Senior Engineering Technical Analyst Lead and Anna Munie, Senior Engineering Technical Analyst II from Consumers Energy provided an overview of their selection process. Consumer’s Energy had previously used the Strategist software for their IRP modeling but have recently switched to the Aurora software. Sara and Anna discussed their proposal process for selecting new modeling software, the scoring criteria used for the software selection, why they decided to select Aurora over other modeling programs, and their experiences to date using Aurora software. For details on the Q&A, please refer to Q&A transcript starting on page 10.
Xcel Energy Jon Landrum, Manager, Resource Planning Analytics, from Xcel Energy then spoke about his experience. Like Consumers, Xcel previously used Strategist as their primary modeling software. Xcel worked with a consortium of utilities in the area which sent a Request for Information (RFI) to 18 software vendors. 11 modeling companies responded and then the list was further narrowed down to Plexos, Aurora, Encompass, and Capacity Expansion, similar to DTE. Eventually, Xcel selected the Encompass software. Jon stated one of the biggest factors in deciding to go with Encompass instead of Aurora was because at the time Encompass was able to model a capital revenue requirement, which they used for internal strategic planning and looking at earnings. For details on the Q&A, please refer to Q&A transcript starting on page 10.
UPPCO Energy Eric Stocking, Manager – Rates & Power Supply from UPPCO then shared the company’s modeling experiences. Due to resource constraints, UPPCO hired an outside consultant to perform its IRP modeling. The consultant used both the PROMOD and Plexos modeling platforms. PROMOD was used for the hourly MISO market simulation and Plexos was used for capacity expansion. The main thing UPPCO was looking for when selecting a consultant, was one that used a sophisticated risk analysis tool. The UPPCO system is driven by energy needs much more than capacity needs. UPPCO currently purchases a significant portion of the energy it delivers to its retail customers from the MISO market. For its next IRP, UPPCO will be actively evaluating whether to bring some of the modeling in-house, or to hire a consultant again.
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DTE Dwain Shelby, Senior Engineer, discussed how DTE has narrowed down the selection process from nine software platforms to four: Aurora and Plexos by Energy Exemplar, Capacity Expansion by ABB, and Encompass by Anchor Power Solutions. See Day 2 Deck, slides 10-12 for more details.
Dwain then spoke about the timeline that DTE expects to follow for the selection of the new model, specifically:
• January to May 2020: Evaluate the different software platforms and narrow down the selection to four modeling platforms. Once these final programs were selected, training sessions were then held by each vendor for each model. This was followed by access to a trial version for independent use, each lasting at least a month
• April to June 2020: Engage with stakeholders and other utilities. This includes benchmarking conversations with other utilities that use at least one of the four software platforms being considered. These conversations provide a more in-depth view of their selection process, modeling experience, and any learnings to consider
• July 2020: Select the new software platform • August 2020: Negotiate the terms of the purchase, as well as gain senior management support • September 2020: Purchase the modeling software • September to October 2020: Transfer the data from the old model to the new model • October to December 2020: Participate in additional training necessary to use the new modeling
software • November 2020 to February 2021: Benchmark and validate the results of the new model to the
detailed dispatch model, PROMOD. • December 2020 to January 2021: Design and implement processes for data input and output
reports that will be needed for the new software • This will all culminate in a final anticipated switch over date to the new model by March 2021.
Next, David Oupicky, Senior Engineer, spoke about the approach that will be used to select the new software. The approach discussed was a quantitative decision theory approach called the weighted sum model (WSM). Feedback from this collaboration will also be taken into consideration in the decision-making process.
David also described the steps that have already been taken and those that will be taken as a part of this decision-making approach:
• Four initial software trials were completed in order to obtain a good understanding of each model's attributes
• Five modelers participated in each software trial • Based on feedback from this collaboration, further evaluation may be necessary to gain additional
information for consideration in the ranking process • A consensus weighting will be determined for each criterion with input from IRP team • A consensus score is reached for each criterion based on individual modeler scores for every
software alternative between 0 and 5 • The individual criterion scores for each software alternative are summed to give a final score • The final scores are ranked in descending order to determine the final model rankings
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Lastly, David discussed the next steps after the collaborative, which are listed below:
• File a report on this collaborative with MPSC on or before June 19 • Incorporate stakeholder’s feedback into our model selection approach • Finalize the model selection • Begin transitioning to new modeling tool in September • File the next IRP by September 1, 2023 using this new modeling software
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Q&A transcript A transcript was made of the discussion between participants that were not part of the prepared remarks. The transcript was edited for relevancy and clarity from the recording of the meeting.
Introductions Day 1 Statement by Margarethe Kearney (ELPC, The Ecology Center, Vote Solar, The Union of Concerned Scientists, MEC, NRDC, Sierra Club):
1. Model must be transparent. Must be possible for interveners to see all model settings and switches, inputs such as market prices, and all outputs the model produces. Interveners must have access to the model's user guide. Each vendor to provide specific on outputs and setting and manuals to intervenors including the format in which the outputs would be exported. Access to some but not all of those data items leaves the Commission and interveners with what is equivalent to one arm tied behind our backs.
2. Model must be licensable and affordable if DTE does not provide the licenses. It would be valuable to know the cost of the fee, and level of support given by the vendors.
3. Model must represent all resource types and load in a manner that is consistent with how they function, how they change over time, e.g., battery state of charge should be representative of real-world operations, and the shape of load should be capable of changing over time as electrification increases
Those are just three big picture issues that we wanted to put forward at the very beginning. These issues are common to all these groups and that’s the lens through which we’re looking at this. I also wanted to reiterate that we’re really excited that you put together these two meetings. Thank you very much for doing it and we really look forward to hearing from some of the software vendors.
DTE introduction, Laura Mikulan Q. What did you mean on slides #8 and #5 about a chronological model? Can you explain the term chronological model a little more? (Julie Baldwin, MPSC Staff)
A. A chronological model actually models hourly. Sometimes it’s 8760 hours per year and sometimes it can be less than that if you’re using an extracted [abbreviated] time scale, such as typical week or fewer hours or days. Load duration curve was used in the Strategist models and was used in some other models as well. A chronological model does it more granularly and you get a lot more detail than if you use that simplification. (Laura Mikulan, DTE)
Q. The Utility Public Service Company of New Mexico [PSCNM] negotiated a reduced cost for the intervener licenses for Encompass because the model was run off the utility’s server, so Anchor Power didn’t have to deal with the set-up time. For example, we ran Encompass for [a low amount] over the duration of the case period, which is a lot less than you would normally pay for it. You said that you’d rather not have a cloud-based model, but I wondered if that type of arrangement was something that you had considered to provide those licenses cheaper to the interveners? (Anna Sommer, Energy Futures Group/ELPC et al.)
A. We are still open to having a server; it’s kind of a drawback to us now. But having a server affects the total cost, and we’re considering DTE’s costs as well as Stakeholder costs. There are
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costs associated with having a server that we need to consider. We’re still getting quotes from the various suppliers, and costs of Stakeholder licenses is definitely going to be a big factor in that. (Laura Mikulan, DTE)
Q. You mentioned the user group and who else has used it or licensed it. Would you also provide more specifics on what the other utilities in the State are using? (Will Kenworthy, Vote Solar)
A. We are definitely curious on what the other utilities are using; we’ve talked to several of them about the different models they use. I don’t think the goal is really to get everyone using the same model. Each utility has to pick the model that works best for them. (Laura Mikulan, DTE)
Q. In Minnesota the Commission actually selected it. They focused all the utilities on the same piece of software, and I think it was a big help. It has been a big help for the utilities, the stakeholders and the Commission to have a consistent application. (Will Kenworthy, Vote Solar)
A. Tomorrow we will hear from the other utilities in Michigan and which models they have chosen as well. (Laura Mikulan, DTE)
Q. How does DTE envision this process going after the conclusion of these presentations? Are you going to test drive any of these models? Have you already tested them? What other interactions with interveners do you anticipate during the selection process? (Anna Sommer, Energy Futures Group/ELPC et al.)
A. We have had trials with these four that are going to be presenting today or tomorrow. These have been month long trials, so we’ve really gotten to kick the tires of these models and really get into the inner workings of them. As far as next steps, we will be filing our report with the Commission in June, so that’s our next step. (Laura Mikulan, DTE)
Q. What is the report that’s being filed in June? (Anna Sommer, Energy Futures Group/ELPC et al.)
A. It’s a report on this collaborative as part of the IRP order, we were to hold the collaborative and then file a report 120 days after the order. (Laura Mikulan, DTE)
Q. At that point you’ll be ready to select the next IRP model? (Anna Sommer, Energy Futures Group/ELPC et al.)
A. I anticipate we’ll be making our decision after we incorporate all feedback from this collaborative, so the report will be filed in June and then the selection will be finalized in July. (Laura Mikulan, DTE)
Q. Which model does Gen Ops use right now? (Anna Sommer, Energy Futures Group/ELPC et al.)
A. They’ve used PROMOD and they’re switching over to Portfolio Optimization. Portfolio optimization will not be used for IRPs build plan generation. (Laura Mikulan, DTE)
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Q. Does ABB’s presentation tomorrow relate to the full E7 suite? Or is that in relation to their Capacity Expansion model that replaces system optimizer and Strategist? (Anna Sommer, Energy Futures Group/ELPC et al.)
A. The Company is already licensing Portfolio Optimization with the Gen Ops group. If we went with Capacity Expansion, we would be plugged in with the Portfolio Optimization model as well. (Laura Mikulan, DTE)
Q. Are you doing some sort of benchmark against actual system results in order to verify that they follow your system properly? (George Evans – Sierra Club and EarthJustice)
A. We haven’t gotten that far. I think you’re talking about doing some sort of back casting. I anticipate we’ll be doing that once we narrow the focus down from four models to two, then we’ll do a more in-depth benchmark at that time. (Laura Mikulan, DTE)
EPRI Presentation, Nidhi Santen Q. When you described market design changes in slide 20, were you talking about optimization across distribution and generation systems? If so, how would that influence the selection of a modeling platform? (Anna Sommer, Energy Futures Group/ELPC et al.)
A. I was thinking along the lines of bulk system planning but addressing the distribution system operations and the bulk system is fair game for assessment. There are a lot of changes happening right now in ISOs with regards to how the resources themselves are going to be able to participate and what market services they’re going to be able to participate in the bulk system process. Many models now are not flexible in being able to test that feature of a changing market. (Nidhi Santen, EPRI)
Q. If a system like MISO moved from a PRM type RA construct to something else, do you think most models would be able to accommodate a different way of looking at resource adequacy as a constraint on optimization? (Anna Sommer, Energy Futures Group/ELPC et al.)
A. I think that most models are not going to be able to change easily without additional model development to change their construct of how they’re considering resource adequacy. There certainly are models out there that can do that, and I think that it’s going to be dependent upon what is specifically needed in an individual market. It’s not super common to be able to design entirely new energy market modeling frameworks within models themselves, but I think that some of the modeling I’ve seen, particularly in PJM, MISO regions, the models do an adequate job doing so. (Nidhi Santen, EPRI)
Encompass Presentation, Norm Richardson Q. Regarding output files, what’s shareable and exportable? (Will Kenworthy, Vote Solar)
A. The output results would include any level of detail. When you export outputs from Encompass, you choose the level of both geographically. So, whether it’s an individual unit level or rolled up to an area balancing authority, a system level, or a company level, then you can also specify whether that should be rolled up from a time perspective at an annual level, a monthly level, or interval. A resource interval report would include things like available capacity generation, ancillary services, charging for battery storage levels. Reports can be incredibly
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detailed and then get very large, or they can be actually created as separate sheets within a single workbook and then that workbook can be shared with anyone. (Norm Richardson, Anchor Power)
Q. What are the circumstances under which Encompass was used in the recent Public Service Company of New Mexico Case? PSCNM told us that it was paying Anchor [a low amount] for each intervening license to use for the duration of the case. Under what circumstances could a similar arrangement be made for a DTE IRP? (Anna Sommer, Energy Futures Group/ELPC et al.)
A. Should DTE choose Encompass a similar arrangement can be made as well. PSCNM kind of had that specific type of request for being able to specify a single virtual machine be made available to interveners for that price. That same thing would be available to DTE. In addition, there are project-based licenses that are available for Encompass. Consulting firms are primarily used to represent intervening parties, so these are very reasonable types of price perspective to be able to license it for a particular project on a monthly basis and then on a weekly basis after the first month. (Norm Richardson, Anchor Power)
Plexos Presentation, Charles Graf, Chuck Fan, Harika Kuppa Q. We’ve seen Plexos used primarily as a production costing tool. I suspect that’s what most of the users that you mentioned earlier in the presentation were licensing it for, but we’ve seen a couple of instances in which it was used as an IRP model which LT plan was used.
a. Is it possible to export the input files, including the setting and switches applied to the model or to export the manual or edit Plexos without a license? Read only or otherwise.
b. Can LTP do both LDC and chronological sampling of time? I’m told for reasons that I’m not clear about that it is really difficult to do something other than LDC dispatch.
c. Regarding capital costs on new resources. Is there an issue with modeling declining capital costs for new resources? Refers to some sort of spreadsheet back in calculation to upload the build cost into Plexos. (Anna Sommer, Energy Futures Group/ELPC et al.)
A. Response:
a. Looking at the settings without the model without having a license. I believe we can work out some sort of arrangement where there can be the essential view only, but no execution for people to actually see what the setting in the system is and also what the data actually modeled.
b. For capital cost we can do load duration curve or we can do chronological constraint? We can do both. There is an issue that if you run very high level of detail, say for every hour or so for a capital plan going out for 20 years, it will be time consuming to run because the model fully optimizes across the entire horizon in long term capacity expansion so it doesn’t chop up the long-term year segments. It’s actually optimizing over the whole thing it knows when to build everything. So, I think the main issue people run into is if you want extremely high degree of optimality then it will take it. There will be run time demands for that. Typically, we don’t necessarily run it every hour because for even with chronological constraint there’s no reason to assume that 20 years in the future every hour will the literally different.
c. We can model declining capital cost. [We] can also model improving resource efficiency so you can model, for example, a wind turbine with decreasing capital cost of a $/MWH
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basis and increasing, say, capacity factor for a given installed MW base. As far as I know, there is no reason why there has to be a work around. They could be modeled explicitly using the actual data. (Chuck Fan, Energy Exemplar)
Q. (Comment) If there is a cost for the read only license, somebody has to incur that. Concerned about the interveners having to pay to see the modeling data. (Anna Sommer, Energy Futures Group/ELPC et al.)
Q. One of the IRPs I worked on uses LDC and they said that they can’t do chronological sampling. Why would that be? (Anna Sommer, Energy Futures Group/ELPC et al.)
A. I do not know. We actually are doing capacity expansion planning with a chronological standpoint. (Chuck Fan, Energy Exemplar)
Stakeholder roundtable Q. (Comment) How does the list of attributes apply to the transparency qualities of a model? Are those things deal breakers? If for example, stakeholders cannot get access to the manual except for the read only license, will that be a deal breaker? (Anna Sommer, Energy Futures Group/ELPC et al.) Q. Want to get a better sense of whether there is perhaps a disconnect between the things that the model is technically capable of doing and whether it is actually capable of doing those things in practice, as I sure you guys know, you can put a lot of bells and whistles into the models but you can’t necessarily use them all simultaneously. And I’ve seen some odd results out of Plexos LT plan before. I just want to put that caution up there to make sure that you really vet its capacity expansion capabilities if you’re leaning toward that model. It’s a great production costing tool, I’m just not sure about it as a capacity expansion model. (Anna Sommer, Energy Futures Group/ELPC et al.) A. That is one of our concerns as well that we have when we’re doing these extensive trials with the model. The vendors can come in and say “Oh it’s going to do X, Y, and Z,” and then it’s a different story entirely. If we can make it do those same things so that is definitely part of our process. (Laura Mikulan, DTE) Q. One of my concerns is the modeling of renewables, and if we’re able to have inputs over time for reductions in costs, increases in capacity factors and the capacity credit – ELCC. In the last IRP those are the sorts of problems that there were known changes in those over time but those were difficult to model so I want to make sure we capture this correctly. (John Richter, GLREA) A. You want to ensure the model can handle changes in capacity over time, capacity factor, capital cost and the ELCC? So, this would encompass the degradation of solar units and decreasing capital costs, things like that. (Laura Mikulan, DTE) Q. Yes. I think some of that got averaged in the last round because the model wouldn’t enable that. (John Richter, GLREA)
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A. Yes this is already on our list; being able to handle decreasing escalation rates as well as different escalation rates each year. (Laura Mikulan, DTE) Q. Do we know how many clients Encompass currently has? I heard Plexos people say 300 but I never heard anything from Encompass. (George Evans – Sierra Club and EarthJustice) A. We will follow up and get the total number. (from follow up with Norm Richardson, Anchor Power: 19 clients, 12 utilities) (Laura Mikulan, DTE) Q. The other question I had was about Aurora vs. Plexos. In some conversations I’ve had with the Energy Exemplar folks they indicated to me that long term they want to get all their clients using Plexos and move away from Aurora in the future. I don’t know how long it is and maybe that’s not even true, but I don’t know if you had heard anything about that. (George Evans – Sierra Club and EarthJustice) A. So that’s funny because we’ve asked them the same thing because we’re evaluating both Aurora and Plexos. They’ve told us that they intend to keep both models around for a while because they have customers using both. So, that is the information that we were given. (Laura Mikulan, DTE) Q. (Comment) Getting things out of Plexos seems overly complicated. (George Evans – Sierra Club and EarthJustice) A. They will be presenting tomorrow so there is another opportunity to ask them as well. (Joyce Leslie, DTE)
ABB Presentation, Eric Hughes Q. Does the modeling software have the capability to include other capabilities of storage other than power storage like system peak shaving? For example, lots of times we look only at the bulk storage of energy shifting time and there’s other capabilities that storage have that can have great impacts on the grid specifically peak shaving where you set a certain amount of that storage to do just one thing like peak shaving. (Rob Rafson, Charthouse/GLREA)
A. Since the dispatch of storage resources is shifting from generally lower cost time periods to higher cost time periods, it is sort of automatically doing that anyway – that’s the way the algorithm is written. It’s looking for the most economic changing vs. discharging for the system. Since those high cost hours almost always align with those peaks, and that’s where you want to use the energy. It’s doing peak shaving almost by default. The way it’s set up particularly when we’re talking about the battery resources that can charge during the middle of the day, for example from PV and then discharge in the late afternoon – early evening during the peaking times. Now could we potentially set this up so that it can only dispatch during those time periods? I suppose that is something that is doable within the model, but it would sort of limit the charging cycle, particularly for a battery. (Eric Hughes, ABB)
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Q. The choice of optimization modes, can you explain that? (George Evans – Sierra Club and EarthJustice)
A. You can you run it in LP mode, which is pure linear program. Linear programming is the theoretic. You get the optimal answer from an LP. That is the theoretical optimal answer because it allows the model to take all of the resources and take slices of those resources to exactly fit the need. Mixed integer programming obviously adds additional constraints, so it can only take a whole resource or none at all in any one year. So, if it builds the resource, it builds it in its entirety, so it doesn’t take a slice of the resource. The final mode, the DSM evaluation mode is kind of a hybridization where we’re looking at the DSM programs in total, so you put the whole program in, but you allow the selection of other resources in LP mode to get to an exact fit for the minimum reserve margin. It can then calculate appropriately the capacity cost savings from those resource slices that didn’t get built. That’s kind of the way the DSM evaluation works but it obviously is then dispatching the resulting resources against the change load resulting from the DSM evaluation and then it calculates those benefits and costs using the California standard practice manual benefit cost ratios for DSM evaluation. (Eric Hughes, ABB)
Q. It gets the benefits of the DSM plan? (George Evans – Sierra Club and EarthJustice)
A. It gets those benefits and costs so you can calculate those appropriate B-C ratios, and those are very common for DSM evaluation. And was something that I felt was necessary because I don’t see anybody else doing it. (Eric Hughes, ABB)
Q. What I don’t understand is LP (linear programming) doesn’t give you an expansion plan? (George Evans – Sierra Club and EarthJustice)
A. No. It gives what I would call a perfect fit for that. Looking at the LP, say I need X MWs of this type of resource and Y MWs of that resource. It gave me my perfect plan that fits exactly and minimizes my result. That would be a statement of perfect need. Verses what you get from the mixed integer program, which is a practical buildout plan because, it takes whole resources exactly. I would always run the LP first while I’m developing my data to make sure everything is going to run because the LP has to be solved first in order to get a mixed integer result. The mixed integer result is trying to get within a user defined tolerance range of that answer from the LP because that is the theoretical optimal answer. The MILP is the first answer that we find that comes honoring the mixed integer portion of taking whole resources that falls within that tolerance range of the theoretical answer from the LP. All MILPs work this way. They all have to. (Eric Hughes, ABB)
Q. In terms of transparency, in being able to extract information out of the model, can you talk a bit about the format in which input and output data can be extracted, and also whether the model enables the expectation of all of the settings and switches that a modeler can enable for any given run? (Anna Sommer, Energy Futures Group/ELPC et al.)
A. Underlying, capacity expansion uses a SQL database. All that data of course can be addressed via query, but from within the model you can of course set up views of the data that then can be exported so that you can look at the export data. Now data can be imported in mass to Capacity Expansion using several different formats that are essentially flat files that can be generated from
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excel in CSV format. We can also read data from other places into the model and into the database using APIs. On the export side, that data that we can sort through all of that in reverse. We can push things out to Excel. We can push them to external databases and all of this can be automated from within the model so that you’re executing an activity that does of this. So yes, all of the input and output data can be exported from the model so you can see it. (Eric Hughes, ABB)
Q. Including flags and settings? (Anna Sommer, Energy Futures Group/ELPC et al.)
A. Including flags and settings. Any input item and any output item can all be exported from the model. (Eric Hughes, ABB)
Q. Regarding licensing fees. We recently participated in a case in New Mexico where the utility provided access to the model for each of the interveners who wanted to perform their own runs. In this particular case the Commission obligated the utility to pay for that license, but the utility let us know how much each license would cost because there were actually three models in this case. The model in question for us was Encompass and the utility had to pay [a low amount] for each model license for each intervenor and that was a significant discount relative to the normal licensing fee for Encompass and I gather that it had to do with the fact that the utility was licensing Encompass itself. It had already paid the sort of full licensing fee and I wondered whether ABB had thought about that type of licensing arrangement as a way to deal with cost related issues. That if you’re using a project license and a case in which a utility itself is already licensing E7, whether the license fee could be discounted to permit other interveners to be able to use the model as well. (Anna Sommer, Energy Futures Group/ELPC et al.)
A. I’m fighting that good fight now. I’m advocating that we go ahead and if we’re going to allow utilities to license one seat that we do the same for interveners, to get it down to that would be about the price ranges that you’re talking about here. If we were finally able to get them to do that, I don’t see any reason we shouldn’t, particularly if we’re doing the way you’ve described where it’s being done under the auspices of the utility customer. My management is supporting me in this, so we’re elevating this at this point in time, but that is something I have thought about very much. And after winning the fight on the number of seats, now I’m pushing this one. (Eric Hughes, ABB)
Aurora Presentation, Charles Graf, Chuck Fan, Harika Kuppa Q. Could you compare and contrast Plexos and Aurora’s ability to simulate ancillary services? (Zach Heidemann, MPSC Staff)
A. Both Aurora and Plexos are able to define specific ancillary service markets and also define specific qualifications of the ancillary service, for example, what resources can meet a particular ancillary service – how much of it can meet ancillary service. Both models can do it based on the fundamental capability of the resource as far as ramping goes, in addition to arbitrarily define that a certain resource can contribute a certain amount. Both tools can co-optimize ancillary services with energy. For nodal and zonal, both tools can operate in such a way that the ancillary service requirement is met and only from units that have the least impact on the total production costs in meeting the energy ancillary service. (Chuck Fan, Energy Exemplar)
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Q. Is the Aurora manual only available within the model, meaning some sort of license fee would have to be paid to have access to the manual? Along with that, are there any project-based licenses? (Anna Sommer, Energy Futures Group/ELPC et al.)
A. Yes there are operating license options. As far as help goes, our help is in Robo help and it’s a HTML version. There have been CHN versions that were stand-along versions in the past. Generally speaking, on help, there is so much documentation beyond just what the file with the column input is. It contains a lot of our IP addresses and information we don’t want to get out unless there is a license or NDA in place, we typically like to keep those two things together. In terms of transparency, we want anyone supporting a utility or intervenor on a case we want to provide access. (Chuck Fan, Energy Exemplar)
Q. Can you talk about the pros and cons of the different approached between how Aurora and Plexos handle unit commitments? (Anna Sommer, Energy Futures Group/ELPC et al.)
A. Aurora doesn’t have a separate algorithm to abstract away unit commitments in dispatch then have an algorithm to determine what resource should be built at what time. What it does is takes the same unit commitment and dispatch in order to assess how that resource will perform and then use that to evaluate how to actually fulfill all the requirements of the portfolio and determine that for LTC and Portfolio Optimization. The thing that makes Plexos different is that Plexos takes the addition and removal of the unit into the same problem as the unit commitment in dispatch. (Chuck Fan, Energy Exemplar)
Utility Approach Consumers Energy Q. Are you able to optimize everything at one time in Aurora? (George Evans – Sierra Club and EarthJustice)
A. Our normal process, as it was with Strategist, is to layer everything in. We’ve done testing, but our formal optimizations won’t start until June. Our normal process is to layer in that way by the third step you’re offering the full menu and each step increases the complexity and runtime. But we fully expect to do what we call wide open runs offering all supply advanced options and that’s both for Consumer’s and the entire MISO footprint. We optimize for the entire footprint. (Sara Walz, CMS) Q. Was Aurora able to customize logic for your long-term contracts that were based prices of your own coal like in Strategist? (George Evans – Sierra Club and EarthJustice) A. Yes, that’s what I was primarily referring to when I talk about customization. We have some long-term power purchase agreements. A good number of them require customization, what they call portfolio contracts. We were able to incorporate those items that need customization working with the vendor. They actually created a new type of transaction specifically for us. (Sara Walz, CMS) Q. How/If you intend to use the LTC and portfolio optimization functions together and how that would work? (Anna Sommer, Energy Futures Group/ELPC et al.)
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A. We would expect to use the LTCE (long term capacity expansion) mode of operation for our IRP. I think it’s a yet to be determined on the portfolio optimization. We’re still evaluating that one. (Sara Walz, CMS) Q. How to you see exporting information to intervenors and access working on the Aurora platform? (Anna Sommer, Energy Futures Group/ELPC et al.) A. I can’t speak to how it would go, because we haven’t done it yet. We have already begun discussions with Energy Exemplar about the timing of when our stakeholders are going to need access to the model and the data, and they are fully aware of our expectations. We’ve started to do the paperwork even though we’re not filing for another year. We expect that to go a lot smoother and that was one piece of the process that we talked about with the vendors. (Sara Walz, CMS) Q. Does that mean that you’re intending on providing licenses to intervenors who would like to do their own Aurora runs? (Anna Sommer, Energy Futures Group/ELPC et al.) A. That is what happened in the 2018 IRP, we did provide those licenses. I don’t know that I could definitely say that will happen with the next IRP, but we do recognize the need for intervening parties to be able to do their own analysis with Aurora, so we need to be a part of that solution. (Sara Walz, CMS)
Xcel Energy Q. I assume you are modeling the whole system? (George Evans – Sierra Club and EarthJustice) A. Yes, we’re doing a two-step process, though, because with any of these MIP (mixed integer program) solvers you can’t really do a full 8760 capacity optimization for a 25-year study period. One of the other things we liked about Encompass was the variety of tools that were available to simplify the problem. Then you can turn off those simplifications to do a detailed 8760 production cost run. (Jon Landrum, Xcel) Q. How much time does it take to run your expansion plan optimization? (George Evans – Sierra Club and EarthJustice) A. It varies. We have a 9000 MW utility in the upper Midwest, and our capacity expansion runs will take anywhere from an hour to an hour and a half and we’ve had some long, complicated ones that take about 12 hours or so. (Jon Landrum, Xcel) Q. Is it true that none of these programs do a pure MIP? (George Evans – Sierra Club and EarthJustice) A. That is correct. What ends up happening is that first LP (linear program) doesn’t enforce things that have to be integers. Then the program goes back and finds the closest you can get to that
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perfect solution by enforcing real world nonlinearities and Encompass works the same way. (Jon Landrum, Xcel) Q. Do you envision using the two-way power flow capability in Encompass? If so, how might you use it? (Anna Sommer, Energy Futures Group/ELPC et al.) A. They are doing the nodal part of Encompass which is scheduled to be released very soon. We will probably use that some, but I think nodal has less application in resource planning. We will probably use that a little bit to do some testing, pricing and things like that. (Jon Landrum, Xcel)
UPPCO No questions were asked
DTE Q. Is the model that has the highest score the model that DTE will pick? (Anna Sommer, Energy Futures Group/ELPC et al.)
A. Yes that would be the process. We are trying to quantify our decision-making process and with that the highest score would be the one that we go with. (David Oupicky, DTE) Q. Will this scoring methodology be part of the filing in June or is this just for internal purposes? (Anna Sommer, Energy Futures Group/ELPC et al.) A. No, we are going to file the report in June and then finalize our own evaluation in the July timeframe and select a model. The scoring will not be finalized by the June report. (Laura Mikulan, DTE) Q. Am I correct in asking that DTE is asking for input on the criteria? (Anna Sommer, Energy Futures Group/ELPC et al.) A. Yes, we have the criteria that was presented earlier but we would like input on if that is good criteria to consider, and if there are any additional criteria that we should be looking at as we make our selection. We will take all your comments into consideration in our ranking. (Laura Mikulan, DTE)
Closing remarks Q. Is there any timeline/deadline of when you would need for feedback on the criteria to incorporate into this report? (Jon DeCooman, MPSC Staff) A. Feedback within the next two weeks; by the end of May would be great. (Laura Mikulan, DTE)
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Q. Is the goal of the formula used only to figure out which vendor to choose and model to use or will there be other conversations? (Margarethe Kearney, ELPC et al.) A. We know what’s important to us, but we just want to present our final decision in a transparent manner with some type of rigor around it. (Laura Mikulan, DTE)
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Stakeholder Follow Up Comments received by email MPSC Staff MPSC staff provided extensive comments concerning the collaborative. See attachment 1. In summary, Staff prioritizes selecting an IRP model with the following criteria:
• Chronological dispatch instead of load duration curve dispatch (#5) • Model’s ability to represent and capture the value of many different storage configurations (#6-
8) • Model Transparency (#10-#12) • Reduction of the number of software platforms (#18) • Having an Intuitive interface (#21) • High focus on model usability pertaining to straightforward error checking, and uncomplicated
data import and export (#27, #29, #33)
ELPC, et al ELPC sent compiled comments from:
Earthjustice; The Ecology Center; The Environmental Law & Policy Center; The Michigan Environmental Council; The Natural Resources Defense Council; The Sierra Club; Solar Energy Industries Association; the Union of Concerned Scientists, and; Vote Solar. See attachment 2.
To summarize,
1. DTE and the Environmental Intervenors are looking for many of the same attributes in DTE’s choice of modeling software, especially that DTE values transparency for Staff and intervenors.
2. Even if the weighting of the criteria will not be included in the June filing, it would be helpful to
see DTE’s assessment of how each of the models stack up against that criteria and would appreciate a matrix of how each model aligns with the Company’s criteria.
3. Environmental Intervenors’ primary concern is ensuring transparency from whatever model DTE
moves to. We would appreciate that for any of the vendors DTE has not yet ruled out, DTE request the certain information and provide it to stakeholders.
4. Request that DTE provide an opportunity for additional feedback from stakeholders following
receipt of transparency information, and that DTE offer opportunities for more detailed conversations about the characteristics of the lesser-known models if DTE is not ready to rule out one or more of these platforms.
Stakeholder Follow Up Comments received verbally After the modeling collaboration, we reached out to both George Evans (Sierra Club and Earth Justice) and Anna Sommers (Energy Futures group/ELPC et al.) to propose a more in-depth discussion based on their hands-on experience with the proposed models still in contention. The IRP team had a phone conversation with Anna Sommer on May 19th regarding her experiences which primarily focused on the Plexos and Encompass models and their specific characteristics. George Evans responded that he didn’t have any additional insights to share on Plexos and Encompass. This feedback will also be taken into consideration.
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DTE Response The Company responds to the follow up comments as follows: We appreciate the additional input provided by both ELPC, et al. and the MPSC Staff. DTE intends to be transparent with the model selection weighting and criteria rankings and will be setting up a review session to discuss the final model selection with Staff and intervenors. Regarding Staff’s input on the suggested prioritization of the model attributes, we agree with the significance and will ensure that our weightings consider their specified attributes among the highest in their respective categories. We agree that some of the criteria are Yes or No answers and the selection matrix will reflect this. We anticipate scheduling a DTE Electric IRP model selection review session this July or August. To the extent that the details of the model selection can be shared, while maintaining Company sensitive information such as vendor pricing information, we will do so at this session. In addition, we have reached out to the vendors still being considered requesting information pertaining to the transparency request included in the letter from ELPC. This information will be shared at the upcoming review session. Feedback regarding the model transparency information can also be provided at this session.
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Attendee List
Invited Stakeholder Group Attended?
ABATE (ASSOCIATION OF BUSINESSES ADVOCATING TARIFF EQUITY) No
Advanced Energy Economy (AEE) No
American Wind Energy Association (AWEA) No
Attorney General No
Chart House Energy Yes
City of Ann Arbor No
Clean Grid Alliance Yes
Consumers Energy Yes
Ecology Center Yes
Environment, Great Lakes and Energy (EGLE) Yes
Energy Michigan No
ELPC Environmental Law and Policy Center Yes
Great Lakes Renewable Energy Association (GLREA) Yes
ITC Yes
League of Conservation Voters No
Michigan Environmental Council (MEC) Yes
Michigan Electric & Gas Association (MEGA) Yes
Natural Resources Defense Council (NRDC) Yes
Residential Customer Group No
Sierra Club Yes
Solar Energy Industries Association No
MPSC Staff Yes
Vote Solar Yes
5Lakes Yes
Michigan Energy Innovation Business Council (MEIBC) No
Soulardarity No
Upper Peninsula Power Co. (UPPCO) Yes
Xcel Energy Yes
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Appendix Day 1 Slides
26
27
28
29
30
31
32
33
34
EPRI: Energy Systems Modeling for Integrated Resource Planning
35
36
37
38
39
Anchor Power: Encompass
40
41
42
43
44
45
46
47
48
49
50
51
52
53
Energy Exemplar: Plexos
54
55
56
57
58
59
60
61
62
63
64
65
66
67
68
Day 2 Slides
69
70
71
72
73
74
75
76
77
78
ABB: Capacity Expansion
79
80
81
82
83
84
Energy Exemplar: Aurora
85
86
87
88
89
90
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Attachments Attachment 1: Comments from MPSC Staff
May 28, 2020
DTE IRP Team,
Please accept the following comments on behalf of the MPSC Staff. Staff appreciates the time and effort DTE has put forth to engage stakeholders and MPSC Staff during the Commission directed 2-day modeling software conference. Staff found it informative and engaging. DTE and software representatives were able to provide a thorough overview of different potential modeling software programs while Staff and stakeholders were able to share their opinions of key attributes for the Company to consider.
Staff’s comments will continue to highlight the key attributes that Staff finds are essential for successful IRP modeling. Staff focused on presentation slides 8-9 IRP modeling software collaborative introductory presentation. In Staff’s opinion, the list of evaluation criteria is robust and comprehensive. It is clear, based on the number and detail of evaluation criteria, that the Company has considered feedback from all intervening parties from the previous IRP when crafting its criteria list.
Staff would like to draw attention to evaluation criteria that it believes should be top priority. First, criteria number 5, using chronological dispatch instead of using a load duration curve dispatch. Staff views this as one of the central tenants of the effort to replace the long-term capacity expansion modeling software. Fortunately, all software options that are included in the short list are capable of dispatching chronologically. Second, criteria numbers 6 thru 8 are focused on a model’s ability to model and capture the value of the many configurations that battery storage can take. Staff believes that understanding the value of battery storage and its potential role in providing energy and capacity as part of the overall generation mix is critically important. Lastly, Staff appreciates the Company’s focus on model transparency and the clarity that DTE provided about its definition of what model transparency entails. This helps to provide certainty to all Stakeholders that the Company is focused on model transparency. Staff also views criteria numbers 18 and 21, reducing the number of software platforms required to model the IRP and intuitive interface, respectively, as other measures that increase the transparency through the reduction of the complexity of the IRP modeling process. Staff appreciates the consideration of these two items.
Staff would also like to highlight specific items from the “Nice to Have” list. Staff views this list as a focus on the value of model usability. Usability is an important attribute when engaging Staff and stakeholders throughout the IRP process. A few notable criteria are numbers 27, 29 and 33. Criteria 27, straightforward error checking, will allow DTE, Staff, and Intervenors to acclimate to the new software more quickly. Straightforward error checking can also eliminate confusion and disagreement on modeling results in the next Company filed IRP. Criteria 29 and 33, uncomplicated data import and easy exporting of input and outputs respectively, will make review of the IRP much simpler, aid in the Company’s transition to a new software, and allow the Company to ensure that data is entered into the model correctly. These attributes will also reduce time required to run the large number of modeling runs necessary for a robust IRP.
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Staff looks forward to working with the Company in the future as we continue to engage in the IRP process.
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Attachment 2: Comments from ELPC, Earthjustice; The Ecology Center; The Environmental Law & Policy Center; The Michigan Environmental Council; The Natural Resources Defense Council; The Sierra Club; Solar Energy Industries Association; the Union of Concerned Scientists, and; Vote Solar
DATE: May 29, 2020
TO: DTE IRP
FROM: Earthjustice; The Ecology Center; The Environmental Law & Policy Center; The Michigan Environmental Council; The Natural Resources Defense Council; The Sierra Club; Solar Energy Industries Association; the Union of Concerned Scientists, and; Vote Solar
RE: Comments on DTE Modeling Software Technical Collaborative
I write on behalf of the above listed organizations (“Environmental Intervenors”) with the purpose of sharing with DTE our combined impressions and comments on DTE’s May 11-12 IRP Modeling Software Technical Collaborative.
First, thank you to DTE for putting together these two meetings. We found the collaborative meetings, including the vendor presentations, very helpful. Because the models are so detailed and complex, we appreciate the opportunity for Staff and Intervenors to provide additional written comments on DTE's IRP model selection process. We were heartened to see that DTE and the Environmental Intervenors are looking for many of the same attributes in DTE’s choice of modeling software. We especially appreciate that DTE values transparency for Staff and intervenors, and we look forward to continuing collaboration with the company regarding IRP software choices and modeling scenarios in DTE’s next IRP.
Second, we appreciated DTE’s thorough list of criteria it will use to evaluate the models it is considering. Even if the weighting of the criteria will not be included in the June filing, it would be helpful to see DTE’s assessment of how each of the models stack up against that criteria, assuming none have already been ruled out. For example, for a number of the criteria we would expect the response to be binary. The ability to tie storage charging to a specific technology would likely be “yes” or “no.” During the collaborative, not all the vendors directly addressed each of these criteria. As a result, we weren’t clear about the answers to these questions ourselves and would appreciate a matrix of how each model aligns with the Company’s criteria.
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Third, as was articulated during the meetings, Environmental Intervenors’ primary concern is ensuring transparency from whatever model DTE moves to. We would appreciate that for any of the vendors DTE has not yet ruled out, DTE request the following information and provide it to stakeholders:
(1) The specifics under which all inputs, model settings, outputs, and the model manual can be shared with intervenors. Those specifics should include the format in which the information would be exported, the fee (if any), and any other terms, such as a requirement that an NDA be signed.
(2) The terms under which Staff and intervenors could license the model for a DTE IRP or other
planning related case. The terms should include the licensing fee, the length of the term, cost for support during the licensing period, and other relevant details that would influence the ability to use the model.
Finally, we ask that DTE provide an opportunity for additional feedback from stakeholders following receipt of this information, and that DTE offer opportunities for more detailed conversations about the characteristics of the lesser-known models if DTE is not ready to rule out one or more of these platforms.
We look forward to hearing more and working with DTE on this important topic. Please do not hesitate to reach out to any of our organizations if we can be in any way useful to your work on selecting new modeling software.
Very Truly Yours,
_ Margrethe Kearney Senior Attorney Environmental Law & Policy Center 1514 Wealthy St. SE, Suite 256 Grand Rapids, MI 49506 T: (773) 726-8701 [email protected]
