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Example Prompts
Smart Grid
| Prompt | Expected Response |
| If I schedule 800 kW of DERs from DER Aggregation abc registered with RTO y under Pricing Node X in the Day-ahead market during peak hours of 2:00 pm to 6:00 pm tomorrow, how much will I be short and how much headroom will I have in each hour? | A table with two rows showing the time in row 1 (from HE14 to HE 18), and positive (headroom) or negative (short) kW numbers in row 2. |
| What is the DER capacity eligible for providing Fast Frequency Response (FFR) under substation z between hours 2:00 pm to 6:00 pm this afternoon? | A table with a kW number for each of the 4 hours (HE14 to HE18) |
| For DER Aggregation abc what are the individual DER types and nameplate capacities comprising the Aggregation? | A list of DER assets, with their respective asset type (PV, electric storage, thermal storage, EV, ..), and nameplate capacities (kW) |
| Is DER Aggregation abc registered in RTO y? Follow up questions, if the answer is yes: What grid services is it eligible to provide? | Expected response 1 Items from the list of grid services: Energy, spinning reserve, supplemental reserve, Fast Frequency Response, frequency regulation, Reg-Up, Reg-Down, etc. 2. What RTO pricing node (transmission substation) is it under? Expected response 2 A pricing node names such from the list of pricing nodes for the RTO |
| For DER Aggregation abc what are the individual DER types and nameplate capacities comprising the Aggregation? | A list of DER assets, with their respective asset type (PV, electric storage, thermal storage, EV, ..), and nameplate capacities (kW) |
Trading
| Prompt | Expected Response |
| If I purchase 50MWs on-peak in DUK tomorrow, will it be more profitable to sell in either PJM or MISO? What is the likelihood that I will lost money? | Based on historical prices, forecasted weather, outages, and day-ahead schedules, PJM is expected to be higher than MISO. By moving power from DUK to PJM will result in a profit of $5.57 per MW for on-peak. This number accounts for transmission costs. This equates to a profit of $4,456 (5.57x16x50). There is a 25% likelihood that selling in either PJM or MISO will result in a loss. |
| Which is likely to be more profitable? A virtual bid or a virtual offer in ISO XYZ for tomorrow | Tomorrow’s weather and scheduled flows indicate that DA prices should exceed RT prices, therefore a virtual offer is more likely to be profitable. |
| Should I buy 50 MW on-peak prompt month (July) at PJM West Hub and then sell the same 50MW every day in Real-time at PJM XYZ Hub. | Based on historical prices, forecasted weather, outages, and day-ahead schedules, on average, this transaction will lose money. However, if the transaction was structured as a bal-month starting on July 15th, it is likely to make money. This is because the period between July 15th and July 31 is expected to result in comparatively higher prices in PJM Real-time compared to the first half of July. |
| Based on the 3-day forecast (yesterday, today, and tomorrow) and broken down by zones (e.g. east/west/north/south – technically PJM would be Dominion or Mid-Atlantic area VS Chicago which is AEP etc.), the Eastern Seaboard weather and Midcontinent weather, Transmission outages and tagging locational flows (e.g. into PJM from SERC or MISO), historical pricing on days with similar load (and days that were close), what are the chances that there will be West to East Congestion based on current and historical data? IF so, then at what range should we get long or short the Western Hub/AEP Dayton Hub (West/AD Spread) for On-Peak and Off-Peak? | Based on the 3-day forecast, forecasted weather, and historical congestion data, there should be West to East Congestion starting around HE 14 and continuing through HE20, peaking at HE 18. There is no expected congestion during the off-peak hours. |
Transmission
| Prompt | Expected Response |
| E-Tag ABCD failed validation today. Explain what needs to be changed on the tag to correct this issue. | Based on webTrans Tag Validation criteria, e-Tag ABCD failed your business rules due to the Transmission Owner for OASIS reservation 1234 not matching the PSE on Physical Segment #2. |
| For the Month of August 2025, how much variation is there between the energy scheduled on dynamic and pseudo type e-Tags vs the final mw adjusted after-the-fact? | In August 2025, there were 25 Confirmed Dynamic type e-Tags and 12 Confirmed Pseudo-Tie type e-Tags for your company. The Dynamic e-Tags had a combined additional 2,345 MWH of energy scheduled after-the-fact. The Pseudo-Tie e-Tags had a combined additional 789 MWH of energy scheduled after-the-fact. |
| For the Month of August 2025, how much non-firm ATC on a Path XYZ is due to counter-flow and unscheduled firm impacts and what percent change is that from the prior month? | In August 2025, Path XYZ had a final combined 13,934 MW of Non-Firm ATC posted to OASIS as a result of Counter-flow schedules and 5,873 MW of Unscheduled Firm TSRs. This is an increase of 9.5% and 23.8%, respectively. |
| For the Month of August 2025, list all TSRs what where overscheduled. Provide results per Customer per TSR and list the e-Tags and MWs. | The following TSRs, active in August 2025, were overscheduled: TSR1 was overscheduled by 15 MHW with Tag1 and Tag2 TSR2 was overscheduled by 100 MHW with Tag45 TSR3 was overscheduled by 5 MHW with Tag23, Tag34 and Tag6 |
| For August 2025, provide a report comparing the volume of TSR capacity purchased verses what was scheduled. Provide results per Path. | In August 2025, the following Paths had remaining unscheduled capacity: Path1 had 2,490 MW of reserved transmission and 1,634 MW of scheduled capacity. Path 2 had 589 MW of reserved transmission and 664 MW of scheduled capacity. This appears to be overshedule. Path 3 had 3,880 MW of reserved transmission and 2,854 MW of scheduled capacity. |