Background on NPRR and system Lambda capping process shared. Capping set to prevent system Lambda from exceeding $5000 per megawatt hour due to concerns raised post-2019 Commission discussions.
Explanation of scenarios where resources dispatched by SCED might be financially harmed due to the capping process.
Lack of proposal inclusion for controllable load resources due to existing operational practices and minimal impact expectation.
Illustration of how the capping process impacts generation resources and the financial implications using a high-level example.
Proposal discussed to utilize existing emergency operation settlements to mitigate potential financial harm from capping.
Concerns raised over the logic of including ancillary service revenues when calculating harm, drawing parallels to price correction scenarios.
Clarification sought on whether ERCOT would actively communicate capping occurrences or if it would be left to QSEs to identify.
Reiteration of misunderstanding around the ancillary service revenue clawback and its necessity questioned.
Simulation tests indicated limited occurrence of the discussed harm scenarios unless under artificially stressed conditions.
The presentation concluded with suggestions for a near-term solution using existing protocols, and considerations for long-term solutions like removing the capping process altogether.
▶️3.1 - Impacts of System Lambda Capping and Discussion on Alternatives
Shams Siddiqi from Hunt Energy Network highlighted issues with capping the System Lambda, initially proposed in 2019, stating that there's no explicit price cap in the current market ordered by the PUC.
Current protocols adjust the ORDC adder to prevent the system Lambda from exceeding $5,000 per MWh, which affects market prices differently than true capping.
Uplifts caused by capping are paid by the load and should be avoided due to market design concerns, including price distortion and inconsistent congestion pricing.
Since the RTC protocols have been approved: The actual value of lost load (VOLL) is closer to $35,000 per MWh, far above current HCAP reduced to $5,000 from the original $9,000 per MWh cap.
Emergency Pricing Program (EPP) implementation reduces HCAP further to ECAP of $2,000, activated if HCAP prices occur in 12 of the last 24 hours.
Example given: Capping leads to pricing signals like negative $250 per MWh at LMP1 = $200/MWh, which distorts consumer behaviors.
Proposal suggests removing system lambda capping due to lack of substantive PUC rule requiring it and to align with energy-only market principles.
Discussion around submitting a no-impact urgent NPRR to eliminate capping language subject to PUC approval, allowing for further discussion if needed.
Concerns about capping impacting prices and CRR payouts, unhedgeable uplifts, and incorrect price signals during scarcity events.
Shams proposed a new proposal with a focus on aligning pricing signals during scarcity events without capping, with potential NPRR submission.
Presentation by Dave Maggio and discussion on the new NPRR language proposals, clarifying telemetry requirements, emergency operations settlement language, and inconsistencies in protocol related to real-time co-optimization.
Multiple discussions on proper adjustments to real-time system-wide offer caps and ancillary service offers.
Concluded with intent to file NPRR in the following weeks to facilitate further stakeholder discussions and iterations.
Overview: Revisit of paper discussed in previous RTC meeting related to NPRR1204, focusing on deployment factors used in RUC (not in real-time).
RUC and RTC Changes: Discussion on energy storage resource commitment and dispatch in RUC. Challenges noted in economic dispatch for batteries led to the decision of self-scheduling batteries based on their submitted SOC.
Self-Scheduling: Self-scheduling batteries to their submitted SOC to avoid unrealistic dispatch scenarios caused by scaled-down offer costs.
Deployment Factors: Deployment factors, crucial for understanding AS usage, were clarified. They are used to calculate how much stored energy may be used during each hour.
RUC Capacity Short Calculations: These calculations utilize deployment factors posted day-ahead at 6 AM for all hours. Discussion on appropriate use and adjustment of these factors.
Concerns and Clarifications: Questions were raised regarding how deployment factors are calculated, especially for non-regular AS like ECRS. The historical deployment is not seen as a reliable indicator.
Future Considerations: Uncertain scenarios and risk analysis will influence deployment factors. This is still under development. Discussion on how this affects AS bidding behavior.
Committee Response: ERCOT confirmed they are considering the ability to dynamically adjust factors and are working on more robust methodologies.
Pre-Day Ahead Market tasks involved ensuring systems can download new reports and manage AS obligations with precision up to five significant digits after the decimal.
Participants need to test self-arrangement and various offer types, particularly AS only offers and submissions involving ESRs and negative values for charging.
Emphasized the difference between day ahead market and real time system-wide offer caps.
Mentions specific AS types that cannot be submitted, like offline reserves, ECRSMD, and RRSUFR.
Reminded QSEs of the unchanged nature of resource-specific AS offers and the introduction of an AS only offer.
After running the day ahead market, the focus is on accurately publishing and pulling final AS obligations and receiving awards accurately.
Adjustment period after the day ahead market allows for changes to COPs and trades, noting the lack of charges for trades above self-arrangement for load resources.
Highlighted the day ahead market's voluntary nature while encouraging participation for successful market tests.
Overall, the purpose of tests is to ensure all mechanics work effectively, not primarily for simulation.
▶️5.3 - Review of Settlement Statements and Extracts
