Commission adopts controversial rule changes approved by ERCOT Board

The Texas PUC approved non-unanimous protocol and other revisions approved at the most recent ERCOT Board meeting. The rules concerned RUC make-whole payments, duration requirements for ECRS and Non-Spinning Reserves, and mandatory ERCOT approval of research outage requests.

Staff filed a memo with a proposed order recommending the approval of 14 ERCOT rules approved by the ERCOT Board of Directors.

NPRR1124

Commissioner Cobos noted that Nodal Protocol Revision Request (NPRR) 1124 was approved by the ERCOT Board on an urgent basis to ensure that generation resources are made whole on their actual fuel cost when their generation units are Reliability Unit Commitment (RUCed) by ERCOT.

While acknowledging that reliability is paramount, Commissioner Cobos added that the impact of ERCOT actions on ratepayer costs is also a very important factor to consider. She noted that it is more costly to RUC specific generation resources that have to pay higher natural gas prices for their contractual agreement with their gas suppliers.

While ERCOT may have to RUC generation units with higher gas prices to address specific reliability needs in certain areas of the state, Commissioner Cobos suggested that, as a general strategy, ERCOT should be looking at the entire generation fleet, to more cost efficiently select units to RUC and to spread out the RUCs among the entire generation fleet in order to mitigate consumer costs and maintain reliability.

Commissioner Cobos also noted that RUC’ing the same older generation units with higher gas prices has a greater impact on consumers and places more pressure on those units, which could lead to higher forced outage rates and retirements.

While acknowledging that she would vote to approve NPRR1124, Commissioner Cobos wanted a commitment from ERCOT that the PUCT’s approval of the NPRR did not create an impetus for continued RUC’ing of the same units and that ERCOT will work on optimizing its RUC engine to look at the entire fleet, to more cost-effectively select generating units to RUC and spread its RUC’ing across the entire fleet as much as possible. Commissioner Cobos requested a report from ERCOT on its RUC engine efficiency optimization efforts.

Commissioner Cobos noted that some generating units are putting themselves in EMR status because they would not break-even on RUC costs because their fuel costs are really high. She acknowledged that these units are needed for reliability but she would like to know when that is happening and when the market is paying above KPI prices. She concluded that the PUCT needs to know when generating units are being RUCed that are experiencing very high natural gas prices.

Chairman Lake noted that reliability always comes first but cost is always a close second.

NPRR1096

Commissioner Glotfelty addressed NPRR1096 (requiring 2-hour sustained capability for ERCOT Contingency Reserve Service and 4-hour capability for Non-Spinning Reserve Service). He hoped that these could ultimately be removed once real-time co-optimization is completed.

Commissioner Glotfelty stated that these facilities need to be able to provide electrons when they can, not dependent on how long they can be sustained. He suggested that this is an important step in ensuring that the system remains reliable and is the right thing for now. However, he noted that the system will change, with new resources, such as batteries, and it will be important to understand how their Effective Load Carrying Capability (ELCC) will be calculated in Security Constrained Economic Dispatch (SCED). He reiterated that he hopes the Commission will modify these in the future.

Chairman Lake agreed, adding that he hopes in the future things will get to the point where resources can schedule for the time they can perform and, as has been discussed, get the same reward or penalty as any other resource.

Commissioner McAdams noted that ERCOT is not an outlier, that other ISOs around the country are adopting the same 4-hour standard for duration for a non-spinning ancillary service, which is being applied nearly universally to incent merchant batteries to achieve that target.

Commissioner McAdams noted that this change increases the hurdle, possibly requiring a derate of the resource for those merchant battery generators that expect to be able to participate in these various programs. However, for the “vast influx” of batteries expected in the near future, it is important for ERCOT to establish this threshold sooner rather than later.

Chairman Lake noted that when the system needed non-spin in the past, it was needed for 4 hours, not 45 minutes.

NPRR1108 (ERCOT Shall Approve or Deny all Resource Outage Requests)

Commissioner McAdams noted that NPRR1108 was hotly contested throughout the entire process, at the ERCOT Technical Advisory Committee (TAC) and before the ERCOT Board of Directors. He stated that it is an extremely important policy enhancement that came to the fore through Senate Bill 3 and through the PUCT’s proceedings and also has implications for resource adequacy in Phase 2 of the PUCT’s ERCOT market redesign.

Commissioner McAdams asked ERCOT staff to explain the Maximum Daily Planned Resource Outage Capacity (MDRPOC or “the cap”). He noted there was a lot of opposition to ERCOT staff’s recommendation although it was ultimately approved by the ERCOT Board of Directors.

Woody Rickerson, ERCOT’s Vice President of Grid Planning and Operations, explained that the MDRPOC is a forecast of available capacity for the next five years. The intent is that the forecast be public for resource owners and that it be used along with what has already been approved against that cap to see how much outage capacity is available. He suggested that most market participants believe it is a good idea.

Mr. Rickerson noted that there had typically been over-scheduling of automatically approved outages in April and October and excess outage capacity available in March November that wasn’t being used. He suggested that this is a good improvement and the controversy primarily concerns what the cap should be.

Commissioner McAdams noted that ERCOT Board Chairman Paul Foster urged ERCOT staff to engage with stakeholders to ensure that all resource owners have sufficient time to conduct planned maintenance to ensure that those facilities remain operational through peak periods, as expected. He understood that certain components of the proposal that were rejected were unpalatable and infeasible by ERCOT staff because they established a minimum that would be unplanned at any time, adding that from an operator standpoint this was untenable because ERCOT needed the ability to call everything back during critical times.

Commissioner McAdams also noted the concern that delegating the overall authority in the independent governance structure that ERCOT now has under SB 2 to the stakeholder-controlled TAC was untenable.

Commissioner McAdams noted that the PUCT will soon be taking up a weatherization rule that will place burdens on generators, imposing standards that will be enhancements to what has already been done toward achieving the “2011 reliability standard.” The commissioner noted that the first year is a concern because the PUCT wants to make sure that, once the weather standard goes into effect, generators have time to do whatever rehabilitation they need to do to their facilities.

Mr. Rickerson explained that for the first three years the proposed cap would have 15% more outage time available than what market participants used in 2021. However, Mr. Rickerson noted that these units are being RUCed more and 2021 may not be the best indication of how much outage time is needed but it is the best ERCOT has at this time.

Mr. Rickerson noted that the cap methodology has been published and will be going before TAC. He informed the commissioners that market participants wanted to include future planned generation into the cap and ERCOT has done that, making the cap higher than it was in the original filing.

Mr. Rickerson noted that ERCOT wants generation units to be able to do as much maintenance as they need to do to be reliable, adding that forced outages are the worst thing that can happen from a grid perspective.

Commissioner McAdams added that forced outages affect the accreditation of those facilities and there needs to be a reasonable expectation of how these units are able to perform in “crunch time” and creating an incentive for a forced outage would not do anyone any good.

Mr. Rickerson noted that “part of the rub” is artificially setting that cap too high because an argument can be made that ERCOT should set the cap very high and then rely on the Advanced Action Notice (AAN)^[1] process to deal with over scheduling. Mr. Rickerson noted that, while AAN is an effective process, it has only been used a limited number of times and won’t work if used too much.

Commissioner McAdams noted that a fear among generators is that the methodology for establishing the range of the MDRPOC could be based on worst case scenarios, low intermittent outputs during the 60 months, especially the first 12 months, or the maximum amount of forced outages experienced so far. He added that everyone wants to know we are not going to prevent them from having a planned outage due to the adoption of a conservative approach.

Mr. Rickerson noted that Texas Competitive Power Advocates’ (TCPA’s) comments, for example, suggested that ERCOT’s 50/50 forecast (the expected case) was the most conservative forecast, which he informed the commissioners is not true. He noted ERCOT will continue to review this and if they are not over-utilizing the AAN process they will change the cap. He explained that ERCOT would like to limit AAN use to 6 to 9 times per year and 30 times would be too much.

Commissioner Cobos noted that SB3’s overarching policy goal is to enhance and ensure grid reliability in the future, which requires balancing the policy goal with compliance with the statutory requirement. She suggested that it is critical that the PUCT ensure that “the cure is not worse than the disease.”

Commissioner Cobos noted that scheduling five years out gives her some concern because nothing can be forecast that far out with any certainty. She wondered whether the generation community can be “nimble enough” to respond to last-minute changes to resource outage availability, to react within seven days to schedule their contractors and conduct needed maintenance within that window.

Commissioner Cobos noted that while ERCOT may believe that 15% may provide additional flexibility, the methodology is “where the rubber meets the road” and it has tremendous impacts for grid reliability. She wants to make sure the process is not more complicated than necessary and wants generation to be able to respond “within practical reality.”

Commissioner Cobos noted there are still important questions to be answered, including how will increasing renewables on the system impact things? How will increased RUC’ing affect planned maintenance?

Mr. Rickerson noted that the MDRPOC process has a short-term component and long-term component. The longer-term piece is based on averages, the 50/50 forecast and seasonal capacities. The shorter-term piece incorporates wind, solar and load forecasts, which can cause the cap to go up or down in the near-term. He suggested that resource owners that have long maintenance cycles won’t be able to use the short-term improvements to schedule maintenance and will have to schedule it in the longer-term.

Mr. Rickerson suggested that having the cap set at the right place will offer resource owners some confidence that ERCOT will not be issuing AANs every week and will not have to consider moving those. He suggested, however, that shorter outages could be fit into the seven-day window when there is excess wind, etc.

Chairman Lake noted that, although the Commission is using a more conservative posture, one out of four or five times this outlook is not conservative enough and that’s why they have to have the AANs. He noted that, without the conservative posture, if an event that happened on May 8 had happened 52 hours earlier, it would have led to “a very serious crisis.”

The Chairman noted that, like Firm Fuel, “the first time out of the gate [MDRPOC] is not going to be absolutely perfect” but they will learn more over time and correct their course. He noted that, at the most recent ERCOT Board meeting, Chairman Foster had directed ERCOT staff to engage with stakeholders, include TAC in the process and be open to course corrections where appropriate.

Noting that the MDRPOC would go back to TAC and then to the ERCOT Board in June, Commissioner Cobos proposed a process to ensure that not only ERCOT staff is involved in ensuring reliability and coordinating outages but also that the “expert stakeholders” on the ground that are operating these “very complex assets” have the opportunity to have a lot more involvement in the process.

Commissioner Cobos proposed that ERCOT hold a workshop to provide an opportunity for stakeholders to provide public comments. After which, the proposed methodology would be sent to TAC and ultimately lead to a TAC-endorsed recommendation to the ERCOT Board.

Chairman Lake stated that, after approving the NPRR, the PUCT needs to “let the newly-independent SB2 Board run [ERCOT].” He stated that, after approving the NPRR, the Commission is no longer involved in the implementation of that methodology and its ongoing edits, that’s up to ERCOT.

Commissioner Cobos replied that, “at the backend, we [the PUCT] are responsible for the MDRPOC methodology because, if it goes wrong, and we have grid reliability issues, we’re responsible.”

Chairman Lake replied “I am acutely aware of our responsibility, of everybody up here. I am most acutely aware of our responsibility. I am also aware that the legislature passed SB2 to have independent oversight of ERCOT and, while we have ultimate regulatory oversight of them, we need to be deferential to SB2.”

The Chairman agreed with Commissioner Cobos’ approach of ensuring the ERCOT Board has multiple points of view and is “not sitting in an echo chamber” but added that the Commission also needs to stay “at arm’s-length” to let them do their job.

Commissioner Glotfelty asked how ERCOT would take into consideration outage requests from cogeneration facilities that coordinate their outages with outages of their steam host.

Mr. Rickerson replied that this was spelled out in a special area and is not subject to ERCOT approval.

Commissioner Glotfelty noted that if there were additional thermal generating capacity in the state this wouldn’t be an issue because people could take outages whenever they want to without creating a reliability issue.

Commissioner Glotfelty suggested that ERCOT is taking responsibility for any increase in forced outages and, if this happens, the Commission will know there was insufficient maintenance time available. He inquired what would prevent one company from scheduling all of its maintenance for five years, leaving a big generating unit at the end with no maintenance capability.

Mr. Rickerson replied that there is nothing that would prevent that but that it is no different today and ERCOT has never experienced anyone doing that.

However, Commissioner Glotfelty noted generators had never been subject to denial of a maintenance request as long as it was made at least 45 days in advance.

Mr. Rickerson suggested there would be ways to police that if it became a problem.

Commissioner Glotfelty asserted that generators are the best entities to be able to police their outages. He noted that they want to make money and will do their best not to be in an outage when there are high prices and they are needed most. He would like for generators to continue scheduling the way they have been scheduling, fearing that the PUCT will change the process and create problems they are not even aware of yet. He explained that plant managers know their plants inside and out and are aware of every day they can take an outage. Commissioner Glotfelty suggested that, if someone tells them no, there are going to be more forced outages, which will create a bigger reliability problem.

Commissioner Cobos shared Commissioner Glotfelty’s concerns and wanted to ensure that the process she laid out earlier is incorporated. She stated that the process for establishment of the initial methodology and its changes going forward are critically important to her and will provide her with more comfort in approving this, which she acknowledged makes her nervous.

Commissioner Cobos stated that she doesn’t want to see stakeholder feedback ignored by ERCOT and generation operators not to be heard. She stated it is important to take and ERCOT staff recommendation as well as a TAC endorsement to the Board, adding that the Board needs to hear from the operators of these very important assets.

Background

At its meeting on April 28,2022, the Board recommended Commission approval of the following proposed revisions to ERCOT rules:

·      NOGRR239, WAN Data Protection Responsibilities;

·      NPRR1092, Reduce RUC Offer Floor and Remove RUC Opt-Out Provision;

·      NPRR1096, Require Sustained Two-Hour Capability for ECRS and Four-Hour Capability for Non-Spin;

·      NPRR1108, ERCOT Shall Approve or Deny All Resource Outage Requests;

·      NPRR1116, Remove Obsolete Reference to Market Information System (MIS);

·      NPRR1117, Related to SMOGRR025, Modifications to Line Loss Compensation Requirement for EPS Metering;

·      NPRR1122, Clarifications for PURA Subchapter M Securitization Default Charges;

·      NPRR1123, Clarifications for PURA Subchapter N Securitization Uplift Charges;

·      NPRR1124, Recovering Actual Fuel Costs through RUC Guarantee;

·      NPRR1125, Use of Financial Security for Securitization Default Charge and Securitization Uplift Charge Invoices and Escrow Deposit Requests;

·      PGRR096, Achieve Consistent Representation of Distributed Generation in Steady-State Models;

·      PGRR098, Consideration of Load Shed in Transmission Planning Criteria;

·      SCR818, Changes to Incorporate GIC Modeling Data into Existing Modeling Applications; and

·      SMOGRR025, Modifications to Line Loss Compensation Requirement for EPS Metering.