ERCOT CEO updates PUCT on “Big Five” initiatives

Prior to the PUCT’s August 24, 2023 Open Meeting, (ERCOT) submitted overviews detailing the following market enhancement initiatives:

•     establishment of the Dispatchable Reliability Reserve Service (DRRS),

•     development of the Performance Credit Mechanism (PCM),

•     implementation of a multi-step floor to the Operating Reserve Demand Curve (ORDC), and

•     implementation of Real-Time Co-optimization (RTC).

The overviews included ERCOT's current estimate of the anticipated timeframes to develop and implement each initiative.

Mr. Vegas reviewed the suite of market design initiatives that ERCOT is working on. He addressed the “big five” initiatives:

•     making the floor changes to the ORDC

•     establishment of the reliability standard

•     development of the new DRRS ancillary service

•     development of PCM, and

•     development of RTC.

ERCOT’s CEO explained that these 5 initiatives will help drive reliability and make changes to the market construct that are designed to improve both operational flexibility and long-term resource adequacy and will be moving in parallel to some degree.

Mr. Vegas explained that issues involving the reliability standard addressed in one memo, while ORDC, DRRS, PCM and RTC are addressed in a separate memo. Within each memo there is a summary that captures the background of what led to each of the initiatives, their scope, key milestones and timelines.

ORDC Changes

Mr. Vegas addressed the ORDC floor, noting that ERCOT is proposing to implement a floor of $10 per MWh when reserves fall to between 6,500 MW and 7,000 MW and the floor would increase to $20 per MWh when reserves fall below 6,500 MW. ERCOT will be bringing an impact analysis to the ERCOT Board at its October 17 meeting and then to the PUCT for approval later in October. If approved, ERCOT could implement the ORDC adjustments in November 2023, providing an opportunity to see the benefits before the winter season.

Commissioner Glotfelty asked the ERCOT CEO whether the ORDC would still be needed if ERCOT moves to PCM and some other way of paying for capacity value.

Mr. Vegas suggested that, before having a clear design of how the PCM works and with some important parameters to be determined, they should always be looking at the combination of tools that are available to incentivize the goals of the ERCOT grid, which are to provide a very efficient and reliable service and be very transparent and clear to all market participants.

While there are other possible ORDC changes that could be beneficial to the market once the other tools have been implemented, ERCOT CEO suggested that it is a little early to say we won’t need the ORDC or that it good be modified in a specific way. However, he recommended that, as the design is implemented, there should be a pause for a reflection on how these services and products are performing, how they are impacting some of the key metrics on the grid, how resource interconnection intentions are being driven, how is it driving real-time pricing? There should be a mindset of continuously improving the suite of tools and only having the tools and services that are necessary to deliver on those mandates.

Commissioner Glotfelty recommended that, as new things are implemented, as the system, demand and generation change, it will be important to consider whether to take things out that may no longer be necessary. He noted that the PUCT has not yet done the ancillary service review required by SB 3 and will bring this topic up at an appropriate time in the future.

Commissioner Glotfelty asserted that it is really important that the Commission provide an understanding of what the ancillary services are, why they are being used, what they can bid into and what they can’t. He noted that ancillary services are operationally focused, designed to help ensure that the transmission system stays adequate and power can flow reliably, but they are not a capacity construct.

Commissioner McAdams noted that Real-Time Co-optimization of Energy and Ancillary Services (RTC) is supposed to harmonize ancillary services and the dispatch of the services, negating the impact of ORDC, which will still have value but not to the degree that we are accustomed to today, but we won’t know until we get there and analyze it.

Reliability Standard

Mr. Vegas noted that developing the reliability standard has three core components: 1) development of the reliability standard itself and its parameters, including reasonable loss of load frequency, magnitude and duration limits, 2) Value of Lost Load (VOLL)., and 3) Cost of New Entry (CONE).

VOLL involves surveying customers across different classes to determine the value of energy when it is not available. This is done to determine how much should be invested to achieve a given reliability standard.

Mr. Vegas explained that CONE is one of the underlying drivers in achieving a reliability standard because the standard describes the resource mix needed to achieve whatever the standard is, so the cost of achieving the standard will depend on CONE, which the cost to build the next lowest cost generating capacity needed to achieve the reliability standard.

ERCOT has proposed 48 scenarios that model variations of the expected loss of load duration and magnitude based on different resource mixes. ERCOT is currently running those scenarios in order to bring the outcomes back to the PUCT for discussion concerning the resource mixes at different scenarios, allowing the Commission to focus on the chosen parameters. ERCOT hopes to provide the outputs at the September 14, 2023 open meeting.

Mr. Vegas noted that ERCOT has been working with Lawrence Berkeley National laboratory at that, which has been working on a VOLL study with AEP Texas and hopes to leverage some of that information to jumpstart and accelerate ERCOT’s work on VOLL. ERCOT’s CEO reported that ERCOT has also initiated a Request for Proposals for its CONE study.

Mr. Vegas informed the Commission that ERCOT hopes to have all of the studies worked through over the next quarter and expects to have the results of all the analyses, with preliminary inputs, sometime in the first quarter of 2024, leading to establishment of a reliability standard in the middle of 2024. He noted that this will be helpful in evaluating the cost/benefit of the other tools, including DRRS and PCM.

Commissioner McAdams complemented ERCOT staff on their work preparing for the VOLL study, adding that he would provide it to SPP and they would probably use it as a template.

Commissioner Cobos suggested that the CONE study has multiple benefits, it is important as a barometer for the market, letting stakeholders and others see how much revenue is being put into the market, in addition to fulfilling the PUCT’s HB 1500 required assessment of PCM.

ERCOT’s filing states that “these market initiatives will implement a mandatory Reliability Standard and determine updated input values for VOLL and CONE to inform that Standard.” [Emphasis added].

Commissioner Cobos was concerned with the use of the word “mandatory,” adding that some people in the audience would quiver at that word. As opposed to a “target,” she suggested that, for most people in the market, this suggests a distinction between a competitive market and a capacity market. She suggested that SB 3 requires the Commission to establish a reliability standard but doesn’t say it must be mandatory and believed this decision would be made at the backend. She asked if ERCOT believed the reliability standard should be mandatory.

Mr. Vegas replied that development of the reliability standard is mandatory but that the real value in a reliability standard is what happens when you have one. He suggested that, if the reliability standard indicates there will be shortfalls in reliability, this is something the Commission should look at, to try to drive the market to achieve that reliability standard and would become a mandate in terms of the collective mandates for their accountabilities.

Commissioner Cobos noted that we are in a market with a variety of tools, both supply and demand, to help achieve a reliability standard and she wonders how they would be able to mandate meeting the reliability standard, because there is not one single tool that will achieve this.

Mr. Vegas agreed, adding that this is a complicated market and it will be necessary to look at supply-side solutions, transmission solutions and demand solutions. He added that some tools are more the purview of the Commission under current statute than others. He suggested that once there is a reliability standard and a reasonable expectation of not being able achieve it, they would look to leverage all the tools that are available to achieve it and advocate for changes in policy, if necessary, which would be a mandate on the accountabilities of both the PUCT and ERCOT to do so.

Commissioner McAdams suggested that there is a bright line between a reliability standard the PUCT would mandate through a single mechanism, which he believed the Legislature spoke to. Policy parameters were clarified and he interpreted the Texas legislature’s action as ordering the PUCT to pursue a “sum of all parts” approach, a diverse menu of resource adequacy reliability driven tools to use to channel a policy for achieving a target reliability standard.

Commissioner Cobos reiterated that using the word “mandatory” made it seem like the Commission had already made a determination that the reliability standard was going to be mandatory.

Chairman Jackson suggested that part of the value of ERCOT’s overviews and workflow diagrams is that parties can see the whole picture, not only the work ahead but also what has been accomplished. She suggested that sometimes the real value is in the process, securing engagement from the public and stakeholders.

Commissioner McAdams asked when information concerning the contractor who will manage the VOLL survey will be publicly available so he could pass that information on to the Southwest Power Pool (SPP). He added that there is a regional effort underway so ERCOT and the greater Midwest have a similar approach.

Mr. Vegas replied that this information would be available soon, probably in the coming weeks, adding that they are “pretty deep in negotiations” but it is confidential until they execute the contract.

Commissioner’s McAdams noted that there will be a resource adequacy summit in Dallas that will be attended by MISO, SPP and FERC. He requested that Mr. Vegas talk with them about ERCOT’s plan.

Commissioner Glotfelty noted that he is on the project advisory committee for updating the Interruption Cost Estimator (ICE) calculator, adding that AEP has been supportive of using that tool but others are still evaluating it. He suggested that bringing in external views, like Lawrence Berkeley Lab, should help the Commission make the right decision.

Dispatchable Reliability Reserve Service (DRRS)

Mr. Vegas noted that DRRS is a new ancillary service that was mandated by HB 1500. It requires load or supply to be able to come online within two hours and operate for a minimum of four hours. One of the stated goals of the service is to reduce Reliability Unit Commitment (RUC) by an amount equivalent to the amount of DRRS that is acquired.

Mr. Vegas explained that ERCOT evaluated several approaches to delivering this ancillary service on a very quick timeline. He noted ERCOT’s last new ancillary service, ERCOT Contingency Reserve Service (ECRS), look a full three years for development and testing so delivering a new ancillary service by December and 2023 is a “very, very quick timeline” and limited available options.

ERCOT looked at three approaches: 1) a traditional stand-alone new ancillary service similar to the development of ECRS, 2) replacing the current Non-Spinning Reserve Service (NSRS), and 3) creating a sub-type of Non-Spin.

After obtaining input from ERCOT’s operations team concerning how they use the current ancillary services, ERCOT believed it would be more reliable and safer to preserve the value of Non-Spin and add a sub-type of Non-Spin that would allow for products between 30 minutes and two hours to come online to meet the requirement for DRRS and deliver the four-hour capacity requirement. Mr. Vegas confirmed that these two products would clear at a single clearing price.

Mr. Vegas acknowledged that paying a peaker and a slow ramping resource the same price is not optimal but it was not possible to meet the schedule by developing a standalone ancillary service. He noted that a final decision has not been made and ERCOT is still working through workshops but that is the direction they are planning to move forward on.

ERCOT’s CEO informed the Commission that ERCOT is going to file the related Nodal Protocol Revision Request (NPRR) through the stakeholder process between September and November, to the ERCOT Board in December and then for approval by the PUCT in January 2024. The development and testing of DRRS will occur between January and November 2024, in anticipation of going live by December 1, 2024.

Commissioner Glotfelty suggested hiring an outside consultant to help evaluate how these ancillary services are working together and where there are challenges, such as solving ramping problems.

Commissioner Glotfelty addressed the annual ancillary services procurement timeline. He was concerned that the methodology not change as the system changes. He believed that at some point it would be necessary to move to something more granular, to a season or month and ultimately to the specific week or day. He concluded that one ancillary service methodology discussion per year “doesn’t cut it” anymore and hopes that ERCOT or the PUCT will tee that up to determine the best timeframe for looking at that issue.

Acknowledging that ERCOT staff is still considering this, Commissioner McAdams reiterated his concern about paying a peaker the same as a combined cycle unit to ramp into an ancillary service. He asked why ECRS would not have been a better home for the 30-minute subset.

Kenan Ögelman, ERCOT’s Vice President of Commercial Operations, explained that ECRS does not have the ability for unit-specific dispatch but Non-Spin does. For this reason, moving more things into “the ECRS bucket” did not work in terms of covering the other reliability benefits that Non-Spin offers.

Mr. Ögelman responded to questions about Responsive Reserve Service (RRS), noting that it is more prescriptive, putting specific requirements concerning “shocks to the grid” and that it “sits” more within the North American Electric Reliability Corporation (NERC) requirements. RRS is usually deployed in response to a contingency, when reserves are below 3,000 MW.

Mr. Ögelman explained that combustion turbines usually have a “quick start” mode that can bring them online in 10 minutes but the normal startup time is 30 minutes. The quick start mode involves additional expense and wear and tear so owners make decisions to optimize which service they want to provide.

Performance Credit Mechanism (PCM)

Mr. Vegas noted that the Commission approved a framework for PCM in January 2023 but some of the parameters were modified during the subsequent legislative session through HB 1500.

ERCOT is currently working on a framing document to develop the key definitions and identify what decisions need to be made in the early stages of developing PCM, such as defining the scarcity hours to use, how many scarcity hours there will be, what periodicity to use for evaluating the scarcity hours, and whether there would be penalties for non-performance. The framing document will be developed in September and October, with feedback from the Commission in late October. Workshops will begin in the third and fourth quarter of 2023 in parallel with input from the market on these issues. Based on this input, ERCOT will develop an initial proposal on how the PCM would work. Additional workshops in the first and second quarter of 2024 will actually design how the PCM would work.

Once the PCM design is complete, ERCOT, in conjunction with the ERCOT Independent Market Monitor (IMM), would be able to begin the legislatively-required cost study to determine whether it is worthwhile to implement PCM based on the reliability benefits that would be expected. Mr. Vegas anticipated completing the cost study by the end of 2024, allowing the results to be available when the next Texas Legislature convenes in January 2025.

Assuming all work proceeds as planned and there is a successful evaluation by the legislature, ERCOT would develop the technology and protocols beginning in 2025, with delivery in late 2026 or 2027.

Noting that the legislature charged ERCOT and the IMM with doing the cost study, Commissioner Glotfelty asked if Mr. Vegas thought those would be two independent studies or one. He hoped the studies would be separate, providing two data points.

Mr. Vegas stated that his initial thinking was that they would be a single study, rather than two independent points of view with potentially contradictory elements. However, he expects to work closely with the IMM on the underlying assumptions and they could possibly present a single study with different assumptions and conclusions. He concluded that a final decision on how this would be done had not been made.

Mr. Vegas anticipated that the decisions on the PCM parameters would be developed as “a slow rollout” of multiple discussions rather than a “Big Bang,” because there will be so many critical issues that need to be addressed.

Commissioner Glotfelty noted that there did not appear to be any ERCOT Technical Advisory Committee (TAC) involvement in the proposed process but hoped that TAC and other ERCOT subcommittees would be involved in the discussion.

Real-Time Co-optimization of Energy and Ancillary Services (RTC)

Commissioner McAdams noted that the RTC+B process outlined in the filing referred to Nodal Protocol Revision Request (NPRR) 1186, which has a number of policies packaged inside of it. The commissioner noted that the PUCT has not approved NPRR 1186, which is a “big policy” and the subject of controversy within TAC. He noted there are some strategic considerations within NPRR 1186 and recommended striking the link between NPRR 1186 and the ultimate implementation of RTC. The commissioner clarified that he was not suggesting striking the linkage to the resolution of “state of charge” policy because you have to get to what your state of charge looks like so that you can co-optimize that.

Mr. Vegas replied that NPRR 1186 is a standalone interim state of charge solution that is not necessarily going to be the end solution in RTC.

Commissioner Glotfelty added that NPRR 1186 is “a big challenge,” adding that we’re trying to make a battery resource look like a coal plant in the operations world, which can’t be done. To get the benefit of the attributes of a battery on a sub- second basis on the system we need to let it act the way it acts and “we need to adapt ERCOT to that, not the other way around.”

Commissioner Glotfelty stated that this system, directed by regulators and utilities, has forced everything that is new to act like an old piece of equipment and he does not believe the benefits of batteries will be realized by doing that.

Commissioner Glotfelty asserted that ERCOT’s rules are increasing the prices and creating problems for consumers. He encouraged ERCOT to not pass this at the next ERCOT Board meeting but take it back to the drawing board and think about it.

Mr. Vegas suggested that the underlying driver for the performance of any resource and ancillary service is to ensure operational reliability. He noted there are a lot of drivers in place to maximize economic opportunity and these things are not mutually exclusive but his priority will always be reliability. He recommended leaning heavily on the expertise of operators who say there is a need for an ancillary service to perform a certain way in order to keep the grid reliable.

Commissioner Glotfelty requested that the discussions that operators share within ERCOT be shared with the Commission so there could be a discussion in an open forum, so operators are not making a decision in a vacuum that could be solved better by the market.

Mr. Vegas replied that he would be happy to bring these concerns into more open conversation. He noted there has been some critique concerning the speed at which ERCOT is moving forward with this, adding that getting the interim state of charge in place is a very urgent issue because there are limits in terms of when these changes can be incorporated into the Energy Management System (EMS) and grid management systems before the lockout and subsequent RTC development. Therefore, Mr. Vegas suggested the need to get some improvement to deal with the state of charge issue quickly, reiterating that the RTC solution is potentially different than the NPRR 1186 solution.

Commissioner Glotfelty suggested that the “landing zone” should be secondary to ensuring that the policy is right.

Commissioner McAdams suggested that, lockout issue aside, this is a strategic consideration for the system for the next 20 years and the commission doesn’t want to disincentivize longer duration batteries while incentivizing shortage duration batteries.

Mr. Vegas noted there is still quite a bit of development but expects the RTC battery issues to be before the Board and the PUCT at the end of 2023 or early 2024, with the development timetable being over the next two years, and an expected delivery in 2026, between the EMS and Market Management Systems (MMS) upgrades.

Finally, Mr. Vegas informed the Commission that ERCOT had filed a market notice earlier in the day related to the Barney Davis gas-fired facility in Corpus Christi. The generating unit submitted a notice that it would cease operations beginning in November 2023. ERCOT evaluated the local reliability impacts of this retirement and found there would be no local reliability issues with regard to transmission reliability and stability.

However, looking more broadly at needed capacity for the winter season, Mr. Vegas noted that multiple units have indicated ceasing operations, mothballing or retirement so ERCOT is going to be evaluating capacity issues for this coming winter season. If necessary, ERCOT will consider evaluating capacity contracts for units that would not be available to ensure adequate capacity is available this winter.

Commissioner Cobos asked if ERCOT’s winter evaluation will examine specific units’ winter performance and outage history and if this evaluation would include looking at demand-side solutions.

Mr. Vegas replied that ERCOT would evaluate any sort of capacity options, including load-side and demand-side, seeking the most cost-effective solution to address any capacity risk. He noted that they would intend to bring any Reliability Must Run (RMR) type contract to the ERCOT Board’s October meeting.

Commissioner McAdams added that this is going to be an expensive decision.