ERCOT 4.0 Shapes Path Forward for the Grid Operator

ERCOT CEO Pablo Vegas has gone public with the grid operator’s internal terminology that is shaping the market’s path forward, defining it for his Board of Directors and stakeholders. 

“This represents more than just the branding of current activities that we have underway,” Vegas told the board during its June 23-24 meeting. “It really represents a distinct new phase in the ERCOT market. It also provides a strategic lens to look at the priorities and the initiatives that we’re going to be investing in to make sure that we continue to deliver on our mission, which is getting more complex and more dynamic every year.” 

Labeled “ERCOT 4.0,” the construct builds on previous versions of the grid operator’s market and its transitions: 1.0 (original formation in the 1970s), 2.0 (deregulated competitive markets and the zonal market in 1999) and 3.0 (the nodal market in 2010). 

“Each of these transitions was driven by a combination of either technology changes, regulatory changes [or] market-driven forces. ERCOT 4.0 reflects this transformation that’s underway right now,” Vegas said. 

He said ERCOT 4.0 is defined by the exponential growth in system complexity and the convergence of three major drivers: the rapidly changing resource mix, significant and unpredictable load growth, and technology-driven operational changes, such as artificial intelligence advances and high-frequency data access. 

“This is changing how we forecast. This is changing how we operate. This is changing how we plan,” Vegas said. “The convergence of these three things … are the core underpinnings of what ERCOT 4.0 looks like for the next generation of ERCOT. This is a new paradigm.” 

Vegas said the grid operator will have to evolve its planning assumptions “to account for the uncertainty and the variability that we’re seeing across both supply and demand.” He said grid operations will have to become more adaptive and market mechanisms will have to be re-evaluated to ensure “those signals support long-term system reliability as well as short-term market efficiencies.” 

“Probably most critically of all, our workforce is going to have to be equipped to lead in a system that is increasingly software-defined, data-rich and constantly changing,” Vegas said, noting the grid operator is investing in professional development and other tools so the team can “operate and lead in this new reality.” 

Staff are focused on innovation to transform the organization and maintain operational excellence in a more complex system. 

“It’s a huge opportunity to reinforce our leadership in the energy economy here in Texas,” Vegas said. 

He closed his comments by tying ERCOT’s 2025 Innovation Summit in May to ERCOT 4.0. The summit drew more than 450 attendees, with more than 400 other people livestreaming the event. 

“It was an opportunity to really showcase innovation efforts, not only within ERCOT, but [also] what’s happening in transformations around the world and around the United States, bringing people together to talk about the most complex issues that we’re dealing with, learning from each other, establishing networks of communication that are going to be helpful as we continue to work on solving these problems together.” 

Board Approves $1.07B 2-year Budget

The board approved a two-year budget of $485 million for 2026 and $585 million for 2027, totaling $1.07 billion. However, the budget includes a system administrative fee of 61 cents/MWh, down 2 cents from the current fee. 

Both changes go into effect in January 2026. 

Board Chair Bill Flores, who also chairs the Finance and Audit Committee, acknowledged that the biennial budgets are “substantial increases from where we are today.” 

“But as we all recognize,” he said, “because of the mandates promulgated by the legislature in the last two legislative sessions, as well as the increasing complexity and the dynamic nature of this market, as well as the focus on reliability, the cost of running the organization is higher than it was before.” 

He said the budget includes “appropriate” funds and staff to address ERCOT’s strategic objectives and comply with the financial corporate standard and associated financial performance measures. The budget also funds the Independent Market Monitor and compliance with Texas Public Utility Regulatory Act and NERC obligations. 

Flores said the budget assumes the administration fee can be kept flat for up to six years. 

RTC+B Market Trials Begin

Market trials for the Real-time Co-optimization+ Batteries (RTC+B) project are underway and proceeding well, staff told the board. 

Matt Mereness, senior director of market operations and implementation, said ERCOT has received the final deliveries of vendor code and completed two operating day end-to-end tests of systems and integration. He said the test environment was deployed weeks ahead of its May 5 start date, and a first round of defects was fixed and redeployed later in the month. 

After establishing connectivity with market participants and testing submissions, the RTC+B project will begin parallel production trials July 7. Mereness said market trials will focus on frequency control tests in the September-October time frame.  

“All the participants will put in reasonable offers that represent [a percentage] of their costs, and we’ll start [dispatching]. That’ll be the real-time co-optimization,” Mereness said. “They’ll have [ancillary service] offers in, and ERCOT will start to print prices and signal where [participants] should go, but no one will go there. Here’s the solution, but don’t follow it.” 

The project is set to go live Dec. 5. 

Staff Responds to IMM Report

ERCOT staff responded to the IMM’s recent State of the Market report for 2024, saying, “Overall, it’s a very good and well-written report.” 

“There are definitely some things we agree with and some other things that we may be in disagreement,” said Keith Collins, vice president of commercial operations. 

He said staff are aligned with the IMM’s comments on improvements to ERCOT contingency reserve service (ECRS), which reduced the product’s average price from $76.77/MWh to $9.62/MWh, and the effective load-carrying capability in the grid operator’s Capacity, Demand and Reserve report. 

“There are a few recommendations or items that the IMM pointed out that we believe we’ve already addressed,” Collins said. 

Responding to the IMM’s recommendation that ECRS include a forecast trigger, he said ERCOT has a three-part trigger for the product. Collins said a trigger that looks forward at the net load ramp addresses that need. 

In its report, the IMM continued to recommend that the grid operator reconsider its policies for procuring and deploying ECRS. (See ERCOT ESRs, Solar Production Lessen AS Costs.) 

ERCOT also disagreed with the Monitor over non-spinning reserves’ duration. The grid operator wants four hours, while the IMM favors a one-hour duration. 

Two Tx Projects Approved

The board approved a pair of Oncor transmission projects in West Texas with combined total costs of $974 million. 

The $855 million Delaware Basin Stage 5 project addresses reliability concerns and accommodates “significant and rapid load growth” in the petroleum-rich area. Oncor will build 220 miles of transmission lines in creating an import path to serve load now that the basin’s peak demand is greater than a 5,422-MW threshold. (See “Oncor $855M Project Endorsed,” ERCOT’s TAC Extends Duration of Ancillary Services.) 

The $119 million, 138-kV Tredway Switch and 138-kV Expanse-to-Tredway project entails upgrading 29 miles of lines and updating other facilities and infrastructure to address reliability issues. Oncor expects to finish the project in December. (See “TAC Endorses $119M Oncor Project,” ERCOT’s TAC Endorses Congestion Management Plan.) 

Both projects were selected by ERCOT’s Regional Planning Group from other alternatives. As Tier 1 projects with costs exceeding $100 million, they require board approval. 

With little discussion, the board also approved: 

• • the third phase of the Aggregate Distributed Energy Resource (ADER) pilot project, which enables a new participation model for resources providing ancillary services but that are not in the five-minute real-time energy market. The first two phases limited total registered capacity of all ADERs to 80 MW for energy and 40 MW for non-spin and ECRS; staff proposed increasing the limits to 160 MW and 80 MW, respectively, for Phase 3. (See “TAC Endorses ADER Doc,” ERCOT’s TAC Extends Duration of Ancillary Services.) 
  • revisions to ERCOT’s methodology used to calculate the maximum daily resource planned outage capacity. The modifications are intended to provide sufficient outage capacity compared to historical levels by applying a risk-based construct for outages more than seven days ahead. (See “Outage Capacity Changes,” ERCOT’s TAC Extends Duration of Ancillary Services.) 
  • a real-time market correction of $81,858 to market participants after a routine software update changed an energy management system setting to its default value, causing a stricter limit on a generic transmission constraint (GTC). That led to the activation of a post-contingency overload on the GTC, affecting dispatch optimization that resulted in a maximum shadow price of $5,251/MWh over March 28-29. The first operating day was corrected within a two-day business deadline, but not the second day. The maximum absolute value impact to counter-parties was $99,580. 

Board Loses 2 More Directors

Chair Flores opened the meeting by announcing that the two most recent independent directors, Alex Hernandez and Sig Cornelius, have resigned to pursue “new opportunities” in the ERCOT market. State law requires the 12-person board’s eight independent directors to not have fiduciary duty or assets in the grid operator’s territory. 

Hernandez and Cornelius were appointed to the board in January. (See ERCOT Fills out Board with 2 New Directors.) 

That leaves the board with three vacancies. Bob Flexon resigned in December 2024. 

Flores said the board’s selection committee is working to fill the three vacant seats. He said the goal is to have them in place by the board’s September meeting. 

Protocol Changes

The board approved a nodal protocol revision request (NPRR1282) and its associated Nodal Operating Guide revision request (NOGRR277) that provides longer-duration ancillary services and state-of-charge (SOC) parameters in advance of the RTC+B project’s deployment in December. 

The NPRR updates duration requirements to 30 minutes for regulation service and responsive reserve service and one hour for ECRS. It also revises reliability unit commitment studies’ requirement to one hour for all ancillary services, excluding fast frequency response. (See ERCOT’s TAC Extends Duration of Ancillary Services.) 

ERCOT supported the measure, saying there is a need for a four-hour ancillary service to cover periods when deploying non-spin. Dan Woodfin, vice president of system operations, said staff analysis revealed that when non-spin is deployed, “we’re basically having to cover the gap because of either an extended forecast error or units that trip offline.” 

“We can deploy reserves, but then we need to last longer until we can get the next generation committed to cover the gap or until the net load goes down,” he said. 

ERCOT is also developing dispatchable reliability reserve service as a four-hour AS product to cover risks. 

Jupiter Power’s Caitlin Smith, who chairs the Technical Advisory Committee, said the change conflates “duration” with SOC, “a misapplication of fundamental [energy storage resource] concepts [that] results in a drastic departure from current ERCOT standards regarding duration and state of charge.” 

The board agreed with ERCOT’s commitment to revisit the NPRR once RTC+B becomes part of the market. 

The directors also endorsed NPRR1229, which creates a process to compensate market participants when a constrained management plan or ERCOT-directed switching instruction trips a generator that otherwise would have remained online. (See ERCOT’s TAC Endorses Congestion Management Plan.) 

The consent agenda of unopposed protocol changes at TAC included five additional NPRRs, two NOGRRs, an Other Binding Document (OBDRR), an addition to the Planning Guide (PGRR) and a system change request (SCR) that: 

• • NPRR1226: directs ERCOT to prepare and publish estimated demand response data showing aggregated state-estimated load points selected by the grid operator. Loads selected for the report will be based on periodically updated offline analysis of the frequency and magnitude of reductions observed in historical state estimator load data that are associated with LMPs, ERCOT-wide conservation appeals or other market signals. 
  • NPRR1238 and NOGRR265: introduces a new early curtailment load (ECL) category and establishes a process allowing loads to operate as an ECL so they can be accounted for differently in load-shed tables. 
  • NPRR1267: requires a large-load interconnection status report be published. The report won’t define “large load,” leaving that to NPRR1234 (Interconnection Requirements for Large Loads and Modeling Standards for Loads 25 MW or Greater). Confidential customer information on large loads will be aggregated. 
  • NPRR1271: allows Mexico’s state-owned electric utility, the Federal Electricity Commission (CFE), to opt out of a requirement to designate a user security administrator and receive digital certificates. CFE is registered with ERCOT as a transmission and/or distribution service provider, a load-serving entity and a resource entity. 
  • NPRR1276: incorporates an OBD, “Emergency Response Service Procurement Methodology,” into the protocols to standardize the approval process. 
  • NOGRR275: aligns the guide with protocol changes to eliminate scheduling center requirements for qualified scheduling entities that are not wide-area network participants. 
  • OBDRR054: creates a process by which transmission and/or distribution service providers will require market participants to successfully test retail transactions before their data universal numbering system is activated in a TDSP’s production system. 
  • PGRR125: adds language to that guide that allows an interconnecting entity or property owner to demonstrate compliance under the Lone Star Infrastructure Protection Act should it have a subsidiary or affiliate that falls under the act’s citizenship or headquarters criteria. The subsidiary must not have direct or remote access to or control of the project, the project’s real property, resource integration and ongoing operations, the market information system, other ERCOT systems or any confidential data from the systems. 
  • SCR830: implements a machine-to-machine client credentials authentication flow using OAuth 2.0, allowing for certain read-only endpoints of the GINR Rest Application Programming Interface to be exposed for authorized use.