In December, the Public Utility Commission agreed to move forward with many changes relating to ERCOT operational issues.
More than 4 million Texans lost power during the February weather emergency and more than 200 lost their lives. Since then, the Texas Public Utility Commission has conducted multiple workshops and called upon market participants to provide recommendations for market changes — all with the goal of making significant reforms to help avoid future outages.
In December, the Commission agreed to move forward with many of the changes it had so far considered. For the most part, these were those relating to ERCOT operational issues. However, the commissioners over the last several months also have debated larger structural issues relating to incentivizing new investments in the ERCOT market. As discussed below, for the most part they have reached no agreement on those issues, and instead have put off decisions related to them until a later date.
OPERATIONAL DESIGN ISSUES: CONSENSUS
The goal all along had been to get needed reforms in place before the end of the year. Toward that end, commissioners had outlined an aggressive market-redesign schedule that included workshops on October 21, November 4, November 18, and finally on December 2. During that final meeting, the commissioners agreed to a number of important changes. As noted above, these related to operational design issues.
We have summarized many of those consensus issues below. (For more information about some of the concepts and terms, below, see the online glossary found here.)
High System-Wide Offer Cap
The “HCAP” represents a price limit on electricity offers in the ERCOT administered wholesale power market. The commission set the High System-Wide Offer Cap at $5,000 per megawatt hour, beginning on January 1. This is a change from the current HCAP of $9,000.
Operating Reserve Demand Curve
The commission agreed to set a future rulemaking on making parameter changes to the ORDC, which is an automated system employed but ERCOT that adds additional dollars to price offers by generators during scarcity conditions. The adders increase gradually — that is, on a “curve” — in tandem with increases in scarcity conditions.
Minimum Contingency Level
Measured in megawatts, the Minimum Contingency Level sets the scarcity level at which the ORDC kicks in. On December 2, the Commission agreed to set the “MCL” at 3,000 megawatts. This represents an increase from the current MCL of 2,000 megawatts.
The commissioners directed ERCOT to change Demand Response compensation amounts such that they employ prices derived from the granular nodal system, as opposed to the broader zonal system. (For more about demand response, and the zonal and nodal markets, see the glossary found here.)
The commission agreed to reopen its energy efficiency rules with an eye toward improving system reliability.
Emergency Response Service (ERS) Reform
Emergency Response Service is an electricity service procured from electricity users that — as per advance agreement with those users — ERCOT can curtail to avoid system-wide outages. Customers that provide ERS receive payment in exchange for curtailing their power usage. The commission agreed that ERCOT should deploy ERS prior to declaring an emergency alert. The commission also agreed to allow for greater variability in procuring ERS on a seasonal basis. ERCOT is already pursuing these changes.
New Ancillary Services
Ancillary Services are services procured by ERCOT to help it maintain system reliability. The owners or operators of generation or load provide ancillary services. The Commission agreed that ERCOT should continue development of new categories of ancillary services known as “Fast Frequency Response,” “ERCOT Contingency Reserve Service” and “Voltage Support.” Fast Frequency Response, however, will not come online prior to May 2022; and ERCOT Contingency Reserve Service will not see deployment before the first half of 2023. Voltage Support remains in development.
BROADER MARKET ISSUES: NO CONSENSUS
The commissioners, however, remained divided on a number of broader market proposals, including one by Chair Peter Lake for a “Load Serving Entity Capacity Obligation.” The proposal would create capacity obligations — that is, requirements to contract in advance for reserve capacity — for retail electric providers, municipal-owned utilities and other “Load Serving Entities.” Chair Lake has pushed hard for the proposal, but without swaying his colleagues.
In prior discussions, commissioners Will McAdams and Lori Cobos had proposed alternative constructs. Commissioner McAdams, for instance, suggested a “Dispatchable Portfolio Standard” that he envisioned working in a similar fashion as the state’s Renewable Portfolio Standard. Commissioner Cobos suggested a “Strategic Reserve Service,” which she described as an annual auction for resources to be held in reserve to help during shortage conditions.
Prior to the December 2 meeting, Chair Lake had filed a memo updating his earlier LSE Capacity Obligation proposal. The memo captured many of the preliminary agreements among the commissioners on market redesign questions, and called upon the Commission to “quickly narrow the scope of its efforts, eliminate unacceptable proposals, and focus on refining the concepts that will bring reliability to our grid.” Commissioner McAdams, however, expressed displeasure during the December 2 meeting that his Dispatchable Portfolio Standard proposal was not included in the Chair’s memo, while Commissioner Jimmy Glotfelty said the commission did not have enough information to move forward. Chair Lake said that while more analysis and due diligence is important, action is even more important. He also appeared to dismiss concerns about how the various proposals might increase electricity supply costs, which in turn could hamper economic development in the state.
On these broad market design proposals, the commissioners achieved only one item of consensus. All four commissioners agreed to support those based on load-side obligations rather than supply obligations. With respect to the three load-side proposals under discussion – the LSE Capacity Obligation, the Dispatchable Energy Credit proposal and some sort of backstop reliability service – the Commission will take further public comment. It also requested that the commission’s consultants, the Brattle Group, perform a detailed economic analysis of each proposal. You can read more about these proceedings in Project No. 52373, Review of Wholesale Electric Market Design, on the PUC website at this link.
The Commission on December 2 also adopted ERCOT’s proposed budget for the two upcoming fiscal years. The budget holds flat for two years the System Administrative Fee, which is the fee on energy that funds ERCOT. However, the adopted budget also includes a significant deficit, which means that ERCOT will have to dip into other revenues to fund its operations.
The PUC Project Number for ERCOT budget consideration is Project No. 38533 – PUC Review of ERCOT Budget. Find out more here.