A contemplated system revamp at ERCOT, the organization that oversees the state’s primary power grid, could cost millions up front — but also end up benefiting Texas ratepayers in the long-term, even after taking the cost into account.

That’s the conclusion of two expert reports issued recently to the Texas Public Utility Commission, the state regulatory agency charged with eventually deciding whether to move forward with the system overhaul.

Staff at ERCOT — the Electric Reliability Council of Texas — authored one of the reports. ERCOT’s Independent Market Monitor authored the other. Both were submitted to the PUC on June 29.

At issue is a contemplated system revamp that would significantly alter ERCOT’s operation of the wholesale electricity market. The twin reports suggest the changes would improve system efficiency, which, in turn, would result in market savings.

PUC Chair DeAnn Walker last week said she had additional questions about the proposed changes, including questions regarding the potential implementation costs to market participants (other than ERCOT itself). Ms. Walker directed interested parties and PUC staff to continue working through the issues during the summer.

PUC Chair DeAnn Walker

Currently ERCOT operates a day-ahead market in which it contracts for the capacity of generation plants for stand-by power. But ERCOT also manages a separate real-time market under which it procures power in 5-minute intervals to ensure grid stability on an ongoing basis.

The contemplated changes would merge these two functions, allowing ERCOT systems to more efficiently deploy lower-cost energy on a real-time basis while reserving higher-cost generation units for standby capacity.  Referred to as “co-optimizationby ERCOT’s cognoscenti, the changes — if authorized by the PUC — would be among the most ambitious by ERCOT since it completed its nodal market system in 2010. (You can read more about the nodal system in TCAP’s Deregulated Electricity in Texas, found here.)

ERCOT has estimated the cost to implement the co-optimization project at $40 million. But the organization also said the changes would result in significant operational benefits — for instance, the changes should allow the grid operator to more efficiently manage transmission line congestion and, as a consequence, allow it to focus more attention on other reliability issues.

In its report to the PUC, ERCOT staff estimated the proposed changes would reduce generation production costs by up to $13.4 million per year and reduce generator revenues by up to $224.5 million per year.  This second figure is important because one method to assess changes in consumer costs is to evaluate changes in generator revenues, according to ERCOT staff. However, the potential loss of generator revenue also could make the co-optimization plan a target of the state’s largest wholesale power providers.

In its separate report to the PUC, ERCOT’s Independent Market Monitor concluded that co-optimization could reduce wholesale energy production costs by $10 to $12 million annually, lead to an even greater reduction in energy costs and result in other dramatic savings.

The independent market monitor found a significant reduction in energy prices because co-optimization shifted energy production away from higher-cost units and toward lower-cost units, because it more efficiently relieved transmission-line congestion and because it led to the improved deployment of energy ramping-up and ramping-down capabilities among generators. It based its report on a modeled analysis that assumed 2017 market conditions, and said actual savings likely would be greater. The IMM recommended that the PUC authorize the changes.

If the PUC follows the recommendation and ERCOT implements necessary rules changes in advance, technicians still would need four or five years to get the new systems up and running, according to ERCOT staff estimates.

PUC chair Walker last week noted that the cost to ERCOT to create the new systems would not be the only cost. “”Right now, ERCOT is saying, I think, $40 million [for implementation of co-optimization], but we know that the other parties are going to have to change their systems, and I want to understand what the total cost is,” she said.

The PUC likely take the issue up again on Aug. 9.

— R.A. Dyer