ERCOT Needs a Minimum Reserve Margin Requirement

Since its inception over fifty years ago, ERCOT has always been unique among energy markets covered by the North American Electric Reliability Corporation (NERC). There are other Independent Service Operator (ISO) and Regional Transmission Organizations (RTO) regions who, like ERCOT, have footprints that are contained to a single state or province (California ISO, New York ISO, and the IESO in Ontario to name a few); however, there are no other ISOs or RTOs whose territory covers an entire interconnect, nor are there any other interconnects whose footprint does not extend beyond the borders of single state or province as is the case with ERCOT.

In another sign of its uniqueness, ERCOT is the only service territory in NERC that does not have any sort of minimum requirement for electric generating capacity reserve margin*. ERCOT has a reserve margin target of 13.75% but no mechanism to require its adherence, whereas other regions in North America maintain reserve margins equal to or above their target levels by requiring load serving entities (LSEs) to procure capacity. In some ISOs and RTOs, capacity is procured via a formal capacity auction, such as PJM’s Reliability Pricing Market (RPM) and NYISO’s Installed Capacity (ICAP) Market; in other ISOs and RTOs, as well as in vertically integrated balancing authority regions that are not part of an ISO or RTO, LSEs procure necessary capacity via bilateral contracts with generators. In ERCOT, since there is no reserve margin requirement, there is correspondingly no requirement for LSEs to procure capacity and thus no direct value to capacity.

ERCOT’s unique lack of a minimum reserve margin requirement has several potentially detrimental impacts on market operations. Perhaps unsurprisingly, ERCOT tends to have tighter installed reserve margins than other regions throughout NERC. This drives significantly more hours of extremely high energy prices in ERCOT than in other regions due to the combination of high demand and the scarcity of generating resources forcing the ISO to call upon demand response, emergency generation, or other expensive resources. From the start of 2022 through January of this year, there were 1,609 day ahead hourly LMPs across all North American market hubs of $500/MWh or greater; 1,311 of those 1,609 (~81.5%) $500+ prices occurred at an ERCOT market hub, including 493 of the 500 highest prices and 468 of the 469 prices at $1,300/MWh or greater**. Even the significant amount of zero-variable-cost renewable capacity that ERCOT has installed does not mitigate the scarcity pricing, during last month’s Winter Storm Heather ERCOT set an all-time high record for solar generation at 14,837 MW on January 16th, which was enough to serve nearly a quarter of ERCOT’s load, yet prices across all ERCOT hubs still averaged nearly $400 for the day and saw hourly maximums in excess of $2,000.

In addition to pricing, there are also reliability concerns driven by ERCOT’s lack of a minimum reserve margin requirement and its corresponding lack of any market for capacity (formal or otherwise). In other regions, the requirement for LSEs to procure capacity provides multiple incentives to help maintain grid reliability. The obvious impact is that LSEs in other regions have procured more capacity than is needed to serve their projected peak demand and are thus prepared to respond if actual demand exceeds projections, whereas ERCOT cannot similarly guarantee preparedness for such an event. There are also two additional less obvious, but just as important, considerations driven by ERCOT’s reserve margin policy that impact reliability related to assets’ ability to deliver power during extreme weather conditions: a lack of funding for weatherization maintenances, and the lack of a penalty for failing to deliver power. In other regions, capacity revenues provide the “missing money” needed to cover shortfalls in operating revenues driven by fixed costs and maintenance that are not allowed to be rolled into energy bids, thereby providing generation owners with the necessary capital conduct weatherization and other reliability maintenance functions; in many regions the capacity market is coupled with extreme penalties for non-performance, providing significant incentive for generation owners to use capacity revenues in service of maintaining their plant’s reliability.

In the aftermath of February 2021’s Winter Storm Uri, and the well-documented failures of the ERCOT grid during it, the Public Utility Commission of Texas (PUCT) issued a rule intended to require generators to be better prepared for weather emergencies. In the Weatherization Rule, the PUCT mandated that all generation entities “use best efforts to implement weather emergency preparation measures intended to ensure the sustained operation of all cold weather critical components during winter weather conditions…” However, this mandate is largely toothless; there is no additional funding for generation asset owners to conduct winterization maintenance, and in fact the asset owners are responsible for paying for weatherization inspections, nor is there any real penalty for failing to deliver power in a weather emergency beyond not earning energy revenues during those hours. Last year the Texas legislature passed Senate Bill 2627 allowing for the use Texas taxpayer money to help fund the construction of more gas-powered plants, but if instead LSEs were required to maintain a minimum reserve margin by procuring capacity and including penalties for non-performance, such taxpayer-funded subsidization would not be necessary.

*Reserve margin in this case is defined as the amount of additional firm capacity available on top of what is needed to serve the annual peak load. For instance, if a region had a peak load of 100 MW and it had 110 MW of firm capacity its reserve margin would be 10%: (110 MW firm capacity – 100 MW peak load) / 100 MW peak load

**All historical prices pulled from Hitachi’s Energy’s Velocity Suite Online database