Entergy must pay a $1.25 million penalty to SERC Reliability and comply with additional sanctions for an alleged violation of NERC’s reliability standards that put the Eastern Interconnection “at risk of potential voltage collapse, frequency fluctuations and possible blackout, according to a Notice of Penalty approved by FERC on Oct. 30 (NP25-17).
NERC submitted the NOP to FERC on Sept. 30; the commission said it would not further review the settlement, leaving the penalty and sanctions intact. Chair Laura Swett and Commissioner David LaCerte, who were sworn in Oct. 20 and Oct. 27, respectively, did not participate in the decision.
The settlement stemmed from TOP-001-5 (Transmission operations), which SERC alleged Entergy violated in its capacity as a transmission operator. Requirement R1 of the standard mandates that a TOP “act to maintain the reliability of its transmission operator area via its own actions or by issuing operating instructions.”
According to the settlement agreement, Entergy twice failed to appropriately react to alarms; one instance that caused a loss of load for several customers was not discovered until months after it occurred.
The first event that the utility discovered began Jan. 25, 2024, while Entergy was performing maintenance activities at the Willow Glen substation near Baton Rouge, La. These activities caused more than 3,500 alarms to trip at Entergy’s Transmission Control Center, which operators expected.
However, one of the alarms was a priority 1 notifying operators of low battery DC voltage, and TCC staff “mistook that alarm for one of the expected maintenance alarms and cleared it from the active screen without notifying the appropriate field personnel.” TCC operators are required to act within 24 hours of a P1 alarm to ensure the grid is in a safe condition, but Entergy did not take appropriate action until Jan. 29, SERC staff wrote.
On that date, TCC staff noticed that multiple remote terminal units (RTUs) in the area were offline. They dispatched investigators, who reported the issue was caused by low DC voltage at the Willow Glen station. By the following day, all RTUs had returned to service, with Willow Glen restored last.
On Feb. 21, 2024, while performing an extent-of-condition evaluation for the incident, Entergy staff discovered a similar earlier instance that had not been identified. This event occurred Oct. 24, 2023, when the TCC received a P1 alarm from the Sabine substation in Texas warning of loss of potential in the coupling capacitor voltage transformer. TCC staff did not notify field personnel at the time.
Two days later the transformer failed, causing multiple transmission line outages that affected 26 industrial customers. Three of these customers lost a total of 23.7 MW of load, while the others “experienced power quality issues” including voltage sag that caused large motors at eight sites to trip, requiring production equipment to be completely restarted. Process units at 13 sites tripped; another site had to restart its cogenerator; and a steam turbine at the final site tripped after its pumps went offline. Two generators at the nearby Sabine power station also tripped offline.
After the transformer failed, the “system responded as designed,” SERC staff wrote, with breakers opening to place the grid in a safe condition. Outage notifications were sent upon the transformer failure and the breakers tripping.
SERC considered both incidents to be part of the same violation. The regional entity blamed the issue on “ineffective management oversight, an improperly designed alarm program, lack of procedures and inadequate training.”
RE staff wrote the design of the alarm program permitted operators to experience “an exorbitant number of alarms,” receiving more than 100,000 P1 alarms alone per day on average at both the northern and southern TCCs. This constant warning prevents them from maintaining situational awareness, performing real-time assessments, working outages, and answering phone and radio calls without distraction, SERC said.
Entergy also had no written guidance on alarm generation designation, prioritization or review; no formal procedure for TCC alarm management; and no reference documentation for operators to use in day-to-day operations.
TCC operators do learn the process of identifying and addressing the different levels of alarm, SERC staff wrote, but this training only occurs once during an operator’s initial training. Entergy management “recognized the magnitude of alarms was a programmatic weakness and an error-likely scenario and failed to act to resolve the issue,” according to the RE.
SERC assessed the violation as posing “a serious and substantial risk” to grid reliability, saying that by failing to correct a known weakness, the utility had put itself and the entire Eastern Interconnection at risk of voltage collapse, frequency fluctuations and blackouts. The RE considered Entergy management’s “passive acceptance of the high volume of alarms” an aggravating factor in the penalty determination.
In addition to the monetary penalty, Entergy will have to adhere to several conditions as part of the settlement. Among these are the tracking of P1 and P2 alarms received on a monthly basis and how many were ignored, silenced or missed. Entergy must provide quarterly reports on these metrics to SERC and its chief security officer for the next two years, starting the quarter after FERC’s acceptance of the agreement.
Entergy executives must also attend quarterly meetings with SERC leadership to discuss these metrics and any other reliability issues as determined by both parties, and the RE will perform a spot check within one year of FERC’s approval.
