FERC has approved settlements between East Kentucky Power Cooperative, Ohio Valley Electric Corp. and Seminole Electric Cooperative, and their respective regional entities, carrying monetary penalties totaling $185,000 for violations of NERC’s reliability standards.

NERC filed the settlements Sept. 30 in its monthly Spreadsheet Notice of Penalty (NP25-18), along with a separate, nonpublic SNOP for violations of the ERO’s Critical Infrastructure Protection standards and a $1.25 million settlement between SERC and Entergy. (See FERC Approves $1.25M SERC-Entergy Settlement.)

Commissioners said in an Oct. 30 filing that they would not further review the settlements, leaving the penalties intact. Chair Laura Swett and Commissioner David LaCerte, sworn in Oct. 20 and Oct. 27, respectively, did not participate.

EKPC’s Ratings Violations

EKPC settled with SERC Reliability for $95,000 over a violation of FAC-008-5 (Facility ratings). According to the SNOP, the utility self-reported the violation to SERC in April 2022, indicating that it had discovered two instances in which the utility “failed to have facility ratings that are consistent with” its facility ratings methodology as required by requirement R6 of the standard.

In the first instance, EKPC learned during a review of survey data on Sept. 27, 2021, that the transmission line on the Flemingsburg-Goddard 138-kV circuit, built in 2006, was too close to a distribution line below it because the distribution poles had been built five feet higher than the design indicated.

EKPC had discovered part of the improper construction in 2012 and lowered the maximum operating temperature of the transmission circuit from 212 degrees F to 175 degrees. However, the 2021 survey indicated that other sections of the distribution line had been built outside of specification, along with a mulch pile beneath the transmission line that had gone undetected in 2012. As a result, the utility further reduced the circuit’s maximum operating temperature to 140 degrees.

In the second case, the utility discovered in December 2021 that a set of 795 aluminum conducted (AAC) line jumpers at its Boone substation had been misidentified as 795 aluminum conductor steel reinforced (ACSR) line jumpers. AAC jumpers are limited to 332 MVA at an ambient temperature of 32 degrees, while ACSR jumpers are limited to 346 MVA, the rating EKPC had assigned the Boone substation. The utility derated the facility to 332 MVA.

After discovering these issues, EKPC began an extent of condition assessment on March 1, 2022, that included physical walk-downs of all substations to which FAC-008-5 is applicable. The utility identified incorrect equipment ratings at four substations that required facility derates ranging from 15-17%. EKPC also identified incorrect facility ratings at 40 transmission line facilities of up to 92% over the correct ratings, the majority of which were caused by line-to-ground and crossing clearances. The findings resulted in derates at 16 facilities.

In addition to re-rating the facilities, EKPC’s ongoing mitigation activities include updating its change management control to require inspecting one quarter of its substations each year until the entire system has been evaluated, starting in 2023. The utility has also developed processes to ensure facilities are inspected as they are built to “verify construction was completed according to the plans and specifications,” and to ensure facility ratings databases are updated correctly. These mitigations are expected to be completed by Dec. 26, 2026.

SERC assessed the violation as a moderate risk because of the number of instances reported, but observed the violation caused no operational issue or harm to the system. The RE awarded penalty credit for EKPC’s cooperation through the enforcement process and its agreement to settle the violation, but withheld credit for self-reporting because the notification occurred after the utility received an audit notification letter.

Reporting Mishaps at OVEC

OVEC’s settlement with ReliabilityFirst stemmed from a violation of requirement R2 of VAR-002-4.1 (Generator operation for maintaining network voltage schedules), which requires generator operators to notify transmission operators of deviations from the voltage or reactive power schedule provided by the TOP. The RE discovered the violation during a compliance audit conducted from Sept. 12-15, 2022.

RF’s audit team reviewed data for eight days across nine units sampled from OVEC’s Kyger Creek and Clifty Creek plants. For each date, auditors found the units spent multiple hours above OVEC’s voltage schedule and reactive power threshold that required it to notify its TOP, PJM, according to PJM’s manual. Despite the utility also receiving voltage deviation alarms of varying severity levels, it did not notify PJM as required. OVEC acknowledged to auditors that “such alarms went off frequently and were disregarded.”

OVEC conducted an extent of condition review following the audit covering about one-and-a-half years of voltage schedule deviation data, confirming that all units “were regularly outside of the restrictive bandwidths of its voltage schedule, and that it did not make the required notifications.”

RF concluded that the cause of the noncompliance was OVEC personnel misunderstanding their obligations under PJM’s manual and VAR-002-4.1. To mitigate the violation, OVEC has updated its generator reactive capability curve data and entered a new voltage schedule in PJM’s eDART reporting tool, and developed and trained system operators in a new bus voltage maintenance procedure.

SEC Settles over Multiple Issues

The last settlement in the SNOP was between SEC and SERC, covering violations of four separate standards with a collective $35,000 penalty. SEC self-reported all infringements.

In the first violation, SEC notified SERC on Sept. 28, 2023 that it was noncompliant with PRC-019-2 (Coordination of generating unit or plant capabilities, voltage regulating controls, and protection). Requirement R2 mandates that generator owners and transmission owners must coordinate voltage regulating system controls of applicable facilities within 90 days of any system, equipment or setting changes that will affect the voltage regulating systems.

Three instances of noncompliance were reported. In the first, SEC discovered during a 2023 system review that it had upgraded four relays and modified their protection settings in 2019 without performing a coordination review within the required time. SEC later discovered evidence that it had actually performed the coordination after all, so SERC dismissed this incident as a violation.

The second instance involved the upgrade of automatic voltage regulator limiters at five units in April and May of 2023, with coordination not completed until that October. Finally, SEC discovered in August of 2023 that it had upgraded relays on two units in 2019 but did not perform the coordination. This was completed in October 2024.

SEC’s next infringement involved PRC-023-4 (Transmission relay loadability), with the utility identifying three instances “where protective relaying on its transmission lines was set to operate at or below 150% of the highest seasonal facility rating of the circuit,” in violation of Requirement R1 of the standard. SEC discovered the first instance during an internal review prior to an audit, and the others in a subsequent extent of condition review.

SERC determined that the violation began on July 1, 2019, when SEC updated the first transmission line’s facility rating without updating the protective relay setting, and ended Jan. 6, 2025, when the utility updated relay settings for all three relays. The RE attributed the violation to deficient processes for internal coordination and communication.

Another violation involved PRC-027-1 (Coordination of protection systems for performance during faults). SEC notified SERC on Sept. 25, 2023, that it had not used the proper internal processes when it developed new protection system settings in recent years. Instead, the utility found that protection engineers “used generally accepted industry practices and guidelines.”

SEC reviewed protection systems developed since April 2021, discovering eight total setting changes that did not follow its procedures, beginning as early as May 17, 2021. To address the problem, the utility reset its protection system settings according to its documented procedure; this was done by June 13, 2025.

Finally, SEC notified SERC on July 5, 2024, that it was noncompliant with TOP-001-6 (Transmission operations). The utility indicated that when its energy management system went down for two hours and 10 minutes on July 6, 2023, SEC failed to ensure that a real-time assessment was performed at least once every 30 minutes, as required by requirement R13 of the standard.

The issue was caused by SEC inadvertently activating firewalls on its servers that blocked control room communication with the EMS, leaving operators unable to perform the RTA. SEC reviewed the past three years of EMS logs for any other outages of greater than 30 minutes and found none, concluding there were no other instances of operators being unable to complete the RTA.

To mitigate the violation, SEC ran the RTA as soon as it regained EMS access, conducted a cause analysis to determine the contributing factors, and developed internal controls and processes to prevent similar events.