FERC last week approved a number of settlements for violations of NERC reliability standards by multiple registered entities, carrying more than $900,000 in penalties in all (NP21-11, et al.). Regional entities involved in the settlements include WECC, NPCC and SERC Reliability.

NERC submitted the penalties to the commission in April, filing separate Notices of Penalty for the following settlements:

• • • A $360,000 penalty assessed against Central Maine Power Company (CMP) by NPCC;
    • $420,000 against Entergy by SERC and NPCC;
    • $100,000 against Vermont Transco (VT) by NPCC; and
    • A spreadsheet NOP including a $50,000 penalty against Valley Electric Association (VEA) by WECC, and a settlement between SERC and the Tennessee Valley Authority carrying no monetary penalty.

NERC also submitted two NOPs relating to violations of the Critical Infrastructure Protection (CIP) standards. Details of those violations, including the REs and utilities involved, were not disclosed, in accordance with FERC and NERC policy on the treatment of such information announced last year. (See FERC, NERC to End CIP Violation Disclosures.) The commission indicated last Friday that it would not review the NOPs, leaving all of the settlements intact.

CMP Fails Assessment Test

NPCC’s settlement with CMP concerns two violations of TOP-001-4 (Transmission operations). Both violations involve requirement R13, which mandates that transmission operators ensure a real-time assessment is performed at least once every 30 minutes.

A real-time assessment requires both a real-time contingency analysis (RTCA) and a state estimation. CMP uses both of these data points, along with actual megawatt flows, generation output, voltage profiles and equipment status to complete the assessment.

In the first incident, which occurred on Sept. 5, 2019, CMP lost communication with 10 substations, nine of which are part of the bulk electric system, after a communication cable was severed at 8:56 a.m. Within minutes, the system operator noticed that the state estimation had not been completed successfully and notified CMP’s operations support group (OSG).

The OSG began to monitor the status of both the state estimation and RTCA but did not discuss the real-time assessment with the system operator. Likewise, the system operator did not bring up the assessment either, even when it notified the OSG about the loss of contact with the substations at 9:35 a.m.

At 10:08 a.m., the RTCA failed to complete. At this point a real-time assessment could not be done because neither a state estimation nor the RTCA was available. OSG staff managed to restore the RTCA long enough for it to complete once, but not until 10:57 a.m., 49 minutes after the initial failure of the RTCA; as a result, CMP missed the deadline to perform a real-time assessment by 19 minutes.

After performing the RTCA, OSG personnel finally notified the system operator that the RTCA had not been solved since 10:08 a.m. The system operator immediately informed its reliability coordinator, which was aware of the initial communication failure but not of the issues with the RTCA. The RC then began to perform real-time assessments on behalf of CMP and continued to do so until 3:34 p.m. despite CMP restoring its RTCA capability more than three hours before.

The second incident occurred on Feb. 12, 2020, after an evacuation drill that involved switching from CMP’s primary control center to the backup. Beginning at 7:16 a.m., during the attempted switch, the utility’s emergency management system (EMS) failed and restarted several times. The final failure occurred at 7:36 a.m., and the EMS was not fully restored until 8:53 a.m.

Because the system had been temporarily restored several times, the system operator and control room supervisor assumed that the RTCA, and hence the real-time assessment, had been performed until 7:36 a.m. As a result, they did not ask ISO-NE for help performing the real-time assessment until 8:04 a.m.

However, they were unaware that the EMS needed to be online for at least five minutes before the RTCA could be performed. Because the EMS had never been on long enough during the relevant time, no RTCA was done and the real-time assessment was not completed between 7:16 a.m. and 8:04 a.m., 18 minutes past the deadline.

No harm is known to have occurred as a result of either violation; system conditions during both incidents were normal and no emergencies occurred. However, NPCC observed that “the failure to ensure a real-time assessment [was] performed … [increased] the risk that system operators could be unaware of changing system conditions … that could result in instability, uncontrolled separation, or cascading outage.”

In assessing the penalty amount, NPCC pointed to the compliance history of CMP and its parent Avangrid. Not only does this case involve two separate incidents, but NPCC assessed a $450,000 penalty in 2019 against three Avangrid utilities, including CMP, for violations of the TOP standards (NP20-4). (See FERC OKs $450,000 Avangrid Penalty.)

Mitigation actions by CMP and Avangrid include taking “steps designed to improve [their] operation’s culture of compliance” by reorganizing the operations department to ensure better interaction with compliance staff. CMP also revised its internal procedures to include strategies for system operators to mitigate the loss of state estimation and RTCA functionality, and to require OSG personnel to “notify system operators immediately upon discovery of potential reliability issues with the [state estimation] and/or RTCA.”

SERC Alleges Entergy Voltage Violations

Entergy’s infringement involves violations of VAR-002-4 and its predecessor VAR-002-2b (Generator operation for maintaining network voltage schedules). Both were self-reported: the first by EntergyNUC, which manages nuclear plants in the SERC region, in November 2017; the second by EntergyFHG, which runs fossil and hydroelectric generation in SERC, in July 2019.

EntergyNUC disclosed 1,399 instances of noncompliance at eight generation units, spanning almost three years. The utility initially discovered compliance issues at the Arkansas Nuclear One station, with additional problems found during a subsequent extent-of-condition assessment at Grand Gulf Nuclear Station, Indian Point Energy Center, and three other facilities in both the SERC and NPCC footprints.

The issues discovered mainly involved operating outside of the voltage schedule; for example, Arkansas Nuclear One on 193 occasions “exceeded its voltage schedule, did not recover within the specified timeframe, and failed to notify its [transmission operator].” Other violations included Grand Gulf Nuclear Station not requiring operators to monitor voltage at all times, which is mandatory under the standard, and the Waterford 3 station failing to incorporate an update to its voltage schedule into its operations procedures and computer systems.

EntergyFHG’s violations included 378 noncompliance instances at 17 facilities, with a duration of five years. The issues were discovered during an extent-of-condition review ordered in response to EntergyNUC’s previously discovered compliance issues. Most of the issues occurred during 2018 and 2019, but two facilities in Louisiana were discovered to have instances of noncompliance dating back to 2014.

SERC found that EntergyNUC’s violations posed a “serious” risk to the bulk power system, while EntergyFHG’s posed a moderate risk. The regional entity identified the root cause of the former entity’s infringement as “organizational siloes and ineffective processes and procedures,” since each nuclear facility was responsible for its own compliance program with no coordination or sharing of best practices and lessons learned. In the latter entity, the root cause of the issues was found to be a lack of “sufficient internal controls to ensure proper execution of its compliance program.”

According to the settlement agreement, SERC will pay 17.4% of the monetary penalty to NPCC. Entergy’s mitigation measures include enhancing the compliance programs at both EntergyFHG and EntergyNUC through improved internal controls and communication. Entergy also implemented a common VAR-002 process for both entities.

Tree Runs Afoul of VT’s Lines

NPCC’s case against VT comprises two violations of FAC-003-4 (Transmission vegetation management). Requirement R2 of the standard mandates that transmission owners (TO) and generator owners (GO) prevent vegetation encroachments into the minimum vegetation clearance distance (MVCD) of their applicable lines, while R6 requires TOs and GOs to perform full vegetation inspections of transmission lines at least once per calendar year.

VT infringed on R2 when a tree grew into the MVCD of a 345 kV transmission line, eventually contacting the line and causing it to trip and lock out of service. That breach was later found to have resulted from the R6 violation, due to VT’s failure to include that line — and a parallel and redundant line located beside it — in the database used for its vegetation management program. That exclusion meant that VT did not perform the required annual inspection on the lines, allowing the tree to encroach on the MVCD.

NPCC found that the R2 violation posed a moderate risk to the BPS, as did the R6 violation. VT mitigated the infringements by removing the violation from the lines’ right-of-way and adding the lines to its vegetation management program. The utility also performed an extent of condition review and found no other lines were missing from the program’s database.

WECC Finds VEA Ratings Variations

NERC’s last filing, the spreadsheet NOP, covers WECC’s settlement with VEA for $50,000 over infringing on FAC-008-3 (Facility ratings), along with SERC’s settlement with TVA over a violation of PRC-001-1 (System protection coordination).

WECC discovered VEA’s potential violations during a compliance audit in January 2019. After sampling seven of VEA’s transmission facilities for a detailed review, WECC found a number of discrepancies. For instance, one of the 138 kV transmission lines had three different facility ratings in VEA’s records. WECC traced this inconsistency to a failure by VEA to communicate internally when a new rating was released for one element at a switching station.

VEA’s database also did not match its one-line diagrams in several places, with equipment represented in one missing from the other. The utility attempted to revise its database during the audit to eliminate the variations, but the RE still found differences between the new database and the diagrams.

The violations were found to have posed a moderate risk to the BPS, as the lack of accurate ratings “could have resulted in operating the transmission facilities above … system operating limits, potentially resulting in permanent or premature damage to the equipment.” Mitigation measures by VEA included updating its facility ratings spreadsheet and confirming equipment ratings, identifying and resolving inconsistencies with joint owners, scheduling annual reviews of the facility ratings manual and spreadsheet, and revising its training methods and manuals.

Not all of these measures were complete at the time of filing in April 2021, but WECC expected them to be finished by May 1.

TVA’s violation stems from an incident on Apr. 17, 2019, when the utility reported to SERC that a 500 kV relay at its Brownsville Combustion Turbine Plant had several failed components. TVA later expanded upon the report, informing the RE that one component had failed in 2012, while another failure dated back to 2017. Though personnel had flagged the relay for repair in both cases, TVA failed to repair or replace it until 2019.

The utility reported the deficiency as a violation of PRC-001-1, which requires generator operators to notify the transmission operator and balancing authority “if a protective relay or equipment failure reduces system reliability;” GOPs are also required to “take corrective action as soon as possible.”

SERC determined the root cause of the violation to be management oversight; TVA failed to implement a documented process and internal controls to ensure the relevant reports were reviewed and actions were taken. The RE noted that TVA has taken a range of mitigation actions, including updating its compliance procedures, evidence checklists, and site notification matrix to account for relay failures; providing training on revised procedures; and reviewing the system to ensure there are no other unresolved or unreported equipment issues.

TVA is not subject to monetary penalties due to a D.C. Circuit Court of Appeals ruling that FERC and NERC cannot impose such penalties against federal entities.