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NERC Violation ID Reliability Standard Req. Entity Name NCR ID

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NERC Violation ID Reliability Standard Req. Entity Name NCR ID A-1 Public Non-CIP – Compliance Exception Consolidated Spreadsheet Future Expected Reliability NERC Violation ID Req. Entity Name NCR ID Noncompliance Start Date Noncompliance End Date Method of Discovery Mitigation Completion Standard Date MRO2019021539 MOD-026-1 R3 CHI Power, Inc (CHI P) NCR10316 12/24/2018 01/23/2019 Self-Report Completed Description of the Noncompliance (For purposes On May 2, 2019, CHI P submitted a Self-Report stating that as a Generator Owner, it was in noncompliance with MOD-026-1 R3. The Entity is registered under the same NCR ID in the ReliabilityFirst (RF), of this document, each noncompliance at issue SERC Reliability Corporation (SERC), and MRO Regions, and is currently monitored under the Coordinated Oversight Program. The noncompliance included two instances and impacted only the MRO is described as a “noncompliance,” regardless of region. its procedural posture and whether it was a possible, or confirmed violation.) In the first instance of noncompliance, the Transmission Planner (TP) for CHI P’s Origin Facility (150-MW Wind Farm) sent a notification stating that the model provided by the TP was unusable. CHI P did not respond within 90 days as required by the standard. CHI P responded 30 days past the 90 day requirement which was 120 days after the notification date. In the second instance of noncompliance, the TP for CHI P’s Goodwell Facility (200-MW wind farm) sent a notification indicating possible technical concerns with the model itself or questions on how to get the simulation to run successfully. CHI P did not respond within 90 days as required by the standard. CHI P responded 15 days past the 90 day requirement which was 105 days after from the notification date. The cause of the noncompliance for both instances was that CHI P’s process lacked sufficient controls to ensure tracking the status of each request in order to meet deadlines for the TP’s written requests and notifications. The noncompliance began on December 24, 2018, when the Entity did not provide a written response to the TP’s notification regarding the submitted models, and ended on January 23, 2019 when CHI P submitted all written responses to the TP. Risk Assessment This noncompliance posed a minimal risk and did not pose a serious or substantial risk to the reliability of the bulk power system. The noncompliance was minimal because the two affected wind farms have relatively low power output (150MW and 200MW) and are not in close geographic or electrical proximity. Additionally, the two wind farm facilities are not blackstart resources, as they are not dispatchable resources, and are not associated with any Remedial Action Schemes. The duration of the noncompliance was limited to a duration of 30 days. No harm is known to have occurred. CHI P has no relevant history of noncompliance. Mitigation To mitigate instances of noncompliance, CHI P: 1) submitted its written responses to the TP’s notifications; 2) ensured that the software tracking tool, used to track all the TP’s data requests, is functional and current to facilitate monitoring and tracking of the requests and up to date with all notifications received; and 3) created a group email distribution list for modelling requests which is used by all TPs to submit their modelling requests. The TPs were directed to use this group email for any notifications, or requests for clarifications sent to TP. This email is accessible by a number of people in the NERC Compliance group to ensure everyone has access to the status of a notification. Last Updated 05/28/2020 1 A-1 Public Non-CIP – Compliance Exception Consolidated Spreadsheet Future Expected Reliability NERC Violation ID Req. Entity Name NCR ID Noncompliance Start Date Noncompliance End Date Method of Discovery Mitigation Completion Standard Date MRO2019021838 EOP-005-2 R11 Dairyland Power Cooperative (DPC) NCR00979 07/01/2017 05/09/2019 Compliance Audit Completed Description of the Noncompliance (For purposes During a Compliance Audit conducted from April 15, 2019 through April 25, 2019, MRO determined that DPC, as a Distribution Provider, Transmission Owner, and Transmission Operator (TOP), it was in of this document, each noncompliance at issue noncompliance with EOP-005-2 R11. is described as a “noncompliance,” regardless of its procedural posture and whether it was a It was discovered that four out of 42 Transmission/Electrical Maintenance personnel did not have at a minimum, two hours of training every two calendar years for the performance of unique tasks possible, or confirmed violation.) associated with the Transmission Operator’s (TOP’s) restoration plan that are outside of their normal tasks as required by EOP-005-2 R11 (and EOP-005-3 R9). DPC developed, scheduled, and delivered learning activities to the DPC Electrical Maintenance and Transmission Maintenance groups, but four staff members missed the training because they were not present on those days for various reasons such as external training, vacations, or sickness. The cause of the noncompliance was that DPC staff did not properly interpret EOP-005-2 R11, and assumed the requirement was meant to ensure training was delivered to the field switching groups identified. The interpretation was to ensure the training was delivered to each field switching group every two calendar years, but not necessarily each individual person within the groups. The noncompliance began on July 1, 2017, when the training should have been provided to all Transmission/Electrical Maintenance personnel, and ended on May 9, 2019, when all of the Transmission Maintenance/Electrical Maintenance staff completed the required training. Risk Assessment This noncompliance posed a minimal risk and did not pose a serious or substantial risk to the reliability of the bulk power system. The noncompliance was minimal because only four out of a total of 42 Electrical Maintenance/Transmission Maintenance field switching personnel missed the training in 2017. Taking into account that at least two DPC qualified individuals would normally be together while performing any operations on the transmission system, the likelihood both individuals present would not have received system restoration training would be extremely low. Additionally, DPC had only three tasks that were identified unique as part of EOP-005-2 R11; these three identified tasks were either already trained on or were simple enough to perform that no additional training was necessary. No harm is known to have occurred. DPC has no relevant history of noncompliance. Mitigation To mitigate this noncompliance, the Entity: 1) required the staff of issue complete the required training; 2) began internal meetings with the different stakeholders regarding EOP-005-2 R11 and EOP-005-3 R9 to ensure interpretation of the requirement was corrected and that System Operations staff were knowledgeable on the topic; and 3) updated the policy document describing the identified unique tasks and the field switching personnel that might perform those tasks to ensure that all Electrical Maintenance and Transmission Maintenance personnel shall attend a system restoration training session once every two calendar years. Last Updated 05/28/2020 2 A-1 Public Non-CIP – Compliance Exception Consolidated Spreadsheet Future Expected Reliability NERC Violation ID Req. Entity Name NCR ID Noncompliance Start Date Noncompliance End Date Method of Discovery Mitigation Completion Standard Date MRO2020022818 TOP-001-4 R13 The Empire District Electric Company NCR01155 10/14/2019 10/14/2019 Self-Log Completed (EDE) Description of the Noncompliance (For purposes On January 14, 2020, EDE submitted a Self-Log stating that, as a Transmission Operator, it was in noncompliance with TOP-001-4 R13. of this document, each noncompliance at issue is described as a “noncompliance,” regardless of EDE reported that it owns and operates its own Real-time Assessment (RTA). However, EDE uses its Reliability Coordinator’s (RC) RTA as a primary, and uses its own RTA is a secondary backup if its’ RC’s its procedural posture and whether it was a RTA fails. In this instance the Entity’s email system notified the system operator about the failure to connect and access the RC’s RTA; however, the system operator incorrectly believed the email possible, or confirmed violation.) notification was spam, therefore the operator did not take any action to switch and operate EDE’s RTA in order to ensure a RTA is completed every 30 minutes as required. The cause of the noncompliance was EDE’s Real-Time Contingency Analysis (RTCA) procedure document/was deficient as it did not address an email alert notifying the system operator about the failure to access the RC’s RTA. In addition, the RTCA procedure document did not address this type of RTCA email. This noncompliance began on October 14, 2019, when EDE lost access to SPP’s RTA, and ended on October 14, 2019 (approximately 2 hours later), when connectivity was restored. Risk Assessment This noncompliance posed a minimal risk and did not pose a serious or substantial risk to the reliability of the bulk power system. The risk was minimal because EDE had situational awareness of the system conditions at all times through the RC’s Energy Management System. Throughout the duration of noncompliance, SPP was operational and monitoring the RC’s footprint through its own RTA. Accordingly, if EDE had detected any overloads or congestions, EDE’s RC would have informed EDE to ensure the appropriate actions were taken. No harm is known to have occurred. EDE has no relevant history of noncompliance. Mitigation To mitigate this noncompliance, EDE: 1) rebooted the computer that performs the RC’s RTA process, which restored its’s automatic task schedule program; 2) provided System Operators specific training on the identification of this type of RTA e-mail alert and the actions that should be taken; 3) revised its RTCA procedure document to include the procedures instructing the System Operators on what they are to do when they encounter these RTCA email types; and 4) implemented additional controls for the RTA emails, which gets sent to System Operators if the RTA application fails to run.
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