AES Armenia Mountain Wind, LLC (AES Armenia), Docket No. RC12-14 (July 30, 2012)
Reliability Standard: VAR-002-1.1b
Requirement: 3
Region: RFC
Issue: AES Armenia, in its role as a GOP, submitted a self-report explaining that it had not notified its TOP of a change in status to its automatic voltage regulator within the 30-minute time frame required set forth in the Standard.
Finding: The issue was deemed by RFC to pose minimal risk to BPS reliability because during the event AES Armenia kept its voltage schedule as established by its TOP. In addition, the interconnection between AES Armenia and its TOP is not considered to be a CA by the TOP or the RTO. The circumstances causing the event were not likely to be repeated.
Reliability Standard: VAR-002-1.1b
Requirement: R1
Region: TRE
Issue: AEP, as a GOP, self-certified an issue with VAR-002-1.1b R1 to TRE when it found that on one instance, it had switched the voltage control mode of the Automatic Voltage Regulator (AVR) at its Oklaunion generation plant from automatic to manual without notifying the TOP.
Finding: TRE determined that the issues posed a minimal risk to the reliability of the BPS because: a) the TOP was knew that the AVR was being tuned and going in and out of service; b) the issue period was short and lasted only ~35 hours; c) AEP was monitoring voltage on the Oklaunion facility; d) the unit maintained its established voltage limits during the issue period; e) the Oklaunion facility was fully available and no trips occurred during the issue period; f) the BPS was not under stress.
Reliability Standard: VAR-002-1.1b
Requirement: R3; R3.1
Region: SPP RE
Issue: AEP, as a GOP, self-reported an issue with VAR-002-1.b R3.1 to SPP RE when it found that it had not reported the status change and expected duration of an outage of a power system stabilizer (PSS) to its TOP within 30 minutes in one instance. Due to a faulty alarm, the generator operators were unaware that the PSS was disabled during an investigation of AEP’s Stall 6S that had tripped due to the loss of the unit’s voltage regulator system. As the generator operators did not know that the PSS was disabled, they did not notify the TOP of the PSS status change.
Finding: SPP RE determined that the issues posed a minimal risk to the reliability of the BPS because the issue was limited to the Stall S6 PSS, which was back in service within less than 7.5 hours. In addition, even when PSS was disabled, the generator voltage was monitored and controlled by the generator operators, consistent with the required voltage schedule for the duration of PSS outage. The issue also did not cause any operating events or loss of load.
Arizona Public Service Company, FERC Docket No. RC12-11 (April 30, 2012)
Reliability Standard: VAR-002-1.1b
Requirement: R3
Region: WECC
Issue: Arizona Public Service Company (AZPS), as a GO, self-reported that it did not notify its TOP within 30 minutes of taking the PPS on its Palo Verde Nuclear Generating Station Unit 3 out of service on October 9, 2011.
Finding: WECC found that this issue constituted only a minimal risk to the BPS. When the relevant PSS was out of service, the PSS equipment on AZPS’ remaining 20 units was still operating and would have been able to respond to a system deviation. In addition, AZPS system conditions were stable and load conditions were low.
Black Hills Colorado IPP, LLC (BHCI), Docket No. RC12-16 (September 28, 2012)
Reliability Standard: VAR-002-1.1b
Requirement: 1
Region: WECC
Issue: BHCI, as a GO, self-reported that, while its PAGS Unit 43 was not operating in Automatic Voltage Control (AVR), it failed to notify its TOP (per R1).
Finding: WECC found that the issue posed a minimal risk to the reliability of the BPS since the generator involved is a 29.5 MVA generator. Additionally, BHCI has two other 71.2 MVA generating units at the facility that were operating in AVR mode and capable to respond to voltage deviations.
Black Hills Colorado IPP, LLC (BHCI), Docket No. RC12-16 (September 28, 2012)
Reliability Standard: VAR-002-1.1b
Requirement: 3
Region: WECC
Issue: BHCI, as a GO, self-reported that it changed the status of its PAGS Unit 43 from manual mode to Automatic Voltage Control (AVR) mode without notifying its TOP within 30 minutes.
Finding: WECC found the issue posed a minimal risk to the reliability of the BPS since the status change resulted from BHCI switching the AVR to the AGC mode, per the TOP requirements.
Cleco Corporation (Cleco), Docket No. RC12-16 (September 28, 2012)
Reliability Standard: VAR-002-1.1b
Requirement: 3
Region: SPP RE
Issue: Cleco self-reported that it failed to notify its TOP of a status change on a generator's automatic voltage regulator (AVR) within 30 minutes (per R3). Cleco's operating personnel attempted to contact the TOP after resetting the AVR, however the Generation Ops database was down. The TOP was informed of the status change of the AVR 33 minutes and 8 seconds after the occurrence.
Finding: SPP RE found the issue posed a minimal risk to the reliability of the BPS because the AVR trip was brief, and the system operators immediately reset the AVR to automatic mode. Furthermore, Cleco was only 3 minutes and 8 seconds over the time requirement to report the AVR status change (per R3).
Colorado Energy Management – MPC (COMPC), Docket No. RC13-6-000 (February 28, 2013)
Reliability Standard: VAR-002-1.1b
Requirement: 3
Region: WECC
Issue: COMPC, a GOP, filed two self-reports (November 2012 and January 2013) explaining that after a start-up of a gas turbine, employees mistakenly reported to the TOP that the Power System Stabilizer (PSS) for the turbine was in service and active when, in fact, the PSS had changed to manual mode and was not active. Operators realized the error and switched the PSS to automatic mode, but the mistake was not noticed for eight hours, and therefore the TOP was not notified within the 30-minute timeframe required nor was the PSS in service for at least 98% of all operating hours during Q4 2012 as required.
Finding: The issue was deemed to pose minimal risk to BPS reliability and not serious or substantial risk. The risk to BPS operations was mitigated because COMPC maintained the TOP's established voltage schedule during the relevant time period. Also, the automatic voltage regulator connected to the relevant turbine was in automatic mode and would have responded as designed to prevent any negative consequences that could have been caused by an increased voltage level or reactive flow. COMPC's internal procedures also are set so that once the issue was found, the TOP was notified immediately of the change and length of the status change. Also, COMPC is only a peaking plant so any impact would be minimal to the TOP's service.
Cottonwood Energy Company LP (Cottonwood), Docket No. RC13-9, May 30, 2013
Reliability Standard: VAR-002-1.1b
Requirement: 3
Region: SERC
Issue: Cottonwood, as a GOP, self-reported an issue with VAR-002-1.1b R3 to SERC after finding that it did not notify its TOP of changes in the status of several power system stabilizers (PSSs) within 30 minutes. This occurred when Cottonwood calibrated the PSSs on three units by toggling the PSSs on and off, which created status changes associated with each unit’s PSS. No notification was provided to the TOP because during the test of each unit, the other units were online and running to manage its commitment to load.
Finding: SERC determined that the issue posed a minimal risk to the reliability of the BPS because all eight generators at Cottonwood’s facility were operating while the calibration was performed, and Cottonwood was able to manage any changes to the BPS while the testing was underway. Furthermore, the longest time that a single PSS was out of service was ~101 minutes.
Covanta Southeastern Florida Renewable Energy (SEFLOR), Ltd. (COVS), Docket No. RC13-9, May 30, 2013
Reliability Standard: VAR-002-1.1b
Requirement: 1, 3
Region: FRCC
Issue: COVS, as a GOP, self-reported an issue with VAR-002-1.1b R1 and R3 to FRCC when, after notifying its BA and TOP that its Turbine Generator #2 (T/G #2) had been brought back online, operators failed to inform the BA and TOP that T/G #2’s automatic voltage regulator (AVR) was in manual operation instead of the required automatic mode for a certain period of time. As a result, COVS failed to notify the TOP of the change in AVR status within 30 minutes, as required by the Status.
Finding: FRCC determined that the issue posed a minimal risk to the reliability of the BPS because after having been notified that T/G #2 had been brought back online, the BA and TOP could have monitored the line voltage of the units through the supervisory control and data acquisition system. Furthermore, COVS maintained the required voltage schedule, the facility’s total generation is only 60 MW, and the AVR was in manual mode for only ~4 hours.
Dairyland Power Cooperative (DPC), Docket No. RC12-12 (May 30, 2012)
Reliability Standard: VAR-002-1.1b
Requirement: R3
Region: MRO
Issue: While conducting a compliance audit in March 2011, MRO found that DPC, a GOP, was unable to provide evidence that it had notified its TOP within 30 minutes of an automatic voltage regulator (AVR) status change. Specifically, when DPC removed a particular unit from service, according to its voltage schedule, the AVR on two other units should have been placed into service. Further review indicted the AVRs had been placed into service, but no documentation could be found to support that the TOP had been notified of the AVR status change, as required.
Finding: The issue was found to pose a minimal risk to BPS reliability because DPC’s Energy Management System (EMS) provides a continuous indication of the AVR status to the TOP. DPC provided evidence that the changes were made within 30 minutes as required in VAR-002 and that the AVRs were placed in-service as per the plan. DPC also reported that it had contacted its TOP via telephone; however, its voice recording system was not in service during the relevant time period.
Delaware City Refining Company LLC (DCR), Docket No. RC13-10, June 27, 2013
Reliability Standard: VAR-002-1.1b
Requirement: R1; R3
Region: RFC
Issue: DCR, as a GO and GOP, self-certified an issue with VAR-002-1.1b R1 and R3 to RFC as DCR did not notify its TOP that four of DCR’s steam generators operate in manual voltage control. Unlike DCR’s two combustion turbine generators, which are effectively controlled by automatic voltage regulation, the four generators at issue are directly connected to the same 13.8 kV bus without any isolation transformers.
Finding: RFC determined that the issues posed a minimal risk to the reliability of the BPS because the use of manual voltage control mode for these steam generators contributes to the stability of the generators and overall BPS stability and reliability. In addition, DCR has now agreed with its TOP that it will continue to operate the generators at issue in manual control mode. Finally, DCR’s primary purpose in electricity generation is to ensure the reliable operation of the refinery itself.
Detroit Renewable Power LLC (DRP), Docket No. RC12-14 (July 30, 2012)
Reliability Standard: VAR-002-1.1b
Requirement: 3
Region: RFC
Issue: DRP, in its role as a GOP, submitted a self-report explaining that it had not notified its TOP of a change in status to its automatic voltage regular (AVR) within the 30-minute time frame established by VAR-002-1.1b R3. Specifically, when an AVR fuse tripped, the AVR changed from automatic to manual mode. DRP assumed that the generator turbine would not operate in the manual mode, but subsequently found the turbine was in fact operating, and at that time, DRP informed its TOP of the issue.
Finding: The issue was deemed by RFC to pose minimal risk to BPS reliability because for the duration of the event, DRP controlled the turbine generator reactive power output in the manual mode, and at all times the voltage schedule was kept.
DTE Electric Company (DTE Electric), Docket No. RC13-7-000 (March 27, 2013)
Reliability Standard: VAR-002-1.1b
Requirement: 2, 3
Region: RFC
Issue: DTE Electric submitted self-reports in October 2012 and November 2012 alerting RFC to compliance issues with VAR-002-1.1b. Regarding R2, DTE Electric reported that the actual generator bus voltage at a wind farm where DTE Electric is registered as the GOP exceeded the TOP-provided voltage schedule on several occasions between January 23, 2012 and September 9, 2012. Many times the issue happened when generation was at or near zero and many other instances occurred during the initial months of operations. DTE Electric and the TOP provided a temporary adjustment to the high operating limit because of the voltage issues, but the operating limit adjustment did not serve to exempt DTE Electric's voltage schedule, as it applied to the facility's operating limits only and not the applicable voltage schedule. Regarding R3, on July 20, 2012, the wind farm management system experienced an outage as the result of a failed power quality meter during which time the Automatic Voltage Regulator (AVR) also failed to operate. DTE Electric, as the GOP, was responsible to alert the TOP of the status change to the AVR within 30 minutes, but it failed to do.
Finding: The issues were deemed to pose minimal risk to BPS reliability and not serious or substantial risk. Regarding R2, DTE Electric has received from the TOP a revised voltage schedule for the facility, and since March 3, 2012, the voltage level exceeded the schedule only one time for less than 1kV during which generation output was only 10.9 MW. Regarding R3, during the relevant time period, the facility operated outside of the voltage schedule on four occasions, by no more than 0.4 kV, which would have been acceptable pursuant to the revised voltage schedule subsequently received by the TOP.
EDF Trading North America, LLC (EDF Trading), Docket No. RC13-6-000 (February 28, 2013)
Reliability Standard: VAR-002-1.1b
Requirement: 3
Region: TRE
Issue: EDF Trading, a GOP, submitted a self-report in February 2012 explaining that a unit was not in automatic voltage control for almost two hours in early February 2012, but the operator did not report the status change to the TOP within 30 minutes, as required.
Finding: The issue was deemed to pose minimal risk to BPS reliability and not serious or substantial risk. The risk to BPS operations was mitigated because the issue was corrected in less than two hours, the incident happened during a regular start-up of the unit, and the unit was ramping up and not in Automatic Generation Control so it had not been released to ERCOT economic dispatch at the time of the issue.
The Dow Chemical Company (Dow), Docket No. RC12-14 (July 30, 2012)
Reliability Standard: VAR-002-1.1b
Requirement: 3.1
Region: TRE
Issue: Dow, in its role as a GOP, submitted a self-report explaining that it had not notified its TOP of a change in status to its automatic voltage regulator (AVR) within the 30-minute time frame established by VAR-002-1.1b R3.1. Specifically, an AVR on one generator unit at Dow’s Freeport facility tripped from automatic to manual voltage control mode while sporadic generator exiter problems were occurring. Dow did not inform its TOP to the status changed until eight days after the event.
Finding: The issue was deemed by TRE to pose minimal risk to BPS reliability because power system voltages on the Dow system are watched through Distributed Control Systems and SCADA systems. In addition, the devices are alarmed to alert system operators to any voltage events requiring attention. Dow staffs its powerhouse and power dispatch centers 24/7. TRE considered the size of the unit in determining any impact to the overall BPS and also found that during the relevant time frame no power had been put to the BPS by Dow. Historical records showed that in 2010 Dow only exported 1% of all energy it had purchased, and in 2011, only 6% of the energy it had purchased was exported. If the unit had been called upon to respond to an energy request, but failed, nearby generating units would have been able to handle such request.
Dynegy Power, LLC (DYN), FERC Docket No. RC13-3-000 (December 31, 2012)
Reliability Standard: VAR-002-1.1b
Requirement: 2
Region: WECC
Issue: DYN, as a GOP and a GO, self-certified a possible violation of R2 of VAR-002-1. 1b to WECC on July 23, 2012. The self-certification indicated that a generator had operated at a higher terminal voltage than allowed by its TOP, which was 21.7kV +/- 0.2kV. DYN stated that the operation technician did not adjust the power factor for two hours after the generator started up, during which the generator operated at 0.5 kV higher than its TOP voltage. A WECC SME determined that DYN did operate its generator at a higher voltage level than its TOP level during those two hours and WECC confirmed SME's findings.
Finding: WECC found that the issue posed a minimal risk to the reliability of the bulk power system, for DYN had a prevention policy for VAR-002-1.1b and had informed its operators of the policy. Once the issue was made aware, DYN quickly remediated the issue by using the procedures of the prevention policy. TOP experienced no changes in voltage and did not contact DYN about the output during those two hours.
Dynergy Power, LLC (Dynergy), FERC Docket No. RC13-5-000 (January 31, 2013)
Reliability Standard: VAR-002-1.1b
Requirement: 1; 2; 3
Region: RFC
Issue: Dynergy, as a GO, self-reported a violation of R1, R2, and R3 of VAR-002-1.1b to RFC on July 6, 2012. Dynergy, during shutdown on August 1, 2011 and on April 7, 2012, did not notify its TOP that it was operating in power factor mode for 16 minutes and 40 minutes, respectively, instead of operating the AVR, as mandated by R1. On November 14, 2011, Dynergy again failed to meet R1 when it didn't notify its TOP that it was tuning with the AVR in power factor mode for 3 hours and 40 minutes during startup and a premediated outage on Combustion Turbine no.2; Dynergy's logs failed to record that it notified the TO, who in turn notifies the TOP, but the logs say that the TOP was notified of the testing time frame. Dynergy also violated R2 of VAR-002-1.1b when it went over the voltage schedule for its Ontelaunee generating plant, which is a combined cycle natural gas fired facility of 526MW, interconnected at 230kV, and has a voltage schedule of 237kV +/- 0.5%. It went over the schedule by 0.6% above its 237kV. Dynergy failed to manually adjust the setpoint to keep the voltage schedule despite knowing that its AVR was at its maximum adjustment limit of +/- 0.5% of the target voltage. Dynergy violated R3 of VAR-002-1.1b when it did not notify the TOP of its AVR status change during shutdown on April 7, 2012.
Finding: RFC found that the issue posed a minimal risk to the reliability of the bulk power system, because: (1) the generating plant stayed within its scheduled voltage despite the failure to notify; (2) the TOP knew about the November 14, 2011 testing, making it likely that the TOP would be aware of changes in AVR status; (3) Dynergy has failed to utilize its policy to ensure that the TOP is notified in case of the AVR changing status for 30 minutes on these three incidents, but does have in place such a policy; (4) Dynergy only went over 0.1% the voltage schedule limit, and the duration did not exceed an hour; (5) Dynergy did not go over the TO (PJM Interconnection LLC)'s default voltage schedule, the maximum limit being 239kV.
Flat Ridge Wind Energy, LLC (Flat Ridge), FERC Docket No. RC13-3-000 (December 31, 2012)
Reliability Standard: VAR-002-1.1b
Requirement: 2; 2.2
Region: SPP
Issue: Flat Ridge, as a GOP, self-reported a violation of R 2.2 of VAR-002-1.1b on April 30, 2012, regarding its failure to abide by its TOP voltage schedule, which was 139kV +/- 4kV at the POI from 2009-2011 and 138 kV +/- 7 kV at the POI from 2011-2012. In April 2012, a new TOP told Flat Ride that its new voltage schedule would be 139 kV +/- 4kV from May 1, 2012. Flat Ridge, during a compliance review, found that its voltage schedule did not comply with the new schedule, mostly with a deviation of less than 1kV. Flat Ridge also found that its facilities, which depend on a tap changing transformer and a shunt capacitor bank control system, were unable to accommodate the new voltage schedule. The devices could not maintain the voltage schedule within 139 kV +/- 4 kV at all times.
Finding: SPP found that the issue posed a minimal risk to the reliability of the bulk power system, for Flat Ridge wind facility's generators are designed to absorb reactive power and are unable to give any substantial voltage support to the BPS. Furthermore, most of the voltage schedule excursions were less than 1 kV and posed a minimal danger to the TOP's transmission system.
Find, Fix and Track Entity, Docket No. RC12-7-000 (January 31, 2012)
Reliability Standard: VAR-002-1.1b
Requirement: R1
Region: ReliabilityFirst
Issue: FFT Entity self-reported an issue with VAR-002-1.1b R1 because, over a three-year period, it started three generating units in manual mode until the units reached minimum unit-stability-related output levels. This process, necessitated by the design of the equipment, concluded when the units were switched to automatic voltage control mode. During the manual mode start, however, FFT Entity failed to notify its TOP of the manual voltage control mode status.
Finding: This issue posed only a minimal risk to the reliability of the BPS because the generators were designed to start in manual mode, and FFT Entity had an established procedure for manual start-up. FFT Entity started the generating units in manual mode because of design requirements. While the units are identified as single generating units, they are actually comprised of two separate generators. To reduce mechanical stress, variability of current, and to ensure the generators are loaded equally and stabilized together, the generators are started in manual mode. Once this process is completed, FFT Entity switches the generating units to automatic voltage control mode and releases them for dispatch.
Find, Fix and Track Entity, Docket No. RC12-7-000 (January 31, 2012)
Reliability Standard: VAR-002-1.1b
Requirement: R1
Region: ReliabilityFirst
Issue: FFT Entity self-reported a violation of VAR-002-1.1b R3.1, because, in one instance, FFT Entity started the AVR on one of its generating units in manual mode, but failed to properly notify the TOP that it was going to do so. ReliabilityFirst, subsequently, determined that the facts of the violation also constituted a violation of VAR-002-1.1b R1.
Finding: The issue posed only a minimal risk to BPS reliability because FFT Entity started the AVR in manual mode pursuant to its operating procedures, maintained its voltage schedule at all relevant times, and placed the AVR into service as soon as practicable. As such, the breach of the Standard was an isolated event that is correctable through personnel training.
Find, Fix and Track Entity, Docket No. RC12-7-000 (January 31, 2012)
Reliability Standard: VAR-002-1.1b
Requirement: R3/R3.1
Region:
Issue: FFT Entity self-reported a violation of VAR-002-1.1b R3.1 because FFT Entity’s local operating personnel failed to provide notice to the TOP 30 minutes before switching to manual mode.
Finding: The issue posed only a minimal risk to the BPS reliability because, although FFT Entity failed to provide proper notice of the intended status change, it did alert the TOP within nine minutes of switching the AVR into manual mode.
Fowler Ridge Wind Farm LLC (Fowler Ridge), Docket No. RC13-1 (October 31, 2012)
Reliability Standard: VAR-002-1.1b
Requirement: 2
Region: RFC
Issue: While conducting a compliance audit, RFC found that Fowler Ridge, as a GOP, was non-compliant with VAR-002-1.1b R2 based on the fact that on several occasions it was unable to maintain the power factor within the established range.
Finding: The issue was deemed by RFC to pose minimal risk to BPS reliability because even though the Fowler Ridge Companies failed to maintain the established power factor schedule, they did maintain voltage at all relevant times and none of the Fowler Ridge facilities were directed to change voltage since initial operations. Also, RFC found that all of the power factor excursions happened when the output of the Fowler Ridge Companies was at or less than 25 percent of nameplate capacity, when the wind farms have limited dynamic reactive control, and would not have been considered excursions under the Fowler Ridge Companies' power factor scheduled updated in July 2012. Moreover, as small, wind-powered generating facilities, the Fowler Ridge Wind Farm Complex's generation output is variable by nature and not coincident with peak load.
Fowler Ridge II Wind Farm LLC (Fowler Ridge II), Docket No. RC13-1 (October 31, 2012)
Reliability Standard: VAR-002-1.1b
Requirement: 2
Region: RFC
Issue: Fowler Ridge II, as a GOP, self-reported non-compliance with VAR-002-1.1b R2 based on the fact that on several occasions it was unable to maintain the power factor within the established range.
Finding: The issue was deemed by RFC to pose minimal risk to BPS reliability because even though the Fowler Ridge Companies failed to maintain the established power factor schedule, they did maintain voltage at all relevant times and none of the Fowler Ridge facilities have been directed to change voltage since initial operations. Also, RFC found that all of the power factor excursions happened when the output of the Fowler Ridge Companies was at or less than 25 percent of nameplate capacity, when the wind farms have limited dynamic reactive control, and would not have been considered excursions under the Fowler Ridge Companies' power factor scheduled updated in July 2012. Moreover, as small, wind-powered generating facilities, the Fowler Ridge Wind Farm Complex's generation output is variable by nature and not coincident with peak load.
Fowler Ridge III Wind Farm LLC (Fowler Ridge III), Docket No. RC13-1 (October 31, 2012)
Reliability Standard: VAR-002-1.1b
Requirement: 2
Region: RFC
Issue: While conducting a compliance audit, RFC found that Fowler Ridge III, as a GOP, was non-compliant with VAR-002-1.1b R2 based on the fact that on several occasions it was unable to maintain the power factor within the established range.
Finding: The issue was deemed by RFC to pose minimal risk to BPS reliability because even though the Fowler Ridge Companies failed to maintain the established power factor schedule, they did maintain voltage at all relevant times and none of the Fowler Ridge facilities were directed to change voltage since initial operations. Also, RFC found that all of the power factor excursions happened when the output of the Fowler Ridge Companies was at or less than 25 percent of nameplate capacity, when the wind farms have limited dynamic reactive control, and would not have been considered excursions under the Fowler Ridge Companies' power factor scheduled updated in July 2012. Moreover, as small, wind-powered generating facilities, the Fowler Ridge Wind Farm Complex's generation output is variable by nature and not coincident with peak load.
GenOn California I (GCAI), FERC Docket No. RC13-3-000 (December 31, 2012)
Reliability Standard: VAR-002-1.1b
Requirement: 1; 3
Region: WECC
Issue: GCAI, as a GOP, self-certified possible violations of R1 of VAR-002-1.1b on July 20, 2012, stating that the Automatic Voltage Regulator (AVR) did not activate when its Etiwanda Unit 4 (Unit 4) reached a minimum load point, as it should have, and remained in manual mode for approximately 40 minutes. GCAI notified its TOP that the unit was offline and that the unit would restart; GCAI also notified its TOP once Unit 4 started to operate in AVR. WECC's SMEs reviewed the self-certifications and confirmed GCAI's violation of R1, that Unit 4 was in manual mode during the 40 minutes when the TOP expected it to be in AVR. Furthermore, SMEs found a violation of R3 because GCAI did not notify its TOP of Unit 4's operating status during those 40 minutes. Since R3 mandates GOPs to notify the TOP within 30 minutes of a change in status of a reactive source, WECC confirmed that GCAI violated R3.
Finding: WECC found that this issue posed a minimal risk to the reliability of the bulk power system because although AVR operation is required to ensure that the generation makes the necessary adjustments for different voltage levels and reactive flows, Unit 4, which failed to switch to AVR, was one of 3 units operating at the time, the rest of which were in AVR, and which were capable of responding to the different voltages at the interconnection during the 40 minutes that the Unit 4 was in manual mode. Additionally, during the 40 minutes GCAI kept up the voltage schedule as established by its TO.
GenOn Power Midwest, FERC Docket No. RC13-3-000 (December 31, 2012)
Reliability Standard: VAR-002-1.1b
Requirement: 1
Region: RFC
Issue: As a GOP and a GO, GenOn Power Midwest self-reported a violation of R1 of VAR-002-1. 1b on May 30, 2012, with regard to the failure of notice to its TO that the Brunot Island Unit 4 with the automatic voltage regulator (AVR) was operating in manual mode for approximately 29 hours, from April 11, 2012 to April 13, 2012.
Finding: RFC found that the issue posed a minimal risk to the reliability of the bulk power system since: (1) it was a singular incident; (2) GenOn Power Midwest uses a program that requires AVR to operate in automatic mode; (3) GenOn Power has alarms for Units 2, 3 and 4 for the AVR status.
GenOn REMA 1, FERC Docket No. RC13-3-000 (December 31, 2012)
Reliability Standard: VAR-002-1.1b
Requirement: 2
Region: RFC
Issue: GenOn REMA 1, a GO and a GOP, self-reported a violation of R2 of VAR-002-1.1b to RFC on July 9, 2012, when it found that it was not maintaining generator voltage schedule for its Sayreville (four combustion turbines of 224MW) and Werner (four combustion turbines of 212 MW) generating stations, with no exemption from the TO. The Werner station, while operating two of its generating units, underwent a voltage excursion higher than necessitated by its schedule; the Sayreville underwent voltage excursions during which the voltage was a bit higher or lower than its schedule, with the largest voltage excursion being 1.13% above the voltage schedule.
Finding: FRC found that the issue posed a minimal risk to the reliability of the bulk power system, for the highest voltage excursion was only a negligible percentage (1.13%) above the voltage schedule and for the automatic voltage regulators functioned in automatic mode during the voltage excursions.
Hatchet Ridge Wind, LLC (HRWL), Docket No. RC13-9, May 30, 2013
Reliability Standard: VAR-002-1.1b
Requirement: 1
Region: WECC
Issue: HRWL, as a GOP, self-reported an issue with VAR-002-1.1b R1 to WECC after it found that its capacitor banks, acting as a part of its automatic voltage control scheme, were operating in manual rather than automatic mode as required by the Standard. This occurred when a relay that controlled capacitor bank switches was operating in manual rather than automatic mode, and when HRWL ignored the indication on the relay indicating that it was in manual mode, believing the indication was incorrect.
Finding: WECC determined that the issue posed a minimal risk to the reliability of the BPS because HRWL’s voltage control scheme includes a Load Tap Changer (LTC) located at its point of interconnection with its TOP, which operates independently of the capacitor banks and assists in regulating voltage fluctuations within predefined levels. In addition, HRWL produces only 101 MW and its load is not considered a base load.
High Desert Power Project, LLC, FERC Docket No. RC12-11 (April 30, 2012)
Reliability Standard: VAR-002-1.1b
Requirement: R3
Region: WECC
Issue: High Desert Power Project, LLC (HDPP), as a GO, self-reported that it had not provided its TOP with a timely change in status notice when it started its combustion turbine unit 1 on November 17, 2011 without turning on the PSS and then on November 20, 2011 when it placed the PSS back in service.
Finding: WECC found that this issue constituted only a minimal risk to the BPS. HDPP’s combustion turbine unit 1 was only operating without the PSS for approximately 63 hours, and during that time the automatic voltage regulator (AVR) was in service (which reduced the chance of an unnecessary loss of a facility during an event). In addition, the AVR allowed the generator to effectively respond to any voltage deviation.
Idaho Power Company (IPCO), Docket No. RC12-13 (June 29, 2012)
Reliability Standard: VAR-002-1.1b
Requirement: R1
Region: WECC
Issue: While conducting an internal review of VAR-002-1.1b requirements, IPCO, as a GOP, found that on one occasion its generator was not set to automatic voltage control, and the Generation Dispatch log in use did not show that the TOP had been informed of the issue within the time period prescribed by the Standard.
Finding: The issued was deemed by WECC to pose minimal risk to BPS reliability because IPCO has many generating units under its control throughout its facilities lessening any impact caused by a one-time event on a single unit. Also, the Generator Dispatchers are located in the same control room as the TOPs, and prior practice was notification through verbal communication.
Idaho Power Company (IPCO), Docket No. RC12-13 (June 29, 2012)
Reliability Standard: VAR-002-1.1b
Requirement: R1, R3
Region: WECC
Issue: While conducting an internal review of VAR-002-1.1b requirements, IPCO, as a GOP, found that on one occasion its generator was not set to automatic voltage control, and the Generation Dispatch log in use did not show that the TOP had been informed of the issue within the time period prescribed by the Standard. In addition, no documentation as to the expected duration of the change in status was available, as required by VAR-002-1.
Finding: The issue was deemed by WECC to pose minimal risk to BPS reliability because IPCO has many generating units under its control throughout its facilities lessening any impact caused by a one-time event on a single unit. Also, the Generator Dispatchers are located in the same control room as the TOPs, and prior practice was notification through verbal communication followed by documentation in the Generation Dispatch log.
Indianapolis Power & Light Company (IPL), FERC Docket No. RC13-5-000 (January 31, 2013)
Reliability Standard: VAR-002-1.1b
Requirement: 3
Region: RFC
Issue: IPL, as a GOP, self-reported a violation of R3 of VAR-002-1.1b to RFC, on July 9, 2012. IPL has an established system with its TOP that IPL will operate the Eagle Valley generation plant's AVR in automatic voltage control mode. However, on June 27, 2012, IPL started Eagle Valley Unit #5 in manual voltage control mode, accidentally, when a necessary component of the process of the AVR operating in automatic voltage control mode failed. IPL did not notify its TOP of the AVR status change within 30 minutes, as mandated by R3. IPL notified the TOP almost four hours after it was mandated to.
Finding: RFC found that the issue posed a minimal risk to the reliability of the bulk power system because despite the failure to notify, IPL was within the voltage schedule via manual voltage control mode. Because IPL knew that it wasn't in automatic voltage control mode, it lessened the probability of a harmful voltage excursion. Additionally, the generating plant had other units online with AVR in automatic mode, had it needed extra support in voltage.
InterPower/Ahlcon Partners, LP (InterPower), Docket No. RC13-1 (October 31, 2012)
Reliability Standard: VAR-002-1.1b
Requirement: 2
Region: RFC
Issue: While conducting a compliance audit in November 2011, RFC determined that InterPower, a GOP, had an issue with VAR-002-1.1b R2 in that on three occasions in 2011, its Colver generating plant exceeded its voltage schedule. The voltage schedule for its 110 MW Colver generating plant is 116.5 kV plus or minus 1.5% for normal and light load conditions and 117.5 kV plus or minus 1.5% for heavy load conditions or when requested. On May 18, 2011, May 22, 2011, and September 14, 2011, during light load conditions, InterPower exceeded its voltage schedule by less than 1% of the voltage schedule.
Finding: The issue was deemed by RFC to pose minimal risk to BPS reliability which was mitigated by the fact that InterPower's TOP depends on the Colver generating plant as a reactive power resource in addition to keeping the generator voltage schedule and the TOP has given instructions to InterPower regarding the Colver plant's generator voltage or reactive power output throughout both a voltage schedule and the ongoing expectation that InterPower operate the plant as a reactive power resource that results in slightly positive MVARs at the interconnection point. When operating the plant in this manner, system load variations may occasionally cause slight deviations from the voltage schedule. Although InterPower did not ask for or secure an exemption from its voltage schedule during these events, it believed it was acting per the instruction of its TOP. Also, the AVR was in automatic voltage control mode during the voltage excursions, and InterPower never had a voltage excursion that exceeded 1%.
Las Vegas Power Company, LLC (LVPC), Docket No. RC12-14 (July 30, 2012)
Reliability Standard: VAR-002-1.1b
Requirement: 3
Region: WECC
Issue: LVPC, in its role as a GOP and a GO, submitted a self-report in March 2012 explaining that it had not notified its TOP within 30 minutes, as required, of a change made that affected the automatic voltage regulator (AVR) and power system stabilizer (PSS) on a Reactive Power resource. LVPC also did not provide a time estimate of when the issue would be resolved, as required. Particularly, while conducting maintenance on one of its generators, the PSS automatically switched off unbeknownst to the crew conducting the maintenance. The generator had not been configured to alert staff when a change occurs. Once plant operators noticed the PSS had been in the off mode, the TOP was notified, and the PSS was put back into service.
Finding: The issue was deemed by WECC to pose minimal risk to BPS reliability because the relevant generator has a 165 MW capacity only and is housed at a facility that has two other generators available that could provide 395 MW of output. Another 2,000 MW of generation is available within a five-mile radius. Due to the amount of generation available with PSS in the immediate area, WECC determined that system damping needs would be minimal and other units would compensate for any issue caused by the subject unit.
Lower Colorado River Authority (LRCA), FERC Docket No. RC12-15 (August 31, 2012)
Reliability Standard: VAR-002-1.1b
Requirement: 3.1
Region:TRE
Issue: LRCA, as a GOP, self-reported that on two instances on January 23, 2012 it had not notified its TOP (ERCOT) within 30 minutes, as required, of an AVR status change at its Gideon Unit 2. ERCOT was alerted of the change by LRCA’s real-time telemetry.
Finding: TRE found the issue constituted a minimal risk to BPS reliability since ERCOT received the information via telemeter in real-time (even though it did not know the expected duration of the status changes). While LRCA had a policy for reporting AVR changes in status, its operators did not follow that policy in those two instances.
Luminant Energy Company, LLC (Luminant), Docket No. RC12-12 (May 30, 2012)
Reliability Standard: VAR-002-1.1b
Requirement: R3.2
Region: TRE
Issue: Luminant, in its role as a GOP, self-reported that it did not notify its TOP within 30 minutes of a Reactive Power resource status or capability change as required. Luminant had an expected outage on a capacitor bank under its control, but it did not notify the TOP of the outage until two days after the outage began. Luminant stated it did not alert its TOP to the outage because its operator believed that a relay lockout caused the issue, but equipment failure was ultimately found to be the problem. TRE stated that no matter the reason for the outage, the TOP should have been told the expected duration of the outage the day the capacitor bank became disabled.
Finding: The issue was found to pose minimal risk to BPS reliability because a second capacitor bank was available to provide reactive capability and Luminant’s plant operator was able to maintain voltage limits as required. Also, the issue was short-term, only two days. Luminant did notify its TOP on the day of the outage, but did not indicate how long the outage would continue.
MidAmerican Energy Company, FERC Docket No. RC12-11 (April 30, 2012)
Reliability Standard: VAR-002-1.1b
Requirement: R3/3.1
Region: MRO
Issue: MidAmerican Energy Company (“MEC”), as a GOP, self-reported that when it restored one of its wind farms to service, the automatic voltage control was not immediately restored to operation and MEC did not notify its associated TOP within 30 minutes of a change in the status or capability of its AVR and the estimated duration of such change. While the AVR was on during the incident (which occurred from November 1-3, 2011), it was not enabled and therefore it was not controlling the voltage.
Finding: MRO found that this issue constituted only a minimal risk to the BPS since MEC, a vertically integrated utility, performed both the GOP and TOP functions. As MEC’s TOP reconnected the wind farm to the grid, the TOP noticed that the AVR was not functioning properly (as the wind farm was not maintaining the voltage schedule) and was able to fix the problem and ensure reliable operations.
Nueces Bay WLE LP (Nueces Bay), FERC Docket No. RC12-15 (August 31, 2012)
Reliability Standard: VAR-002-1.1b
Requirement: 3.1
Region:TRE
Issue: Nueces Bay, as a GOP, self-reported that on June 4, 2011 when the exciter was powered down to replace a bad card and fan motor, the unit operator did not manually enable the Power System Stabilizer (PSS) to function automatically during future starts, as required. Thus, during subsequent unit restarts, the PSS remained in the disabled mode and Nueces Bay failed to timely report the change in status.
Finding: TRE found the issue constituted a minimal risk to BPS reliability since the unit was only run for 31 hours with a disabled PSS and the AVR was online during the whole time. Since the AVR remained online, the unit would have been able to effectively respond to any system voltage deviations. In addition, the unit was only 223 MVA. The duration of the issue was from June 4, 2011 through June 9, 2011.
Oklahoma Gas and Electric Co. (OGE), Docket No. RC13-1 (October 31, 2012)
Reliability Standard: VAR-002-1.1b
Requirement: 3.1
Region: SPP
Issue: While conducting a Compliance Audit in April 2011, SPP found that OG&E, as a GOP, was unable to show that the communication of manual AVR operation for September 27, 2010, was within 30 minutes.
Finding: SPP found the issue posed minimal risk to BPS reliability. Even OG&E's plant voltage summary for September 27, 2010 showed that two of its generation facilities were in manual AVR mode, plant records show that the plants' AVRs were in automatic mode the entire time. OG&E found that one generation facility's AVR was incorrectly displayed in manual mode, via a supervisory control and data acquisition (SCADA) signal, from March 27, 2010 until October 26, 2010. The second generation facility's AVR manual status was due to human error. OG&E's transmission system operators have the ability to toggle the status of a unit's AVR upon receiving communication from a generation operator. This ability either reminds a transmission system operator of the status of a unit's AVR or communicates the status to another transmission operator in the event of a shift change. OG&E's second generation facility's status change occurred on September 27, 2010, only, and it occurred as a toggle error on the part of the operator rather than an actual status change.
Papalote Creek II, LLC (Papalote), Docket No. RC13-10, June 27, 2013
Reliability Standard: VAR-002-1.1b
Requirement: R3
Region: TRE
Issue: Papalote, as a GO and GOP, self-reported an issue with VAR-002-1.1b R3 to TRE when it found that on 12 instances between May 18, 2010 to November 1, 2010, a change in Automatic Voltage Regulator (AVR) status was not communicated to its TOP. This communication failure was due to technical communication issues between a third party contractor and the TOP.
Finding: TRE determined that the issue posed a minimal risk to the reliability of the BPS because Papalote’s operators were continuously monitoring voltage levels, and there were alarms set to trigger if any deviations form voltage profile limits occurred. In addition, Papalote did not experience any voltage issues with its systems during the issue period. The unit also provided the voltage support needed during the pendency of the issue.
Portland General Electric Company (PGE), Docket No. RC13-10, June 27, 2013
Reliability Standard: VAR-002-1.1b
Requirement: R3
Region: WECC
Issue: PGE, as a GO, self-reported an issue with VAR-002-1.1b R3 to WECC when it found that on two occasions certain power system stabilizers (PSS) had not been enabled as its generators were brought online. The first instance occurred further to an electronic outage when a technician rebooted certain controllers on a gas turbine as part of the process of updating the Toolbox programming application of the gas turbine’s control system human machine interface. After the reboot, the PSS defaulted to the “OFF” position and was still in this state when the combustion turbine generator (CTG) restarted the following day. The second incident occurred when a power supply board in PGE’s Coyote Springs Unit 2 CTG exciter was replaced. When the CTG was restarted, the PSS was in the “OFF” state. In both instances, as soon as PGE crews discovered the status of the PSS, they promptly changed the PSS to automatic mode and notified PGE’s TOP.
Finding: WECC determined that the issue posed a minimal risk to the reliability of the BPS because there were numerous compensating measures in place to limit the risks of the issue, such as: the automatic voltage regulators (AVRs) installed on both units at issue with were fully functional in each occurrence and would have acted properly had any voltage fluctuations or disturbances occurred; PGE’s other three turbines had functioning PSSs and AVRs that would also have functioned in the event of any voltage fluctuations.
PPL Holtwood, L.L.C. (Holtwood), Docket No. RC13-1 (October 31, 2012)
Reliability Standard: VAR-002-1.1b
Requirement: 1, 3
Region: RFC
Issue: Holtwood submitted a self-report in 2011 explaining that, as a GOP, it had an issue with VAR-002-1.1b R1 and R3 in that it failed to notify the TOP within 30 minutes that its Automatic Voltage Regulator (AVR) was not in automatic control mode.
Finding: RFC deemed the violation to pose minimal risk to BPS reliability. While the issue was ongoing, six generating units at Holtwood were operating with their AVRs in automatic voltage control mode and could provide any required voltage or reactive support. Also, PPL's voltage schedule was maintained during the relevant time period. Holtwood reported there were no issues during the time period.
PSEG Fossil LLC (PSEG Fossil), Docket No. RC13-6-000 (February 28, 2013)
Reliability Standard: VAR-002-1.1b
Requirement: 3
Region: RFC
Issue: PSEG Fossil, in its role as a GOP, submitted a self-report explaining that it did not notify its TOP within 30 minutes of a status change to its automatic voltage regulator (AVR). PSEG Fossil had notified its TOP that it was starting a generating unit's AVR in manual mode, but when the AVR was reset to automatic voltage control mode, PSEG Fossil did not notify the TOP until one hour after the change.
Finding: The issue was deemed to pose minimal risk to BPS reliability and not serious or substantial risk. The failure by PSEG Fossil to notify the TOP for 30 minutes of the status change led to the BA not knowing that the unit was ready for dispatch from a minimum output level; however, risk to reliable BPS operations was mitigated because the incident was an isolated occurrence. Also, the operator notified the TO, and PSEG Fossil notified the TOP 30 minutes after it was supposed to do so.
Sacramento Municipal Utility District (SMUD), Docket No. RC12-14 (July 30, 2012)
Reliability Standard: VAR-002-1.1b
Requirement: 3.1
Region: WECC
Issue: SMUD, in its role as a GOP, submitted a self-report in February 2012 explaining that it had not notified its TOP of a change in status to its power system stabilizer (PSS) within the 30-minute time frame established by VAR-002-1.1b R3.1. SMUD also did not provide a time estimate of when the issue would be resolved, as required. Particularly, when conducting a scheduled 5-year testing on one of its units, the system operator switched the automatic voltage regulator (AVR) from the primary AVR with a PSS to a secondary AVR that does not have a PSS installed. The operator swapped the primary AVR to the secondary AVR based on testing procedures provided by the system vendor, but no notification of the status change was provided to the TOP.
Finding: The issue was deemed by WECC to pose minimal risk to BPS reliability because the relevant unit is a steam generator that is part of a combined cycle 55 MW unit. WECC considered that the unit had a 45.6% capacity factor in 2010 and only 31.5% in 2011. WECC found that the amount of generation involved was minimal compared to the generation available at the facility and only a minor amount of total generation accessible by the TOP, meaning that it not knowing the PSS status of this particular unit would have little, if any, effect on overall operations. .
Safe Harbor Water Power Corporation (Safe Harbor), Docket No. RC12-14 (July 30, 2012)
Reliability Standard: VAR-002-1.1b
Requirement: 1, 3
Region: RFC
Issue: Safe Harbor, in its role as a GOP, submitted a self-report explaining that it had not notified its TOP of a change in status to its automatic voltage regular (AVR) within the 30-minute time frame established by VAR-002-1.1b R3. In addition, a Safe Harbor operator had changed the AVR mode on one of its hydro generating units from automatic mode to manual mode without notifying the TOP of the change in status as required by R1.
Finding: The issues were deemed by RFC to pose minimal risk to BPS reliability because the AVRs for all other units were in the correct mode (automatic) during the relevant time period and could provide voltage support if called upon. In addition, if the AVR were to trip to manual mode, alarms would sound. In this instance, the change in status was made by a Safe Harbor operator attempting to balance VARS among the units and thus no alarm sounded. Safe Harbor maintained its established voltage schedule during the relevant time period, and the voltage for the two 230 kV buses interconnected with Safe Harbor stayed within the operating range.
Settlers Trail Wind Farm LLC (STWF), Docket No. RC12-13 (June 29, 2012)
Reliability Standard: VAR-002-1.1b
Requirement: R1
Region: SERC
Issue: STWF, a GOP, submitted a self-certification in September 2011 stating that it had not notified its TOP that its automatic voltage regulator (AVR) was not in automatic voltage control mode due to the fact that STWF had not yet begun commercial operation. SERC review confirmed that STWF was unable to place its AVR into service until after most of the wind turbines at the facility were in operation; however, individual turbines could not be commissioned without back feed power provided by the grid. Energy from SWFT was first put on the grid while conducting testing in June 2011. STWF did not notify its TOP that its AVR was not in automatic voltage control mode until late September 2011. SERC found that STWF and its TOP were in communication regarding the status of the project, even though STWF did not formally tell its TOP what mode its AVR was in until the end of September.
Finding: The violation was deemed by SERC to pose minimal risk to BPS reliability because SWTF’s TOP knew the operational status of the facility. While in the test power stage, every wind turbine operated independently and controlled its own voltage and power factor. In addition, the STWF facility has a combined capacity of only 150 MW.
Simpson Tacoma Kraft Co., LLC (STK), Docket No. RC13-10, June 27, 2013
Reliability Standard: VAR-002-1.1b
Requirement: R1
Region: WECC
Issue: STK, as a GOP and GO, self-reported an issue with VAR-002-1.1b R1 to WECC when, after taking the STK Biomass Cogen unit offline to replace turbine generator communication cards on the turbine control system, the automatic voltage regulator’s (AVR’s) power factor mode was disabled. When the unit resynchronized to the system, the replacement cards caused the unit to synchronize in the power factor mode of operation instead of the required AVR control mode. This incorrect mode of operation was not immediately discovered or reported to the TOP. When it was discovered, STK changed the voltage control from power factor mode to AVR control mode and notified the TOP.
Finding: WECC determined that the issue posed a minimal risk to the reliability of the BPS because the biomass generator operated in the incorrect mode of operation for only 17 hours and 35 minutes without notification to the TOP, and the generator is a steam turbine unit with a name plate rating of 55 MW. In addition, STK had a power system stabilizer that would have automatically delivered additional voltage support if needed, resulting in a voltage schedule that would always have been maintained.
South Carolina Public Service Authority (SCPSA), Docket No. RC13-8, April 30, 2013
Reliability Standard: VAR-002-1.1b
Requirement: 1, 3
Region: SERC
Issue: SCPSA filed two self-reports in November and October 2012 stating that it had failed to notify its TOP on two instances when (1) it was not operating its Automatic Voltage Regulator (AVR) in automatic voltage control mode (R1); and (2) it did not notify its TOP of a change in AVR status within 30 minutes (R3).
Finding: The violation was deemed to pose minimal risk to BPS reliability but not serious or substantial risk which was mitigated because SCPSA maintained voltage within the prescribed limits of the voltage schedule throughout the period in question. SCPSA further found that voltage regulation at the relevant unit would not have had any impact on area bus voltages or facility loadings during the specific time period.
Sunbury Generation LP (Sunbury), Docket No. RC12-16-000 (September 28, 2012)
Reliability Standard: VAR-002-1.1b
Requirement: 3
Region: ReliabilityFirst
Issue: Sunbury, a GO, self-reported a violation of VAR-002-1.1b/3 because on March 24, 2012 it failed to notify its TOP that it experienced a status change on one of its generating units for 32 minutes after the event. The Standard requires companies to notify the TOP within 30 minutes. Prior to March 24, 2012, economic reasons forced all of Sunbury's generating units to be shut down. Sunbury's TOP requested Sunbury to start its Unit 1 generator to provide day-to-day reactive support while the local TO performed maintenance work. Sunbury operated its Unit 1 generator with one plant control operator, a reduced staff to its normal operations. On March 24, 2012, a relay operation caused Unit 1 to trip into manual mode. While there was only one operator on duty at the time, he responded to the trip event and notified the TOP of the status change on the AVR 32 minutes after Unit 1 returned to service in manual mode.
Finding: ReliabilityFirst determined this issue posed only a minimal risk the reliability of the BPS for three reasons. First, at the time of the trip, Sunbury's generator was operating at its minimal load level of 40 MW. Second, the two minute delay in notifying the TOP was the result of the reduced staffing conditions related to Sunbury's economic problems. Third, Sunbury's notice to the TOP was transmitted only two minutes late.
Tenaska Alabama Partners, L.P. ("Tenaska-AL"), FERC Docket No. RC13-2-000 (November 30, 2012)
Reliability Standard: VAR-002-1.1b
Requirement: 3
Region: SERC
Issue: Tenaska-AL, as a GO, self-reported an issue R3, stating that the control room operator observed that the PSS on three units were in the "Off" position on May 10, 2011. The operator changed the PSSs to the "On or Armed/Active" position and notified Plant Management, and Tenaska-AL did not notify the appropriate TOP within 30 minutes of the change (per R3). Tenaska-AL subsequently discovered that two units had their respective PSSs in the "Off" position.
Finding: SERC found the issue posed a minimal risk to the reliability of the BPS because although two combustions turbines were online with their respective PSSs off, the steam turbine, which was controlling the voltage, was operating with its PSS on. In addition, the control room operator in the Tenaska-AL facility is responsible for maintaining the plant voltage schedule provided by the TOP. During the seven days Tenaska-AL operated the units with their PSSs off, the two combustion turbines units in question ran for approximately 33 hours and 18 hours respectively.
Tenaska Virginia Partners, LP (TVP), Docket No. RC12-16 (September 28, 2012)
Reliability Standard: VAR-002-1.1b
Requirement: 3
Region: SERC
Issue: TVP self-reported that following an outage, the TVP operator was unaware that the PSS associated with its steam turbine generator (STG) had changed its status to disabled when its plant resumed operation. Subsequently, TVP did not report this status change to its TOP inside of the 30-minute time limit (per R3).
Finding: SERC found the issue posed a minimal risk to the reliability of the BPS since TVP was able to sustain system voltage in accordance with the TOP voltage schedule. In addition, the TOP confirmed that a small voltage trip by TVP would have had little impact on general grid voltage, and other plants in the region could easily deal with any event caused by the issue.
Whitewater Operating Services, LLC (Whitewater), Docket No. RC13-1 (October 31, 2012)
Reliability Standard: VAR-002-1.1b
Requirement: 1, 3
Region: RFC
Issue: Whitewater, a GOP, submitted a self-report in June 2012 explaining that it had an issue with VAR-002-1.1b R1 and R3 in that it failed to notify its TOP of a change in status to its automatic voltage regulator (AVR) within 30 minutes, as required.
Finding: The issue was deemed by RFC to pose minimal risk to BPS reliability because it was an isolated incident. The Whitewater operator started manual voltage control within 14 minutes of synchronization to the grid, and Whitewater notified its TOP within 36 minutes of the status change on its AVR.
Wisconsin Electric Power Company (Wisconsin Electric), FERC Docket No. RC13-5-000 (January 31, 2013)
Reliability Standard: VAR-002-1.1b
Requirement: 1
Region: RFC
Issue: Wisconsin Electric, as a GOP, self-reported a violation of R1 of VAR-002-1.1b to RFC on August 10, 2012. Specifically, on August 6, 2012, Wisconsin Electric failed to notify its TOP that its Oak Creek Unit 6, a 250 MW coal-fired generating unit, was not operating in automatic voltage control mode. The unit had tripped from service as a result of high temperature on its low speed exciter and was brought back online via a combination of its emergency and high speed exciters, but Wisconsin Electric did not notify the TOP, until an hour after the required time.
Finding: RFC found that the issue posed a minimal risk to the reliability of the bulk power system, for Wisconsin Electric discovered the issue under one hour and remediated the issue the following day. It also controlled voltage manually inside the boundaries of its voltage schedule during the issue time frame. Furthermore, Oak Creek Unit 6 is only 3.9% of Wisconsin Electric's 6,459 MW, making it less probably that Oak Creek Unit 6 in manual voltage control mode would have led to an issue with voltage change responses or voltage support to the system.
Wisconsin Public Service Corporation, FERC Docket No. RC12-11 (April 30, 2012)
Reliability Standard: VAR-002-1.1b
Requirement: R1
Region: MRO
Issue: In August 2011, Wisconsin Public Service Corporation (“WPS”), as a GOP, self-reported that it improperly reported to its TOP that one of its generator units was operating in voltage control mode after a controls upgrade, even though it was actually still in Mvar control mode. WPS also did not timely reports to its TOP that three other units were going into MVAR control mode during shutdown.
Finding: MRO found that this issue constituted only a minimal risk to the BPS. The first generating facility is a 63 MW non-base load unit that is connected to the BPS at the same interconnection point as three other larger units that were operating in voltage control mode. Therefore, the facility’s control mode had minimal impact on the bus voltage since the larger units provided the voltage control. In terms of the other three units, there was only a very small window of time that they were operating in a different control mode (even though they still had the AVR in-service).
Wood Group Power Operations, FERC Docket No. RC12-11 (April 30, 2012)
Reliability Standard: VAR-002-1.1b
Requirement: R3
Region: WECC
Issue: Wood Group Power Operations (WGPO), as a GO, self-reported that it had not provided its TOP with a timely change in status notice of its PSS being out of service. On January 22, 2012, WGPO lost power to its Panoche Energy Center and therefore shut down its four generating units. When the power was restored on January 23, 2012, WGPO activated the generating units, but as a result of an oversight, did not turn on the PSS until January 25, 2012.
Finding: WECC found that this issue constituted only a minimal risk to the BPS. During the time the PSS was out of service, the automatic voltage regulator (AVR) on all the units was in service, which allowed the generating units to effectively respond to any voltage deviation. In addition, the relevant generating units are peaking facilities dispatched by Pacific Gas and Electric Company.
