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["OpGID","OpGCat","OpGSect","OpGTitle","OpGNum","OG Version","OpGLang","MarkPartCat","Comments"]
[1,"Training","1 Overview, 1.5 Operational Training","1.5.1 System Operator Training Objectives","1.5.1(1)","2015-09-25","Each operating Entity within the ERCOT System shall train its operators such that they will possess the necessary knowledge, skills and abilities to perform their assigned tasks in directing the operation of the bulk power system.  Instruction provided shall be in accordance with North American Electric Reliability Corporation (NERC) Reliability Standards, the Protocols, these Operating Guides, and ERCOT Procedures, as well as individual Entity operating goals, plans and procedures. ","QSE/\nTO","Include both QSE and TO so as to be consistent with 1.5.2"]
[2,"Training","1 Overview, 1.5 Operational Training","1.5.1 System Operator Training Objectives","1.5.1(2)","2015-09-25","Training will prepare operators to: (a) Maintain the safety of personnel, even during emergency situations involving complex switching and manipulation of control elements;\n(b) Protect system components, particularly major power system elements from serious life degradation or harm;\n(c) Operate the system in a secure manner to minimize violations of operating limits, avoiding customer Outages where reasonably possible, and avoiding unstable situations that might result in widespread Outages, Partial Blackouts or Blackouts;\n(d) Operate the system using Good Utility Practices whenever possible within continually changing operating environment; and\n(e) Restore the system to its normal operating state as rapidly as practical after a disturbance.","QSE/\nTO","Include both QSE and TO so as to be consistent with 1.5.2"]
[3,"Training","1 Overview, 1.5 Operational Training","1.5.2 System Operator Training Requirements","1.5.2(1)","2015-09-25","The System Operator Training Program applies to all operators who are responsible for the Day-Ahead and Real-Time operation of the ERCOT Transmission Grid.  Transmission Operators (TOs) and Qualified Scheduling Entity (QSE) operators who represent Generation and Load Resources shall participate in 32 hours per year of training and drills on system emergencies.  QSE operators who do not represent Generation or Load Resources must participate in at least eight hours per year of training and drills in system emergencies.","QSE/\nTO","PER-005-1"]
[4,"Training","1 Overview, 1.5 Operational Training","1.5.2 System Operator Training Requirements","1.5.2(2)","2015-09-25","For those operators required to obtain 32 hours annually at least eight hours must be from simulations or realistic drills.","QSE/\nTO","PER-005-1"]
[5,"Training","1 Overview, 1.5 Operational Training","1.5.2 System Operator Training Requirements","1.5.2(3)","2015-09-25","Training should use simulations appropriate to each class of operator and all such training shall meet or exceed established NERC Reliability Standards.  Participation in emergency simulations, severe weather drills, ERCOT Black Start training, and portions of the ERCOT Operations Training Seminar that relate to NERC recommended topics may be used to satisfy this requirement.  Task specific training carried out internally within an Entity will be considered in full compliance with this requirement.  Training documentation, including curriculum, training methods, and individual training records, shall be immediately available during any audit.","QSE/\nTO","PER-005-1"]
[6,"Training","1 Overview, 1.5 Operational Training","1.5.4 ERCOT Severe Weather Drill","1.5.4(2)","2015-09-25","TOs and QSEs that represent Generation Resources are required to participate in the severe weather drill.","QSE/\nTO"]
[7,"Training","1 Overview, 1.5 Operational Training","1.5.5 Training Practices ","1.5.5","2015-09-25","Each operating Entity should establish a clear requirement, define and develop a systematic approach in administering the training, and provide the necessary feedback as a measurement of curriculum suitability and trainee progress.  Each operating Entity should recognize the importance of training and provide sufficient operator participation through adequate staffing and work-hour scheduling.","QSE/\nTO","PER-005-1"]
[8,"Protective Relay Systems","2 System Operations and Control Requirements, 2.2 System Monitoring and Control","2.2.3 Response to Transient Voltage Disturbance","2.2.3","2015-09-25","Response to Transient Voltage Disturbance\nGeneration Resources should be designed in accordance with Section 6.2, System Protective Relaying, in order to properly respond to transient voltage disturbances.","RE"]
[9,"AGC","2 System Operations and Control Requirements, 2.2 System Monitoring and Control","2.2.4 Load Frequency Control","2.2.4(3)","2015-09-25","QSEs shall use Automatic Generation Control (AGC) to direct the output of generation facilities providing Regulation and RRS.","QSE"]
[10,"AGC","2 System Operations and Control Requirements, 2.2 System Monitoring and Control","2.2.4 Load Frequency Control","2.2.4.1","2015-09-25","Maintenance and Verification\nEach provider of Regulation and/or Responsive Reserve Services will properly maintain AGC equipment.  Performance of AGC will be verified by the results of performance metrics for Ancillary Service providers described in the Protocols.  ERCOT will initiate a regulation survey to evaluate the performance of all AGC equipment in the ERCOT Region.","QSE/\nRE"]
[11,"AGC","2 System Operations and Control Requirements, 2.2 System Monitoring and Control","2.2.4 Load Frequency Control","2.2.4.2","2015-09-25","Regulation Provider Loss of AGC \nIf a QSE providing Regulation Services or Responsive Reserve Services loses its AGC for any reason, it will notify ERCOT as soon as practicable of the reason for and estimated duration of the loss.  ERCOT will assess whether additional action should be taken to maintain system frequency.  Possible ERCOT actions include opening a Supplemental Ancillary Service Market (SASM) per Protocol Section 6.4.8.2, Supplemental Ancillary Service Market, for the period of anticipated loss.","QSE"]
[12,"AGC","2 System Operations and Control Requirements, 2.2 System Monitoring and Control","2.2.4 Load Frequency Control. 2.2.4.3 ERCOT Loss of AGC","2.2.4.3(2)","2015-09-25","ERCOT Loss of AGC\nERCOT shall conduct unannounced testing to verify a QSE’s capability to operate in CFC mode.  Only QSEs with at least 350 MW of spinning reserve room will be tested.  QSEs shall be tested at least once every three years.  At a time determined solely by ERCOT, ERCOT will direct the QSE to operate under CFC mode.  Once instructed by ERCOT, the QSE will have five minutes to switch to CFC mode.  The duration of this test shall be no more than 15 minutes.  ERCOT shall maintain the list of QSEs that have successfully demonstrated their capability to operate in CFC mode.","QSE","CFC: Constrant Frequency Control"]
[13,"AVR","2 System Operations and Control Requirements, 2.2 System Monitoring and Control","2.2.5 Automatic Voltage Regulators","2.2.5(1)","2015-09-25","Generation Entities shall notify their QSEs of any change in Automatic Voltage Regulator (AVR) status (e.g. AVR unavailability due to maintenance or failure and when the AVR returns to normal operation).  QSEs shall notify ERCOT and the TO at the Point of Interconnection (POI) of any change in AVR status and shall supply AVR status logs to ERCOT upon request per Protocol Section 6.5.5.1, Changes in Resource Status.","QSE/\nRE","VAR-002"]
[14,"AVR","2 System Operations and Control Requirements, 2.2 System Monitoring and Control","2.2.5 Automatic Voltage Regulators","2.2.5(2)","2015-09-25","Generation Entities shall conduct performance tests on AVRs or verify AVR performance through comparison with operational data a minimum of every five years as prescribed in item (5) of Protocol Section 8.1.1.2.1.4, Voltage Support Service (VSS) Qualification, or if equipment characteristics are knowingly modified, within 30 days of the modification.  The test reports should include the minimum and maximum excitation limiters, volts/hertz settings, gain and time constants, type of voltage regulator control function, date tested, and voltage regulator control setting.","RE"]
[15,"AVR","2 System Operations and Control Requirements, 2.2 System Monitoring and Control","2.2.5 Automatic Voltage Regulators","2.2.5(3)","2015-09-25","Generation Resources shall verify excitation systems model data upon initial installation, within 30 days of performance modifications, and a minimum of five years thereafter.","RE"]
[16,"AVR","2 System Operations and Control Requirements, 2.2 System Monitoring and Control","2.2.5 Automatic Voltage Regulators","2.2.5(4)","2015-09-25","Generation Resource AVR modeling information required in the ERCOT Planning Criteria shall be determined from actual Generation Resource testing described in these Operating Guides.  Within 30 days of ERCOT’s request, the results of the latest test performed shall be supplied to ERCOT and the Transmission Service Provider (TSP).","RE","submission/notification Via QSE(EMO)"]
[17,"PSS","2 System Operations and Control Requirements, 2.2 System Monitoring and Control","2.2.6 Power System Stabilizers","2.2.6(1)","2015-09-25","Generation Resources with Power System Stabilizers (PSSs) shall keep their PSSs in-service (“On” or energized and performing as designed by the manufacturer) unless the PSS is installed but not in service as described in paragraph (4)(a)(ii) below.  When available, the PSS shall be active and responsive at all times the generator is synchronized to the ERCOT Transmission Grid and operating at or above its Low Sustained Limit (LSL).  However, if the PSS of a Generation Resource is set to be active and responsive at a point above the LSL for technical reasons, the Generation Resource may request ERCOT to allow an exception to the requirement that the PSS be active anytime the Generation Resource is at or above its LSL.  In order to obtain the exception, the Generation Resource shall notify ERCOT and provide the necessary technical information to ERCOT to justify a higher activation point for the PSS.","RE","submission/notification Via QSE(EMO)"]
[18,"PSS","2 System Operations and Control Requirements, 2.2 System Monitoring and Control","2.2.6 Power System Stabilizers","2.2.6(2)","2015-09-25","Generation Entities shall notify their QSEs of any change in PSS status (e.g. PSS unavailability due to maintenance or failure and when the PSS returns to normal operation).  QSEs shall notify ERCOT and the TO at the POI of any change in PSS status and shall supply PSS status logs to ERCOT upon request per Protocol Section 6.5.5.1, Changes in Resource Status.","QSE/\nRE"]
[19,"PSS","2 System Operations and Control Requirements, 2.2 System Monitoring and Control","2.2.6 Power System Stabilizers","2.2.6(3)","2015-09-25","Synchronous Generation Resources greater than 10 MW installed after January 1, 2008 and on or before December 1, 2010 shall install a PSS and place the PSS in service by June 1, 2011.  Synchronous Generation Resources greater than 10 MW installed after December 1, 2010 shall install a PSS and place the PSS in-service prior to the commercial operation start date of the Generation Resource.  The Generation Resource shall establish PSS settings to dampen modes with oscillations within the range of 0.2 Hz to 2 Hz.  The PSS settings shall be tested and tuned to ensure the PSS has appropriate damping characteristics.  Final PSS settings shall be provided to ERCOT and the TSP within 30 days of the PSS in-service date.","RE","submission/notification Via QSE(EMO)\n"]
[20,"PSS","2 System Operations and Control Requirements, 2.2 System Monitoring and Control","2.2.6 Power System Stabilizers","2.2.6(4)","2015-09-25","Synchronous Generation Resources greater than 10 MW installed before January 1, 2008 are subject to the following requirements: (a) All Generation Resources that are in this category shall notify ERCOT and the TSP:\n(i) Whether or not a PSS has been installed; and\n(ii) Whether or not PSS settings have been determined and the PSS has been or will be placed in-service.\n(b) If a PSS was in-service prior to January 1, 2008, the PSS shall remain in-service with the established PSS settings, provided that ERCOT may direct the Generation Resource to modify the settings. The PSS settings shall be tested and tuned to ensure the PSS has appropriate damping characteristics.\n(c) If a PSS is newly installed and/or placed in-service the Generation Resource shall establish PSS settings to dampen modes with oscillations within the range of 0.2 Hz to 2 Hz. The PSS settings shall be tested and tuned to ensure the PSS has appropriate damping characteristics. Final PSS settings shall be provided to ERCOT and the TSP within 30 days of the PSS in-service date.","RE"]
[21,"PSS","2 System Operations and Control Requirements, 2.2 System Monitoring and Control","2.2.6 Power System Stabilizers","2.2.6(5)","2015-09-25","If an excitation system on a synchronous Generation Resource greater than 10 MW is modified or replaced after January 1, 2008, the Generation Resource shall install a PSS, establish PSS settings to dampen modes with oscillations within the range of 0.2 Hz to 2 Hz, and place the PSS in-service.  The settings shall be tested and tuned to ensure the excitation system has appropriate damping characteristics.  Final PSS settings shall be provided to ERCOT and the TSP within 30 days of the PSS in-service date.","RE","submission/notification Via QSE(EMO)"]
[22,"PSS","2 System Operations and Control Requirements, 2.2 System Monitoring and Control","2.2.6 Power System Stabilizers","2.2.6(6)","2015-09-25","If it is determined that a change in PSS settings or the addition of a PSS to a synchronous Generation Resource would improve overall system performance, ERCOT shall coordinate with the Generation Resource owner to determine appropriate settings.  Within 180 days of determining appropriate settings, the Generation Resource owner shall revise the PSS setting and/or install the PSS.  Any PSS setting established pursuant to this section shall be established to dampen modes with oscillations as directed by ERCOT and place the PSS in-service.  Final PSS settings shall be provided to ERCOT and the TSP within 30 days of the PSS in-service date.","RE","submission/notification Via QSE(EMO)"]
[23,"PSS","2 System Operations and Control Requirements, 2.2 System Monitoring and Control","2.2.6 Power System Stabilizers","2.2.6(7)","2015-09-25","At least every five years, Generation Entities shall conduct performance tests on PSS settings or verify PSS performance based on operational data.  If PSS equipment characteristics are modified, the Generation Entity shall conduct a performance test within 30 days of the modification.  Final PSS settings shall be provided to ERCOT and the TSP within 30 days of the PSS in-service date.","RE","submission/notification Via QSE(EMO)"]
[24,"PSS","2 System Operations and Control Requirements, 2.2 System Monitoring and Control","2.2.6 Power System Stabilizers","2.2.6(8)","2015-09-25","The results of PSS tests or PSS performance verification shall be supplied to ERCOT and the TSP within 30 days of a request from ERCOT.","RE","submission/notification Via QSE(EMO)"]
[25,"Governor","2 System Operations and Control Requirements, 2.2 System Monitoring and Control","2.2.7 Turbine Speed Governors","2.2.7(1)","2015-09-25","A Governor shall be in-service whenever the Generation Resource is providing energy to the ERCOT Transmission Grid.","RE"]
[26,"Governor","2 System Operations and Control Requirements, 2.2 System Monitoring and Control","2.2.7 Turbine Speed Governors","2.2.7(2)","2015-09-25","Resource Entities shall conduct Governor performance tests for each Generation Resource or Wind-powered Generation Resource (WGR) at least every two years using one of the test methods or historical methods specified in Section 8, Attachment C, Turbine Governor Speed Tests.  The Resource Entity shall then provide test results to ERCOT.","RE","submission/notification Via QSE(EMO)"]
[27,"Governor","2 System Operations and Control Requirements, 2.2 System Monitoring and Control","2.2.7 Turbine Speed Governors","2.2.7(3)","2015-09-25","Every effort should be made to maintain Primary Frequency Response.  Maintenance tests on Governors shall demonstrate calibration for operation consistent with a generator droop characteristic of no greater than 5% but no less than 2% and Governor Dead-Band no greater than +/- 0.036 Hz.","RE"]
[28,"Governor","2 System Operations and Control Requirements, 2.2 System Monitoring and Control","2.2.7 Turbine Speed Governors","2.2.7(4)","2015-09-25","There are elements that can contribute to poor Primary Frequency Response.  These include: (a) Governor Dead-Band in excess of +/- 0.036 Hz (measured from 60 Hz);\n(b) Valve position limits; (c) Blocked Governor operation;\n(d) Control mode;\n(e) Adjustable rates or limits;\n(f) Boiler/turbine coordinated control or set point control action; and\n(g) Automated “reset” or similar control action of the turbine’s MW set point.","RE","Related requirement is in 2.2.7(5)"]
[29,"Governor","2 System Operations and Control Requirements, 2.2 System Monitoring and Control","2.2.7 Turbine Speed Governors","2.2.7(5)","2015-09-25","Every attempt should be made to minimize the effects of the elements listed in item (4) above on the Governor operation for the duration of all frequency deviations.  Each Resource Entity should monitor its Generation Resources to verify these elements do not contribute to a Governor droop characteristic of no greater than 5% but no less than 2%.","RE"]
[30,"Performance/Disturbance/Compliance","2 System Operations and Control Requirements, 2.2 System Monitoring and Control","2.2.8 Performance/Disturbance/Compliance Analysis","2.2.8(1)","2015-09-25","Performance/Disturbance/Compliance analysis shall be performed by ERCOT for the purpose of ensuring conformance with the Protocols.  All Generation Resources and Controllable Load Resources, except nuclear-powered Resources or WGRs with a permanent exemption approved by ERCOT, must respond to frequency disturbances with a Governor droop of 5% or less.","RE"]
[31,"Performance/Disturbance/Compliance","2 System Operations and Control Requirements, 2.2 System Monitoring and Control","2.2.8 Performance/Disturbance/Compliance Analysis","2.2.8(3)","2015-09-25","ERCOT shall make a regular report on selected system disturbances, documenting the response of individual Generation Resources and Controllable Load Resources.  In addition, Resource Entities, QSEs, and individual members of the PDCWG are encouraged to work within their respective companies to enhance the performance of individual Generation Resource’s or Controllable Load Resource’s control systems through application of the results of the PDCWG studies.","-"]
[32,"Time Synchronization","2 System Operations and Control Requirements, 2.2 System Monitoring and Control","2.2.9 Time Error and Time Synchronization","2.2.9.2","2015-09-25","To promote accurate data reporting during an Energy Emergency Alert (EEA) and other system events, and to ensure transaction schedules are simultaneous, all QSEs and TOs, and ERCOT will maintain their control system time within ±3 seconds of the National Bureau of Standards (NBS) time signal.  The NBS time signal shall set the time standard for ERCOT.  ERCOT, QSEs and TOs are required to employ clocks, voice and data recording systems that synchronize automatically with the NBS on at least a weekly basis.","QSE/\nTO"]
[33,"Generation Resource Response Time","2 System Operations and Control Requirements, 2.2 System Monitoring and Control","2.2.10 Generation Resource Response Time Requirements","2.2.10(1)","2015-09-25","All Generation Resources providing VSS as described in Protocol Section 3.15, Voltage Support, shall maintain the necessary procedures and processes plus communications, telemetry, remote control, automation, and staffing in order to normally comply with the response times listed below when a VSS Dispatch Instruction as described in Protocol Section 6.5.7.7, Voltage Support Service, is given to the Generation Resource or the QSE representing a Generation Resource.  Compliance is based upon normal operating conditions where VSS Dispatch Instructions respect all equipment operating limits and other restrictions that are periodically placed on equipment.  The response time to a Dispatch Instruction shall commence with the successful receipt by the appropriate Entity.","QSE/\nRE","Protocols 3.15(2):\nAll Generation Resources (including self-serve generating units) that have a gross generating unit rating greater than 20 MVA or those units connected at the same Point of Interconnection (POI) that have gross generating unit ratings aggregating to greater than 20 MVA, that supply power to the ERCOT Transmission Grid, shall provide Voltage Support Service (VSS)."]
[34,"Generation Resource Response Time","2 System Operations and Control Requirements, 2.2 System Monitoring and Control","2.2.10 Generation Resource Response Time Requirements","2.2.10(2)","2015-09-25","In a Force Majeure Event, compliance with VSS Dispatch Instructions shall not be required.  TSPs and QSEs shall follow Dispatch Instructions for VSS except under those exemptions described in paragraphs (1) and (2) of Protocol Section 6.5.7.9, Compliance with Dispatch Instructions.","QSE/\nTSP"]
[35,"Generation Resource Response Time","2 System Operations and Control Requirements, 2.2 System Monitoring and Control","2.2.10 Generation Resource Response Time Requirements","2.2.10(3)","2015-09-25","The required VSS response times for Generation Resources are: (a) For automatically switchable static VAR capable devices, when voltage or reactive measurements at the point of interconnection are outside of the limits as specified in paragraph (d) of Protocol Section 3.15.2, TSP and DSP Responsibilities Related to Voltage Support; then the response (within the operating Reactive Power capability of the Generation Resource) must be sufficient to initiate response in no more than one minute and return the measurement within the required range in no more than five minutes.\n(b) Response to a VSS Dispatch Instructions from ERCOT or authorized VSS Dispatch Instructions from a TSP, within the Reactive Power capability of the Generation Resource shall be completed in no more than five minutes of the receipt of a Dispatch Instruction.","RE"]
[36,"Generation Resource Response Time","2 System Operations and Control Requirements, 2.2 System Monitoring and Control","2.2.10 Generation Resource Response Time Requirements","2.2.10(4)","2015-09-25","Shutting down and disconnecting Generation Resources from the ERCOT Transmission Grid: (a) On-Line Generation Resources must be able to commence their shutdown sequence within five minutes of receipt of a Dispatch Instruction from ERCOT. Nuclear-fueled Generation Resources shall comply with the procedural requirements of the Nuclear Regulatory Commission (NRC) when receiving Dispatch Instructions from ERCOT to disconnect the Generation Resource from the ERCOT Transmission Grid.\n(b) If the ERCOT Transmission Grid condition requires breaker or switch operations needed to disconnect a non-MW producing generator from the system shall be completed as soon as practical, but no longer than 15 minutes of the receipt of a Dispatch Instruction from ERCOT. Once disconnected from the ERCOT Transmission Grid, a Generation Resource shall complete as soon as practical, but no longer than 15 minutes, the required switching to return the system to a normal configuration except for nuclear-fueled Generation Resources which shall comply with the procedural requirements of the NRC when receiving Dispatch Instructions from ERCOT to disconnect the Generation Resource from the ERCOT Transmission Grid.","RE"]
[37,"Ancillary Services - RRS","2 System Operations and Control Requirements, 2.3 Ancillary Services","2.3.1 Responsive Reserve, 2.3.1.2 Additional Operational Details for Responsive Reserve Providers","2.3.1.2(1)","2015-09-25","ERCOT shall specify the minimum amount of RRS provided by Generation Resources.  QSE’s Generation Resources providing RRS must be On-Line and capable of ramping to the awarded output level within ten minutes of the notice to deploy energy, must be immediately responsive to system frequency, and must be able to maintain the scheduled level for the period of service commitment.","QSE/\nRE"]
[38,"Ancillary Services - RRS","2 System Operations and Control Requirements, 2.3 Ancillary Services","2.3.1 Responsive Reserve, 2.3.1.2 Additional Operational Details for Responsive Reserve Providers","2.3.1.2(2)","2015-09-25","RRS provided by a QSE shall meet the requirements as defined in item (3) of Protocol Section 3.18, Resource Limits in Providing Ancillary Service. ","QSE"]
[39,"Ancillary Services - RRS","2 System Operations and Control Requirements, 2.3 Ancillary Services","2.3.1 Responsive Reserve, 2.3.1.2 Additional Operational Details for Responsive Reserve Providers","2.3.1.2(6)","2015-09-25","Load Resources providing RRS must be either a Controllable Load Resource qualified for Security-Constrained Economic Dispatch (SCED) and capable of providing Primary Frequency Response or a Load Resource controlled by high-set under-frequency relays for automatic interruption. For eligibility to participate as a RRS provider, reference Protocol Section 8.1.1.2.1.2, Responsive Reserve Service Qualification. Load Resources controlled by high-set under-frequency relays shall also complete the following requirements:\n(a) The under-frequency relay must have a delay of no more than 20 cycles (or 0.33 seconds for relays that do not count cycles). Total time from the time frequency first decays to a value low enough to initiate action of the under frequency relay(s) to the time Load is interrupted should be no more than 30 cycles, including all relay and breaker operating times;\n(b) The initiation setting of the under-frequency relay shall not be any lower than 59.7 Hz; and\n(c) The Load Resource must be able to remain interrupted during actual event until replaced by other net dependable capability. In no case may interrupted Load be restored to service without the approval of an ERCOT operator.","?"]
[40,"Ancillary Services - RRS","2 System Operations and Control Requirements, 2.3 Ancillary Services","2.3.1 Responsive Reserve, 2.3.1.2 Additional Operational Details for Responsive Reserve Providers","2.3.1.2(7)","2015-09-25","To become and remain fully qualified as a provider of RRS, the Load Resource shall complete the requirements above and the following:\n(a) Pass simulated or actual testing according to ERCOT procedures; and\n(b) Perform verification testing as described in Section 8, Attachment G, Load Resource Tests.","?"]
[41,"Ancillary Services - RRS","2 System Operations and Control Requirements, 2.3 Ancillary Services","2.3.1 Responsive Reserve, 2.3.1.2 Additional Operational Details for Responsive Reserve Providers","2.3.1.2(8)","2015-09-25","A Direct Current Tie (DC Tie) may be used as RRS up to 30 MW subject to the following constraints:   \n(a) The tie shall respond with increased deliveries to ERCOT or decreased deliveries from ERCOT at a frequency of 59.9 Hz;\n(b) The response rate will not be less than 30 MW per minute;\n(c) The response delay will not exceed four seconds;\n(d) The response will be retained until frequency has recovered to a level at or above 60.00 Hz or as directed by ERCOT;\n(e) A QSE claiming DC Tie RRS must demonstrate the existence of contracts agreeing to provide the required response with the DC Tie operator; and\n(f) A QSE claiming DC Tie RRS must have an agreement with the balancing authority on the opposite side of the DC Tie involved approving the amount and conditions.","?\nQSE"]
[42,"Ancillary Services - Non-Spin","2 System Operations and Control Requirements, 2.3 Ancillary Services","2.3.2 Non-Spinning Reserve Service, 2.3.2.1 Additional Operational Details for Non-Spinning Reserve Providers","2.3.2.1(1)","2015-09-25","Non-Spin Service Generation Resource providers must be capable of being synchronized and ramped to a specified output level within 30 minutes of notification of deployment and run at a specified output level for at least one hour, as specified in item (1)(a) of Protocol Section 3.17.3, Non-Spinning Reserve Service.","QSE/\nRE","Service provided via QSE(EMO)"]
[43,"Ancillary Services - Non-Spin","2 System Operations and Control Requirements, 2.3 Ancillary Services","2.3.2 Non-Spinning Reserve Service, 2.3.2.1 Additional Operational Details for Non-Spinning Reserve Providers","2.3.2.1(2)","2015-09-25","Non-Spin Controllable Load Resource providers must be capable of ramping to an ERCOT-instructed consumption level within 30 minutes and consuming at the ERCOT-instructed level for at least one hour, as specified in item (1)(b) of Protocol Section 3.17.3.","?"]
[44,"Ancillary Services - Non-Spin","2 System Operations and Control Requirements, 2.3 Ancillary Services","2.3.2 Non-Spinning Reserve Service, 2.3.2.1 Additional Operational Details for Non-Spinning Reserve Providers","2.3.2.1(3)","2015-09-25","To become provisionally qualified as a provider of Non-Spin, a Controllable Load Resource shall complete the following requirements:\n(a) Register as a Controllable Load Resource with ERCOT;\n(b) Complete asset registration of the Controllable Load Resource;\n(c) Provide ERCOT the appropriate Non-Spinning Load affidavit;\n(d) Test to verify appropriate voice communications are in place for VDIs by ERCOT;\n(e) Provide telemetry through the QSE to ERCOT in accordance with all applicable requirements set forth in paragraph (5) of Protocol Section 6.5.5.2, Operational Data Requirements; and\n(f) Be able to consume at an ERCOT-instructed level during an ERCOT deployment for a minimum of one hour up to a maximum of the hours of service responsibility.","?"]
[45,"Ancillary Services - Non-Spin","2 System Operations and Control Requirements, 2.3 Ancillary Services","2.3.2 Non-Spinning Reserve Service, 2.3.2.1 Additional Operational Details for Non-Spinning Reserve Providers","2.3.2.1(4)","2015-09-25","To become and remain fully qualified as a provider of Non-Spin, the Controllable Load Resource shall complete all the requirements for provisional qualification identified above and the following:\n(a) Respond successfully to an actual ERCOT deployment or pass simulated or actual testing according to ERCOT’s Procedure; and\n(b) Perform verification testing as described in Section 8, Attachment G, Load Resource Tests.","?"]
[46,"UFLS","2 System Operations and Control Requirements, 2.6 Requirements for Under-Frequency Relaying","2.6.1 Automatic Firm Load Shedding","2.6.1(1)","2015-09-25","At least 25% of the ERCOT System Load that is not equipped with high-set under-frequency relays shall be equipped at all times with provisions for automatic under-frequency load shedding.  The under-frequency relays shall be set to provide Load relief as follows:\nFrequency Threshold         Load Relief\n             59.3 Hz                      5% of the ERCOT System Load\n             58.9 Hz                      Additional 10% of the ERCOT System Load\n             58.5 Hz                      Additional 10% of the ERCOT System Load","DSP","PRC-006"]
[47,"UFLS","2 System Operations and Control Requirements, 2.6 Requirements for Under-Frequency Relaying","2.6.1 Automatic Firm Load Shedding","2.6.1(2)","2015-09-25","With the assistance of applicable Transmission Service Providers (TSPs), ERCOT will, prior to the peak each year, survey each Distribution Service Provider’s (DSP’s) compliance with the automatic Load shedding steps above, and report its findings to the Technical Advisory Committee (TAC).  For minimum compliance, DSPs are obligated to meet the prescribed percent values at all times.  It is not permitted to use rounding to meet the minimum.","DSP","PRC-006"]
[48,"UFLS","2 System Operations and Control Requirements, 2.6 Requirements for Under-Frequency Relaying","2.6.1 Automatic Firm Load Shedding","2.6.1(3)","2015-09-25","Additional under-frequency relays may be installed on Transmission Facilities with the approval of ERCOT provided the relays are set at 58.0 cycles or below, are not directional, and have at least 2.0 seconds time delay.  A DSP may by mutual agreement arrange to have all or part of its automatic Load shedding requirement performed by another entity.  ERCOT will be notified and provided with the details of any such arrangement prior to implementation.","DSP","PRC-006"]
[49,"UFLS","2 System Operations and Control Requirements, 2.6 Requirements for Under-Frequency Relaying","2.6.1 Automatic Firm Load Shedding","2.6.1(4)","2015-09-25","DSPs shall ensure, to the extent possible, and under the direction of ERCOT, that Loads equipped with under-frequency relays are dispersed geographically throughout the ERCOT Region to minimize the impact of Load shedding within a given geographical area.  Customers equipped with under-frequency relays shall be dispersed without regard to which Load Serving Entity (LSE) serves the customer.  DSPs shall ensure that the under-frequency relays connected to each Load will operate with a fixed time delay of no more than 30 cycles.  Total time from the time when frequency first reaches one of the values specified above to the time Load is interrupted should be no more than 40 cycles, including all relay and breaker operating times.","DSP","PRC-006"]
[50,"UFLS","2 System Operations and Control Requirements, 2.6 Requirements for Under-Frequency Relaying","2.6.1 Automatic Firm Load Shedding","2.6.1(5)","2015-09-25","If a loss of Load occurs due to the operation of under-frequency relays, a Transmission Operator (TO) designated by a DSP to shed Load may rotate the physical Load interrupted to minimize the duration of interruption experienced by individual Customers or to restore the availability of under-frequency Load-shedding capability.  In no event shall the initial total amount of Load without service be decreased by a TO without the approval of ERCOT.  TOs, in coordination with DSPs, shall make every reasonable attempt to restore Load, either by automatic or manual means, to preserve system integrity.  Restoration of any Load shed by Under-Frequency Load Shedding (UFLS) systems shall be coordinated with ERCOT.","DSP/\nTO","PRC-006"]
[51,"UFLS","2 System Operations and Control Requirements, 2.6 Requirements for Under-Frequency Relaying","2.6.1 Automatic Firm Load Shedding","2.6.1(6)","2015-09-25","Whenever possible, TOs and DSPs shall not manually drop Load connected to under-frequency relays during the implementation of Level 3 of an Energy Emergency Alert (EEA).","DSP/\nTO","PRC-006"]
[52,"UFR & OFR","2 System Operations and Control Requirements, 2.6 Requirements for Under-Frequency Relaying","2,6,2 Generators","2.6.2(1)","2015-09-25","If under-frequency relays are installed and activated to trip the unit, these relays shall be set such that the automatic removal of individual Generation Resources from the ERCOT System meets the following requirements:\n          Frequency Range                             Delay to Trip\n            Above  59.4 Hz                       No automatic tripping\n       >58.4 Hz & <=59.4 Hz                Not less than 9 minutes\n       >58 Hz & <=58.4 Hz                   Not less than 30 seconds\n       >57.5 Hz & <=58 Hz                   Not less than 2 seconds\n               <=57.5 Hz                            No time delay requried","RE"]
[53,"UFR & OFR","2 System Operations and Control Requirements, 2.6 Requirements for Under-Frequency Relaying","2,6,2 Generators","2.6.2(2)","2015-09-25","If over-frequency relays are installed and activated to trip the unit, they shall be set such that the automatic removal of individual Generation Resources from the ERCOT System meets the following requirements:\nThis Operating Guide is not intended to conflict with the plant operator’s responsibility to protect Generation Resources from potentially damaging operating conditions:\nFrequency Range                                             Delay to Trip\nBelow 60.6 Hz down to and including 60 Hz  No automatic tripping (Continuous operation)\nBelow 61.6 Hz down to and including 60.6 Hz     Not less than 9 minutes\nBelow 61.8 Hz down to and including 61.6 Hz     Not less than 30 seconds\n61.8 Hz or above                                                  No time delay required","RE"]
[54,"UFR & OFR","2 System Operations and Control Requirements, 2.6 Requirements for Under-Frequency Relaying","2,6,2 Generators","2.6.2(3)","2015-09-25","The Resource Entity that owns Generation Resources that are unable to comply shall provide to ERCOT an explanation of the limitations including, but not limited to, study results or manufacturer’s advice.","RE"]
[55,"Voltage Profile","2 System Operations and Control Requirements, 2.7 System Voltage Profile","2.7.1 Introduction","2.7.1(2)","2015-09-25","ERCOT shall coordinate and conduct studies with the Transmission Service Providers (TSPs) to determine the normally desired Voltage Profile for all Generation Resource busses in the ERCOT Region as specified in item (1) of Protocol Section 3.15, Voltage Support, as published on the Market Information System (MIS) Secure Area.","TSP","VAR-001-4"]
[56,"Voltage Profile","2 System Operations and Control Requirements, 2.7 System Voltage Profile","2.7.2 Maintaining Voltage Profile","2.7.2(a)","2015-09-25","Operations Engineering\n(i) All voltage limits must be based on sound engineering studies that use the appropriate Network Operations Model. TSP study results should be made available to ERCOT; and\n(ii) Transfer limits shall reflect voltage and/or reactive restrictions.","TSP","VAR-001-4"]
[57,"Voltage Profile","2 System Operations and Control Requirements, 2.7 System Voltage Profile","2.7.2 Maintaining Voltage Profile","2.7.2(b)","2015-09-25","Coordination\n(i) Entities must coordinate high voltage limits in order to guarantee that the maximum continuous over-voltage of equipment is not exceeded. Transmission Operators (TOs) shall notify ERCOT of normal operating voltage limits and post-contingency voltage limits for each bus;\n(ii) Low voltage limits must be coordinated in order to prevent one Entity from being a burden to another;\n(iii) Voltage limits shall not be violated during all normal and Credible Single Contingency conditions; and\n(iv) The operation of all Reactive Power devices under the control of a TO or a Qualified Scheduling Entity (QSE) will be coordinated under the direction of ERCOT to maintain transmission voltage levels within normal limits and post-contingency voltages within post contingency limits. Static reactive devices will be managed to ensure that adequate dynamic reactive reserves are maintained at all times.","TO","VAR-001-4"]
[58,"Voltage Profile","2 System Operations and Control Requirements, 2.7 System Voltage Profile","2.7.2 Maintaining Voltage Profile","2.7.2(c)(i)","2015-09-25","Notification\n(i) Generation Resources with voltage problems shall notify the TO to whom they are directly connected. TOs shall notify other affected TOs and ERCOT;; ","RE/\nTO","VAR-001-4"]
[59,"Voltage Profile","2 System Operations and Control Requirements, 2.7 System Voltage Profile","2.7.2 Maintaining Voltage Profile","2.7.2(d)(i)","2015-09-25","When the voltage levels deviate from established limits, ERCOT or the TO shall take immediate steps to relieve the condition using all available reactive resources.","TO","VAR-001-4"]
[60,"Voltage Profile","2 System Operations and Control Requirements, 2.7 System Voltage Profile","2.7.2 Maintaining Voltage Profile","2.7.2(e)(i)","2015-09-25","TOs shall provide telemetry to ERCOT on all major transmission bus voltages.","TO","VAR-001-4"]
[61,"Voltage Profile","2 System Operations and Control Requirements, 2.7 System Voltage Profile","2.7.2 Maintaining Voltage Profile","2.7.2(g)(i)","2015-09-25","Each TO must maintain a voltage/reactive plan for normal and Emergency Conditions and will provide this plan to adjacent TOs as well as ERCOT upon request.","TO","VAR-001-4"]
[62,"Voltage Profile","2 System Operations and Control Requirements, 2.7 System Voltage Profile","2.7.2 Maintaining Voltage Profile","2.7.2(h)","2015-09-25","Emergency or Abnormal Conditions\n(i) Transmission systems shall be designed so that effective reactive reserves shall be available without de-energizing other Facilities or shedding Load under normal conditions;\n(ii) Major transmission lines shall be kept in service during light Load as much as possible. Lines should only be removed after all applicable reactive controls are implemented and studies show that reliability will not be degraded; and\n(iii) Voltage reduction should not be done on the transmission system unless coordinated with adjacent TOs.","?"]
[63,"Voltage Support","2 System Operations and Control Requirements, 2.7 System Voltage Profile","2.7.3 Special Considerations for Nuclear Power Plants","2.7.3","2015-09-25","In all planning studies and Real-Time operations, ERCOT and TOs shall maintain the switchyard voltage at each nuclear power plant at a value that does not violate its licensing basis with the Nuclear Regulatory Commission (NRC). ERCOT shall notify the QSE representing a nuclear power plant of the result of any studies where the voltage at the plant switchyard cannot be adequately maintained. ERCOT and the TO shall monitor the voltage in Real-Time. ERCOT shall provide notice to the QSE representing the nuclear power plant of any voltage inadequacy at the plant switchyard that cannot be corrected within 30 minutes. High and low limits on switchyard voltage at each nuclear power plant necessary to meet these requirements shall be specified in ERCOT Procedures.","TO"]
[64,"Voltage Support","2 System Operations and Control Requirements, 2.7 System Voltage Profile","2.7.4 Reactive Considerations for Generation Resources","2.7.4.1(3)","2015-09-25","Except under Force Majeure conditions or ERCOT-permitted operation of the Generation Resource, failure of a Generation Resource required to provide VSS to provide either leading or lagging reactive up to the required capability of the unit upon request from a TO or ERCOT may, at the discretion of ERCOT, be reported to the Texas Reliability Entity (Texas RE).","QSE/\nRE","NP 3.15.3(5)"]
[65,"Voltage Support","2 System Operations and Control Requirements, 2.7 System Voltage Profile","2.7.4 Reactive Considerations for Generation Resources","2.7.4.1(4)","2015-09-25","Except under Force Majeure conditions or ERCOT-permitted operation of the Generation Resource, if a Generation Resource required to provide VSS fails to maintain transmission system voltage at the point of interconnection with the TSP within 2% of the voltage profile while operating at less than the maximum reactive capability of the Generation Resource, ERCOT may, at its discretion, report this to the Texas RE.","QSE/\nRE","NP 3.15.3(5)"]
[66,"Standard Reactor and Capacitor Switching Plan","2 System Operations and Control Requirements, 2.7 System Voltage Profile","2.7.4 Reactive Considerations for Generation Resources, 2.7.4.2 Parameters for Standard Reactor and Capacitor Switching Plan","2.7.4.2","2015-09-25","TOs shall provide switching plans for automatically controlled reactors, capacitors, and other reactive controlled sources to ERCOT.  For manually switched reactive devices, the TO shall provide its guidelines for the operation of these devices.  These plans and guidelines shall be posted on the MIS Secure Area and must be provided in accordance with the Network Operations Model Change Request (NOMCR) or other ERCOT prescribed process. The parameters to be provided in the standard reactor and capacitor switching plan as required by Protocol Section 3.10.7.1.5, Reactors, Capacitors, and other Reactive Controlled Sources are as follows:\nDevice Attributes \n(a) Transmission Element name per Protocol Section 3.10.7.1, Modeling of Transmission Elements and Parameters; \n(b) Substation name; and\n(c) Schedules of device: \n(i) Time-based;\n(ii) Voltage-based;\n(iii) Load-based;\n(iv) Contingency-based;\n(v) Normal Operation;\n(vi) Emergency Operation;\n(vii) Seasonal; and\n(viii) Others as required by technology.","TO","VAR-001-4"]
[67,"Voltage Control","2 System Operations and Control Requirements, 2.7 System Voltage Profile","2.7.4 Reactive Considerations for Generation Resources, 2.7.4.3 Unit Dispatch Beyond the Corrected Unit Reactive Limit or Unit Reactive Limit","2.7.4.3","2015-09-25","Each Generation Resource shall respond to ERCOT instructed voltage control, including exceeding its Corrected Unit Reactive Limit (CURL) or Unit Reactive Limit (URL). For multi-generator busses, ERCOT shall not instruct any single Generation Resource to operate beyond its CURL or URL until all Generation Resources On-Line and interconnected at the same transmission bus, have been instructed to their respective CURLs or URLs.  ","QSE/\nRE","via QSE(EMO)?"]
[68,"Voltage Ride-Through","2 System Operations and Control Requirements, 2.9 Voltage Ride-Through Requirements for Generation Resources","2.9 Voltage Ride-Through Requirements for Generation Resources","2.9(1)","2015-09-25","The facility’s generation machine characteristics and plant design shall incorporate the firm Load shedding philosophy and criteria defined in this Section.  Inherent in this philosophy is the idea that all generators remain On-Line until all steps of firm Load shedding have been executed.","RE"]
[69,"Voltage Ride-Through","2 System Operations and Control Requirements, 2.9 Voltage Ride-Through Requirements for Generation Resources","2.9 Voltage Ride-Through Requirements for Generation Resources","2.9(2)","2015-09-25","Generation Resources must be designed and generation voltage relays must be set to remain connected to the transmission system during the following operating conditions: (a) Generator terminal voltages are within 5% of the rated design voltage and volts per hertz are less than 105% of generator rated design voltage and frequency; (b) Generator terminal voltage deviations exceed 5% but are within 10% of the rated design voltage and persist for less than ten seconds;\n(c) Generator volts per hertz conditions are less than 116% of generator rated design voltage and frequency and last for less than 1.5 seconds;\n(d) A transmission system fault (three-phase, single-phase or phase-to-phase), but not a generator bus fault, is cleared by the protection scheme coordinated between the Generation Entity and the Transmission Service Provider (TSP) on any line connected to the generator’s transmission interconnect bus, provided such lines are not connected to induction generators described in paragraph (9) of Protocol Section 3.15, Voltage Support; and\n(e) In the case of a generator bus fault or a primary transmission system relay failure, the generator protective relaying may clear the generator","RE"]
[70,"Voltage Ride-Through","2 System Operations and Control Requirements, 2.9 Voltage Ride-Through Requirements for Generation Resources","2.9 Voltage Ride-Through Requirements for Generation Resources","2.9(3)","2015-09-25","Generating Resources required to provide Voltage Support Service (VSS) shall have and maintain the following capability: (a) Over-excitation limiters shall be provided and coordinated with the thermal capability of the generator field winding and protective relays in order to permit short-term reactive capability that allows at least 80% of the unit design standard (ANSI C50.13-1989), as follows:\nTime (seconds) 10 30 60 120\nField Voltage % 208 146 125 112\nAfter allowing temporary field current overload, the limiter shall operate through the automatic AC voltage regulator to reduce field current to the continuous rating. Return to normal AC voltage regulation after current reduction shall be automatic. The over-excitation limiter shall be coordinated with the over-excitation protection so that over-excitation protection only operates for failure of the voltage regulator/limiter.\n(b) Under-excitation limiters shall be provided and coordinated with loss-of-field protection to eliminate unnecessary generating unit disconnection as a result of operator error or equipment malfunction.","RE"]
[71,"Voltage Ride-Through","2 System Operations and Control Requirements, 2.9 Voltage Ride-Through Requirements for Generation Resources","2.9 Voltage Ride-Through Requirements for Generation Resources","2.9(4)","2015-09-25","Generation Resources shall have protective relaying necessary to protect its equipment from abnormal conditions as well as to be consistent with protective relaying criteria described in Section 6.2.6.3.4, Generator Protection and Relay Requirements.","RE"]
[72,"Voltage Ride-Through","2 System Operations and Control Requirements, 2.9 Voltage Ride-Through Requirements for Generation Resources","2.9 Voltage Ride-Through Requirements for Generation Resources","2.9(5)","2015-09-25","The Voltage Ride-Through (VRT) requirements do not apply to faults that occur between the generator terminals and the transmission voltage side of the Generator Step-Up (GSU) transformer, or when clearing the fault effectively disconnects the Generation Resources from the ERCOT System.","RE"]
[73,"Voltage Ride-Through","2 System Operations and Control Requirements, 2.9 Voltage Ride-Through Requirements for Generation Resources","2.9.1 Additional Voltage Ride-Through Requirements for Intermittent Renewable Resources","2.9.1(1)","2015-09-25","All Intermittent Renewable Resources (IRRs) shall also comply with the requirements of this Section, except as follows:\n(a) An IRR that interconnects to the ERCOT System pursuant to a Standard Generation Interconnection Agreement (SGIA) (i) executed on or before January 16, 2014 and (ii) under which the IRR provided all required financial security to the TSP on or before January 16, 2014, is not required to meet any high VRT requirement greater than 1.1 per unit voltage unless the interconnected IRR includes one or more turbines that differ from the turbine model(s) described in the SGIA (including any attachment thereto), as that agreement existed on January 16, 2014. Notwithstanding the foregoing, if the Resource Entity that owns or operates an IRR that was interconnected pursuant to an SGIA executed before January 16, 2014, under which the IRR provided all required financial security to the TSP on or before January 16, 2014, demonstrates to ERCOT’s satisfaction that the high VRT capability of the IRR is not lower than the capability of the turbine model(s) described in the SGIA (including any attachment thereto), as that agreement existed on January 16, 2014 that IRR is not required to meet the high VRT requirement in this Section.\n(b) An IRR that interconnects to the ERCOT System pursuant to an SGIA executed prior to November 1, 2008 is not required to meet VRT requirements presented in this Section. However, any WGR that is installed on or after November 1, 2008 and that initially synchronizes with the ERCOT System, pursuant to a Standard Generation Interconnection Agreement (SGIA) (i) executed on or before January 16, 2014, and (ii) under which the IRR provided all required financial security to the TSP on or before January 16, 2014 (except for an IRR installed pursuant to an SGIA executed before November 1, 2008) shall be VRT-capable in accordance with the low VRT requirements in this Section and high-voltage requirements in this Section up to 1.1 per unit voltage unless the interconnected IRR includes one or more turbines that differ from the turbine model(s) described in the SGIA (including any attachment thereto), as that agreement existed on January 16, 2014 in which case the IRR shall also be required to comply with the high VRT requirements of this section, subject to the exemption described in paragraph (a), above.\n(c) An IRR that is not technically capable of complying with a 1.2 per unit voltage high VRT requirement and that is not subject to either of the exemptions described in paragraphs (a) or (b), above, is not required to meet any high Voltage Ride-Through (VRT) requirement greater than 1.1 per unit voltage until January 16, 2016\n(d) Notwithstanding any of the foregoing provisions, an IRR’s VRT capability shall not be reduced over time.","?"]
[74,"Voltage Ride-Through","2 System Operations and Control Requirements, 2.9 Voltage Ride-Through Requirements for Generation Resources","2.9.1 Additional Voltage Ride-Through Requirements for Intermittent Renewable Resources","2.9.1(2)","2015-09-25","Each IRR shall provide technical documentation of VRT capability to ERCOT upon request.","?"]
[75,"Voltage Ride-Through","2 System Operations and Control Requirements, 2.9 Voltage Ride-Through Requirements for Generation Resources","2.9.1 Additional Voltage Ride-Through Requirements for Intermittent Renewable Resources","2.9.1(3)","2015-09-25","Each IRR is required to set generator voltage relays to remain in service for at least 0.15 seconds during all transmission faults and to allow the system to recover as illustrated in Figure 1, Default Voltage Ride-Through Boundaries for IRRs, below. Recovery time to 90% of per unit voltage should be within 1.75 seconds. Faults on individual phases with delayed clearing (zone 2) may result in phase voltages outside this boundary but if the phase voltages remain inside this boundary, then generator voltage relays are required to be set to remain connected and recover as illustrated in Figure 1.","?"]
[76,"Voltage Ride-Through","2 System Operations and Control Requirements, 2.9 Voltage Ride-Through Requirements for Generation Resources","2.9.1 Additional Voltage Ride-Through Requirements for Intermittent Renewable Resources","2.9.1(4)","2015-09-25","Each IRR shall remain interconnected during three-phase faults on the ERCOT System for a voltage level as low as zero volts with a duration of 0.15 seconds as measured at the Point of Interconnection (POI) unless a shorter clearing time requirement for a three-phase fault specific to the generating plant POI is determined by and documented by the TSP in conjunction with the SGIA. The clearing time requirement shall not exceed nine cycles.","?"]
[77,"Voltage Ride-Through","2 System Operations and Control Requirements, 2.9 Voltage Ride-Through Requirements for Generation Resources","2.9.1 Additional Voltage Ride-Through Requirements for Intermittent Renewable Resources","2.9.1(5)","2015-09-25","Each IRR shall set generator voltage relays to remain interconnected to the ERCOT System during the following high-voltage conditions, as illustrated in Figure 1: any per-unit voltage equal to or greater than 1.175 but less than 1.2 for up to 0.2 seconds, any per-unit voltage equal to or greater than 1.15 but less than 1.175 per unit voltage for up to 0.5 seconds, and any per-unit voltage equal to or greater than 1.1 but less than 1.15 for up to 1.0 seconds. The indicated voltages are measured at the POI.","?"]
[78,"Voltage Ride-Through","2 System Operations and Control Requirements, 2.9 Voltage Ride-Through Requirements for Generation Resources","2.9.1 Additional Voltage Ride-Through Requirements for Intermittent Renewable Resources","2.9.1(6)","2015-09-25","An IRR may be tripped Off-Line after the fault clearing period if this action is part of an approved Special Protection Systems (SPSs).","?"]
[79,"Voltage Ride-Through","2 System Operations and Control Requirements, 2.9 Voltage Ride-Through Requirements for Generation Resources","2.9.1 Additional Voltage Ride-Through Requirements for Intermittent Renewable Resources","2.9.1(7)","2015-09-25","VRT requirements may be met by the performance of the generators; by installing additional reactive equipment behind the POI; or by a combination of generator performance and additional equipment behind the POI. VRT requirements may be met by equipment outside the POI if documented in the SGIA.","?"]
[80,"Voltage Ride-Through","2 System Operations and Control Requirements, 2.9 Voltage Ride-Through Requirements for Generation Resources","2.9.1 Additional Voltage Ride-Through Requirements for Intermittent Renewable Resources","2.9.1(8)","2015-09-25","If an IRR fails to comply with the clearing time or recovery VRT requirement, then the IRR and the interconnecting TSP shall be required to investigate and report to ERCOT on the cause of the IRR trip, identifying a reasonable mitigation plan and timeline.","?"]
[81,"System Control Interfaces with ERCOT","3 Resource Testing and Qualification Procedures, 3.1 System Control Interfaces with ERCOT","3.1.1 Introduction","3.1.1","2015-09-25","Introduction\nThis section defines the specific responsibilities between Qualified Scheduling Entities (QSEs) and Transmission Service Providers (TSPs) to support ERCOT in the security and reliability of the ERCOT System.  Resource Entities may communicate directly with ERCOT under emergency and specific scheduling activities.  All other Entities operating in ERCOT shall communicate with their appropriate QSE or TSP.","QSE/\nTSP","QSE & TSP need to ensure all communications with ERCOT are conducted through them."]
[82,"System Control Interfaces with ERCOT","3 Resource Testing and Qualification Procedures, 3.1 System Control Interfaces with ERCOT","3.1.2 Compliance with Dispatch Instructions","3.1.2","2015-09-25","Compliance with Dispatch Instructions\nEach QSE and Transmission Operator (TO) within the ERCOT System shall comply fully and promptly with valid Dispatch Instructions as specified in Protocol Section 6.5.7.9, Compliance with Dispatch Instructions.","QSE/\nTO","IRO-001-1.1\nIRO-004-2"]
[83,"QSE Schedule Center and Back-Up Plan","3 Resource Testing and Qualification Procedures, 3.2 Qualified Scheduling Entities","3.2.1 Operating Obligations","3.2.1(1)","2015-09-25","A Qualified Scheduling Entity (QSE) shall maintain a 24x7 scheduling center with qualified personnel with the authority to commit and bind the QSE.  QSEs shall communicate with ERCOT for the purpose of meeting their obligations specified in the Protocols and these Operating Guides.  Each QSE shall designate an Authorized Representative as defined in Protocol Section 2.1, Definitions.","QSE"]
[84,"QSE Schedule Center and Back-Up Plan","3 Resource Testing and Qualification Procedures, 3.2 Qualified Scheduling Entities","3.2.1 Operating Obligations","3.2.1(2)","2015-09-25","Each QSE shall submit to ERCOT, by March 15 of each year, a written back-up control plan to continue operation in the event the QSE’s scheduling center becomes inoperable.  Back-up control plans shall be submitted to ERCOT via secured webmail or encrypted data transfer.  QSEs shall request that a secure email account be created with ERCOT by sending an email to shiftsupervisors@ercot.com.","QSE"]
[85,"QSE Schedule Center and Back-Up Plan","3 Resource Testing and Qualification Procedures, 3.2 Qualified Scheduling Entities","3.2.1 Operating Obligations","3.2.1(3)","2015-09-25","Each back-up control plan shall be reviewed and updated annually and shall include as a minimum, the following: (a) Description of actions to be taken by QSE personnel to avoid placing a prolonged burden on ERCOT and other Market Participants, while operating in back-up control mode;\n(b) Description of specific functions and responsibilities to be performed to continue operations from an alternate location; (c) Procedures and responsibilities for maintaining basic voice communications capabilities with ERCOT; and\n(d) Procedures for back-up control function testing and the training of personnel.","QSE"]
[86,"QSE Schedule Center and Back-Up Plan","3 Resource Testing and Qualification Procedures, 3.2 Qualified Scheduling Entities","3.2.1 Operating Obligations","3.2.1(4)","2015-09-25","As an option, the back-up control plan may include arrangements made with another Entity to provide the minimum back-up control functions in the event the QSE’s primary functions are interrupted.","QSE"]
[87,"QSE Schedule Center and Back-Up Plan","3 Resource Testing and Qualification Procedures, 3.2 Qualified Scheduling Entities","3.2.1 Operating Obligations","3.2.1(5)","2015-09-25","For connectivity requirements for back-up sites, refer to Section 7, Telemetry and Communication.","QSE"]
[88,"Changes in Resource Status","3 Resource Testing and Qualification Procedures, 3.2 Qualified Scheduling Entities","3.2.2 Changes in Resource Status","3.2.2(1)","2015-09-25","QSEs shall verbally notify ERCOT of unplanned changes in Load and Generation Resource status as soon as practicable following the event as referenced in Protocol Section 6.5.5.1, Changes in Resource Status.","QSE"]
[89,"Changes in Resource Status","3 Resource Testing and Qualification Procedures, 3.2 Qualified Scheduling Entities","3.2.2 Changes in Resource Status","3.2.2(2)","2015-09-25","QSEs shall verbally notify ERCOT and/or Transmission Service Provider (TSP) of equipment changes that affect the reactive capability of an operating Generation Resource.","QSE"]
[90,"Changes in Resource Status","3 Resource Testing and Qualification Procedures, 3.2 Qualified Scheduling Entities","3.2.2 Changes in Resource Status","3.2.2(3)","2015-09-25","QSEs shall submit a Current Operating Plan (COP) in accordance with Protocol Section 3.9, Current Operating Plan (COP).","QSE"]
[91,"Incident and Disturbance Reports","3 Resource Testing and Qualification Procedures, 3.2 Qualified Scheduling Entities","3.2.3 Regulatory Required Incident and Disturbance Reports","3.2.3(1)","2015-09-25","In the event of a system incident or disturbance, as described by North American Electric Reliability Corporation (NERC) and the Department of Energy (DOE), QSEs, and TSPs or their Designated Agents shall provide required reports to ERCOT, the DOE and/or NERC.  Types of incidents or disturbances which may trigger these reporting requirements are:\n(a) Uncontrolled loss of Load;\n(b) Load shed events;\n(c) Public appeal for reduced use of electricity;\n(d) Actual or suspected attacks on the transmission system;\n(e) Vandalism;\n(f) Actual or suspected cyber attacks;\n(g) Fuel supply emergencies;\n(h) Loss of electric service to large customers;\n(i) Loss of bulk transmission component that significantly reduces integrity of the transmission system;\n(j) Islanding of transmission system;\n(k) Sustained voltage excursions;\n(l) Major damage to power system components; and\n(m) Failure, degradation or misoperation of Special Protection Systems (SPS), Remedial Action Plans (RAPs) or other operating systems.  ","QSE/\nTSP","EOP-004-2"]
[92,"Ancillary Service Qualification and Testing","3 Resource Testing and Qualification Procedures, 3.2 Qualified Scheduling Entities","3.2.4 Ancillary Service Qualification and Testing Program","3.2.4(1)","2015-09-25","Resources designated to provide Ancillary Services must qualify with ERCOT prior to participation in the Ancillary Service market.","QSE/\nRE"]
[93,"Ancillary Service Qualification and Testing","3 Resource Testing and Qualification Procedures, 3.2 Qualified Scheduling Entities","3.2.4 Ancillary Service Qualification and Testing Program","3.2.4(4)","2015-09-25","ERCOT shall evaluate the actual performance of all Resources providing Ancillary Services in accordance with Protocol Section 8, Performance Monitoring.  ERCOT shall notify the QSE of a Resource failing to meet the performance requirements as specified in Protocol Section 8.   A Resource failing to meet the performance requirements for two consecutive months shall be required to develop and implement a corrective action plan to address its failure as specified in Protocol Section 8.4, ERCOT Response to Market Non-Performance.","QSE/\nRE"]
[94,"Ancillary Service Qualification and Testing","3 Resource Testing and Qualification Procedures, 3.2 Qualified Scheduling Entities","3.2.4 Ancillary Service Qualification and Testing Program","3.2.4(6)","2015-09-25","Any Resource with a revoked Ancillary Service qualification may be re-tested at the sole discretion of ERCOT only after demonstrating and implementing a corrective action plan as described in Protocol Section 8.4.","QSE/\nRE"]
[95,"Resource Entity Obligations","3 Resource Testing and Qualification Procedures, 3.3 Resource Entities","3.3 Resource Entities","3.3(1)","2015-09-25","The operation of a Generation Resource shall conform to the requirements of the Protocols, North American Electric Reliability Corporation (NERC) Reliability Standards and these Operating Guides.  As prescribed in Protocol Sections, 3.7.1.1, Generation Resource Parameters, 3.7.1.2, Load Resource Parameters, and 3.10.7.2, Modeling of Resources and Transmission Loads, the Qualified Scheduling Entities (QSEs) and Resource Entities shall provide ERCOT and the Transmission Service Provider (TSP) with modeling information describing each Generation and Load Resource.","RE"]
[96,"Resource Entity Obligations","3 Resource Testing and Qualification Procedures, 3.3 Resource Entities","3.3 Resource Entities","3.3(2)","2015-09-25","As prescribed in Protocol Section 3.10.7.1.4, Transmission and Generation Resource Step-Up Transformers, Resource Entities will provide information on Generator Step-Up (GSU) transformers to TSPs.","RE"]
[97,"Resource Entity Obligations","3 Resource Testing and Qualification Procedures, 3.3 Resource Entities","3.3 Resource Entities","3.3(3)","2015-09-25","As prescribed in Protocol Sections 3.10.7.5, Telemetry Criteria, 6.5.5.2, Operational Data Requirements, and 8, Performance Monitoring, the QSE reporting for a Resource Entity shall provide operational information for generation facilities greater than 10 MW.","QSE"]
[98,"Resource Entity Obligations","3 Resource Testing and Qualification Procedures, 3.3 Resource Entities","3.3 Resource Entities","3.3(4)","2015-09-25","At a minimum, a Resource Entity shall notify ERCOT and the QSE of the following: (a) 60 days prior to implementation of any planned equipment changes that affect the reactive capability of an operating Generation Resource.\n(b) Any such changes that decrease the reactive capability of the Generation Resource below the required level and changes that decrease the Voltage Ride-Through (VRT) capability of the plant must be approved by ERCOT prior to implementation;\n(c) As soon as practicable when high reactive loading or reactive oscillations on Generation Resources are observed; and\n(d) As soon as practicable when a Generation Resource trips Off-Line due to voltage or reactive problems.","RE"]
[99,"Resource Entity Obligations","3 Resource Testing and Qualification Procedures, 3.3 Resource Entities","3.3 Resource Entities","3.3(5)","2015-09-25","When scheduled to ERCOT, Resource Entities shall be staffed or monitored 24x7, by personnel capable of making operating decisions.  Each Resource Entity shall designate an Authorized Representative as defined in Protocol Section 2.1, Definitions.  This applies to all:\n(a) Generation Resources greater than 10 MW; and  \n(b) Load Resources.","RE"]
[100,"Resource Entity Obligations","3 Resource Testing and Qualification Procedures, 3.3 Resource Entities","3.3 Resource Entities","3.3(6)","2015-09-25","The Resource Entity shall implement the following in a reliable and safe manner and in accordance with the switching procedure of the directly connected TSP: (a) Synchronizing of the generation to the ERCOT System; and (b) Transmission switchyard switching or clearances.","RE"]
[101,"Resource Entity Obligations","3 Resource Testing and Qualification Procedures, 3.3 Resource Entities","3.3 Resource Entities","3.3(7)","2015-09-25","Any Resource or Customer-owned switching device that can interrupt flow through network transmission equipment, 60 kV or greater in nominal voltage, must have an agreement with the Transmission Operator (TO) to schedule Outages on, and perform emergency switching of, the device.","RE"]
[102,"Resource Entity Obligations","3 Resource Testing and Qualification Procedures, 3.3 Resource Entities","3.3 Resource Entities","3.3(8)","2015-09-25","The Generation Resource specifically licensed by a federal regulatory agency shall, through its QSE representative, provide any applicable grid interconnection and performance licensing requirements to ERCOT and the TSP to which the licensee is connected.","RE"]
[103,"Resource Entity Obligations","3 Resource Testing and Qualification Procedures, 3.3 Resource Entities","3.3 Resource Entities","3.3(9)","2015-09-25","The TSP is obligated to incorporate any such licensing requirements into its planning and operations, and ERCOT shall support such requirements.  Both ERCOT and the TSP will create necessary procedures for satisfying these requirements.  Such procedures will include provisions to notify the facility licensee through its QSE of any requirements that cannot be satisfied.","TSP"]
[104,"Resource Entity Obligations","3 Resource Testing and Qualification Procedures, 3.3 Resource Entities","3.3 Resource Entities","3.3(10)","2015-09-25","Any proposal for revision of this Operating Guide and the procedures incorporating the licensee requirements that would diminish the obligation or ability of ERCOT or the TSP to support these requirements shall be provided to the licensee through its QSE to afford it an opportunity for review and response.  Any such proposal that is approved, as a result of which the licensee is required to implement changes to meet its license requirements or to seek amendment to its license, shall become effective no sooner than six months following the approval. ","-"]
[105,"Resource Entity Obligations","3 Resource Testing and Qualification Procedures, 3.3 Resource Entities","3.3 Resource Entities","3.3(11)","2015-09-25","Resource Entities must provide Resource-owned Transmission Elements data requirements as prescribed in Protocol Section 3.10.7, ERCOT System Modeling Requirements.  Additional distribution voltage level devices and connectivity may be required as well to adequately represent the modeling of the Resource within ERCOT computer systems.","RE"]
[106,"Unit General Capacity Testing","3 Resource Testing and Qualification Procedures, 3.3 Resource Entities","3.3.1 Unit Capability Requirements","3.3.1(2)","2015-09-25","ERCOT shall allow the QSE three days to correct the omission by submitting ERCOT approved test results.   If the generating resource in question is operated during these three days, and no test results are provided to ERCOT, then the QSE shall be disqualified from provision of Ancillary Services.","-","Not a direct requirement for QSE.  However, it shows QSE has three days to provide test results for generating resources that fail to meet General Capacity Testing Requirements."]
[107,"Unit Reactive Capability","3 Resource Testing and Qualification Procedures, 3.3 Resource Entities","3.3.2 Unit Reactive Capability Requirements","3.3.2.1","2015-09-25","Corrected Unit Reactive Limits (CURL)\nThe reactive capability curve for each unit on the ERCOT System shall be submitted to ERCOT through the Market Information System (MIS) Certified Area and must contain the most limiting elements for the leading and lagging reactive output.  The limiting factors such as under-excitation limiters, over-excitation limiters, ambient temperature limitations across the MW range of the unit at the unit terminals or any other factor that limits the reactive output of the unit and is verifiable through engineering calculations or testing may be produced on the corrected reactive capability curve.  ","QSE"]
[108,"Unit Reactive Capability Testing","3 Resource Testing and Qualification Procedures, 3.3 Resource Entities","3.3.2 Unit Reactive Capability Requirements","3.3.2.2(1)","2015-09-25","The QSE representing the Generation Resource shall give ERCOT at least two hours advance Notice prior to the start of the test.","RE"]
[109,"Unit Reactive Capability Testing","3 Resource Testing and Qualification Procedures, 3.3 Resource Entities","3.3.2 Unit Reactive Capability Requirements","3.3.2.2(2)","2015-09-25","It is recommended, but not required, that tests to verify maximum lagging reactive capability shall be conducted during times when ERCOT System Loads are typically high, such as during the months of May through September, but not necessarily at the time of system peak.  ERCOT has the authority to not allow a reactive capability test to be conducted if it believes system conditions at the requested time of the test are unfavorable.  Generation Resources being tested shall be operating at or above 95% of net dependable real power (MW) output.  Generation Resources that are classified as Intermittent Renewable Resources (IRRs) shall be tested when generating at or above 60% of their seasonal High Sustained Limit (HSL).  If the Generation Resource being tested is unable to achieve adequate lagging reactive capability per the CURL, the Generation Resource, at its discretion, may utilize the capability of another Generation Resource in the same plant to offset (take in VArs) the lagging test that is under way.  This circulation of VArs must leave the high side of the GSU of the unit being tested and flow through the GSU of the Generation Resource taking in the VArs.  Under no circumstances shall VArs be circulated between Generation Resources on the same low side bus.","RE"]
[110,"Unit Reactive Capability Testing","3 Resource Testing and Qualification Procedures, 3.3 Resource Entities","3.3.2 Unit Reactive Capability Requirements","3.3.2.2(3)","2015-09-25","It is recommended, but not required, that tests to verify maximum leading reactive capability be conducted during times when ERCOT System Loads are typically low, during the months of October through April.  Generation Resources being tested shall be operating at a real power (MW) output representative of its usual loading during such light Load periods.  Generation Resources that are classified as IRRs shall be tested when generating below 60% of their seasonal HSL.","RE"]
[111,"Unit Reactive Capability Testing","3 Resource Testing and Qualification Procedures, 3.3 Resource Entities","3.3.2 Unit Reactive Capability Requirements","3.3.2.2(4)","2015-09-25","The Resource Entity shall measure the tested reactive capability on the Generation Resource output terminals.  The value recorded shall represent the gross MVAr output of the Generation Resource.  This value shall have the Generation Resource’s auxiliary reactive consumption deducted from the Generation Resource’s gross reactive output.  Additionally, the net reactive capability shall be measured at the high side of the GSU transformer if metering is available.  If metering is not available at the high side, the Resource Entity shall calculate the reactive capability at the high side.  Both high side of the GSU transformer and Generation Resource output terminal values are required and must be submitted through the MIS Certified Area.  CURLs shall be attached to the test results submitted, and shall be clearly defined.  All fields shown on the form in the MIS Certified Area shall be completed in order for a submittal to be considered complete by ERCOT.","RE"]
[112,"Unit Reactive Capability Testing","3 Resource Testing and Qualification Procedures, 3.3 Resource Entities","3.3.2 Unit Reactive Capability Requirements","3.3.2.2(5)","2015-09-25","The QSE representing a Generation Resource shall be responsible for scheduling reactive verification tests in accordance with the conditions outlined above.  If ERCOT does not issue an alternative reactive testing interval, the Generation Resource shall complete a reactive qualification test at least every two years.","QSE/\nRE"]
[113,"Unit Reactive Capability Testing","3 Resource Testing and Qualification Procedures, 3.3 Resource Entities","3.3.2 Unit Reactive Capability Requirements","3.3.2.2(7)","2015-09-25","The minimum duration for any reactive verification test, leading or lagging, is 15 minutes.  The CURL should be posted in the Resource Entities control room, where the tests are conducted, at the QSE’s Real-Time/generation dispatch desk, and copies should be provided to ERCOT Operations.  During any test, the Generation Resource must maintain its generator cooling system at normal operating level.  Tests will be conducted to produce MVArs at a level not less than 90% of the amount indicated by the existing reactive capability curve (original manufacturer’s unit reactive capability curve, or the most recent CURL).","RE"]
[114,"Unit Reactive Capability Testing","3 Resource Testing and Qualification Procedures, 3.3 Resource Entities","3.3.2 Unit Reactive Capability Requirements","3.3.2.2(8)","2015-09-25","The QSE representing a Generation Resource shall be responsible for the timely and accurate reporting of test results to ERCOT.  The QSE representing a Generation Resource shall be responsible for the timely submittal to ERCOT of an updated CURL reflecting any known changes in the reactive output of the Generation Resource.  A QSE must properly complete all required data fields on the MIS Certified Area for a test to be considered valid.","QSE"]
[115,"Unit Reactive Capability Testing","3 Resource Testing and Qualification Procedures, 3.3 Resource Entities","3.3.2 Unit Reactive Capability Requirements","3.3.2.3(1)","2015-09-25","“Coordinated Testing” is the testing of a Generation Resource’s reactive capability to verify the Generation Resource’s most current CURL.  The verification test will be a coordinated effort between the Resource Entity, the Resource Entity’s QSE, the TO which the Resource Entity is connected, and ERCOT Operations.  Coordinated Testing is at the option of the Resource Entity.  Coordinated Testing can be ordered by ERCOT if a retest is required. ","RE"]
[116,"Unit Reactive Capability Testing","3 Resource Testing and Qualification Procedures, 3.3 Resource Entities","3.3.2 Unit Reactive Capability Requirements","3.3.2.3(2)","2015-09-25","The Resource Entity requesting to perform a Coordinated Test will provide ERCOT Operations and the TO with notice of the proposed test date before 1500 on the day prior to the day of the test.  Requests shall be made between 0800 and 1700 on Business Days.  Upon receipt of a request for test, ERCOT Operations and the TO will evaluate the expected conditions and determine whether  ERCOT System conditions conducive to a valid test can be created through coordinated network switching, modification of the generation reactive dispatch of nearby Generation Resources, or by some other means.  Having established that suitable ERCOT System conditions exist or can be created, ERCOT Operations, and the TO shall confirm with the Resource Entity and the QSE the agreed upon test time and date or a rejection of the test time and date before 1700 on the day prior to the day of the test.","RE"]
[117,"Unit Reactive Capability Testing","3 Resource Testing and Qualification Procedures, 3.3 Resource Entities","3.3.2 Unit Reactive Capability Requirements","3.3.2.3(3)","2015-09-25","The Coordinated Test shall begin and end within the standard work day (nominally 0800 to 1700).  Since leading tests will often occur in off-peak periods, the coordinated leading test shall begin and end at times agreed to by ERCOT, the TO, QSE and Resource Entity.  The minimum duration for any reactive verification test, leading or lagging, is 15 minutes.  The CURL should be provided to ERCOT Operations and posted in the Resource Entity’s control room and at the QSE’s Real-Time/generation dispatch desk.  The testing period shall be scheduled such that sufficient time is given for any transmission switching.  During the test, the QSE shall be in communication with the TO in order to coordinate the reactive output of adjacent Generation Resources, capacitor switching, reactor switching, and any other activity needed to perform the scheduled reactive test accurately.","RE"]
[118,"Unit Reactive Capability Testing","3 Resource Testing and Qualification Procedures, 3.3 Resource Entities","3.3.2 Unit Reactive Capability Requirements","3.3.2.3(4)","2015-09-25","Lagging Reactive Tests - Generation Resources shall be tested to verify lagging reactive capability at or above 95% of net dependable real power output as indicated on the CURL.  Generation Resources that are classified as IRRs shall be tested when generating at or above 60% of their seasonal HSL.  Maximum lagging capability is most likely to be needed during times when ERCOT System Loads are typically high, and transmission system voltages are relatively low, such as during the months of May through September.  ERCOT has the authority to not allow a reactive capability test to be conducted if it believes ERCOT System conditions at the requested time of the test are unfavorable.  The transmission voltage at the switchyard to which the Generation Resource is connected should be at or below the ERCOT currently scheduled voltage prior to starting the test.  If the Generation Resource being tested is unable to achieve adequate lagging reactive capability per the CURL, the Generation Resource, at its discretion, may utilize the capability of another Generation Resource in the same plant to offset (take in VArs) the lagging test that is under way.  This circulation of VArs must leave the high side of the GSU of the Generation Resource being tested and flow through the GSU of the Generation Resource taking in the VArs.  Under no circumstances shall VArs be circulated between Generation Resources on the same low side bus.","RE"]
[119,"Unit Reactive Capability Testing","3 Resource Testing and Qualification Procedures, 3.3 Resource Entities","3.3.2 Unit Reactive Capability Requirements","3.3.2.3(5)","2015-09-25","Leading Reactive Tests - Generation Resources shall be tested to verify leading reactive capability at a MW loading level representative of expected Generation Resource MW loading during minimum Load conditions as indicated on the CURL.  Generation Resources that are classified as IRRs shall be tested when generating below 60% of their seasonal HSL.  Maximum leading capability is most likely to be needed when ERCOT System Loads are typically light and transmission system voltages are relatively high, such as during the months of October through April.  ERCOT has the authority to not allow a reactive capability test to be conducted if it believes the system conditions at the requested time of the test are unfavorable.  The transmission voltage at the switchyard to which the Generation Resource is connected should be at or above the ERCOT currently scheduled voltage prior to starting the test.  At ERCOT’s sole discretion, the requirement to test leading capability may be waived for peaking Generation Resources which seldom, if ever, run during light Load conditions.","RE"]
[120,"Unit Reactive Capability Testing","3 Resource Testing and Qualification Procedures, 3.3 Resource Entities","3.3.2 Unit Reactive Capability Requirements","3.3.2.3(6)","2015-09-25","The Resource Entity shall measure the tested reactive capability at the Generation Resource terminals.  The reading recorded shall represent the net MVAr output of the generator and shall have the Generation Resource’s auxiliary reactive consumption deducted from the Generation Resource’s gross reactive output at the machine’s terminals.  Additionally, the tested reactive capability shall be measured at the high side of the GSU transformer if metering is available.  If metering is not available at the high side, the Resource Entity shall calculate the reactive capability at the high side.  Both high side and generator terminal values are required for proper submittal of the test results.","RE"]
[121,"Unit Reactive Capability Testing","3 Resource Testing and Qualification Procedures, 3.3 Resource Entities","3.3.2 Unit Reactive Capability Requirements","3.3.2.3(7)","2015-09-25","The QSE representing a Generation Resource shall be responsible for scheduling reactive tests in accordance with the conditions outlined above, and for the timely and accurate reporting of test results to ERCOT.  All test documents (the CURL and the CURL with the test point indicated) shall be submitted by the Resource Entity’s QSE.  The Resource Entity must properly complete all required data fields on the MIS Certified Area for a test to be considered complete.","QSE","QSE, not the Resource Entity, must properly complete all required data fields on the MIS Certified Area for a test to be considered complete.\nRefer 3.3.2.2(8) and 3.3.2.3(9)"]
[122,"Unit Reactive Capability Testing","3 Resource Testing and Qualification Procedures, 3.3 Resource Entities","3.3.2 Unit Reactive Capability Requirements","3.3.2.3(8)","2015-09-25","The minimum duration for any reactive verification test, leading or lagging, is 15 minutes.  The CURL should be posted in the Resource Entities control room, where the tests are conducted, at the QSE’s Real-Time/generation dispatch desk, and copies should be provided to ERCOT Operations.  During any test, the Generation Resource must maintain its generator cooling system at normal operating level.  Tests will be conducted to produce MVArs at a level not less than 90% of the amount indicated by the existing reactive capability curve (original manufacturer’s unit reactive capability curve, or the most recent CURL).","RE"]
[123,"Unit Reactive Capability Testing","3 Resource Testing and Qualification Procedures, 3.3 Resource Entities","3.3.2 Unit Reactive Capability Requirements","3.3.2.3(9)","2015-09-25","The QSE representing a Generation Resource shall be responsible for the timely and accurate reporting of test results to ERCOT.  The QSE representing a Generation Resource shall be responsible for the timely submittal to ERCOT of an updated CURL reflecting any known changes in the reactive output of the Generation Resource.  A QSE must properly complete all required data fields on the MIS Certified Area for a test to be considered valid.","QSE"]
[124,"Transmission Facility Ratings","3 Resource Testing and Qualification Procedures, 3.3 Resource Entities","3.3.3 Resource Entity Responsibilities for Equipment Ratings","3.3.3(1)","2015-09-25","Resource Entities that own Transmission Facilities are responsible for determining the Ratings of its Transmission Facilities and shall send the methodology used to ERCOT in accordance with the Protocols.  Technical limits established for the operation of Transmission Facilities and associated equipment shall be applied consistently in engineering and planning studies, Real-Time security analyses, and operator actions.","-"]
[125,"Transmission Facility Ratings","3 Resource Testing and Qualification Procedures, 3.3 Resource Entities","3.3.3 Resource Entity Responsibilities for Equipment Ratings","3.3.3(2)","2015-09-25","Resource Entity owners of Transmission Facilities shall provide to ERCOT all nominal Transmission Facility Ratings.","-"]
[126,"TSP Operating Obligations","3 Resource Testing and Qualification Procedures, 3.6 Transmission Service Providerss","3.6 Transmission Service Providerss","3.6(1)","2015-09-25","ERCOT and Transmission Service Providers (TSPs) shall operate the ERCOT Transmission Grid in compliance with Good Utility Practice, North American Electric Reliability Corporation (NERC) Reliability Standards, Protocols and Operating Guides. ","TSP"]
[127,"TSP Operating Obligations","3 Resource Testing and Qualification Procedures, 3.6 Transmission Service Providerss","3.6 Transmission Service Providerss","3.6(2)","2015-09-25","TSPs shall designate an Authorized Representative as defined in Protocol Section 2.1, Definitions. ","TSP"]
[128,"TSP Operating Obligations","3 Resource Testing and Qualification Procedures, 3.6 Transmission Service Providerss","3.6 Transmission Service Providerss","3.6(3)","2015-09-25","Each TSP, at its own expense, may obtain Operating Period data from ERCOT.","TSP"]
[129,"TO Operating Obligations","3 Resource Testing and Qualification Procedures, 3.7 Transmission Operators","3.7 Transmission Operators","3.7(1)","2015-09-25","Transmission Operators (TOs) shall follow ERCOT instructions related to ERCOT responsibilities: (a) Performing the physical operation of the ERCOT Transmission Grid, including circuit breakers, switches, voltage control equipment, protective relays, metering and Load shedding equipment;\n(b) Directing changes in the operation of transmission voltage control equipment;\n(c) Managing Voltage Profiles established by ERCOT. TOs, under the direction of ERCOT, will coordinate Transmission Service Provider (TSP) static device switching with Qualified Scheduling Entity (QSE) dynamic reactive device operation. Static reactive devices will be brought On-Line before predicted daily maximum Load growth or dynamic reactive Resources reach operating limits. Static reactive devices will be taken Off-Line during daily Load decline and before dynamic reactive Resources reach operating limits. ERCOT will coordinate Automatic Voltage Regulator (AVR), dynamic and static reactive device Outages to ensure adequate reactive reserves are maintained; and\n(d) Taking those additional actions required to prevent an imminent Emergency Condition or to restore the ERCOT Transmission Grid to a secure state in the event of a system emergency.","TO","IRO-001-1.1\nIRO-004-2\nTOP-001-1a"]
[130,"TO Operating Obligations","3 Resource Testing and Qualification Procedures, 3.7 Transmission Operators","3.7 Transmission Operators","3.7(2)","2015-09-25","TOs must meet all requirements identified in the Protocols for TOs in addition to those requirements stated below for all Transmission Facilities represented: (a) Monitor system conditions and notify ERCOT when Transmission Facility elements reach maximum safe operating limits as soon as practicable;\n(b) Notify ERCOT of any changes in its Transmission Facility status within ten seconds of the change of status as specified in Protocol Section 3.10.7.5, Telemetry Criteria;\n(c) Operate and manage Transmission Facilities between energy sources and the point of delivery;\n(d) Coordinate emergency communications between a represented TSP system and ERCOT;\n(e) Monitor the loading of the transmission system(s);\n(f) Notify ERCOT of all changes to the status of all Transmission Elements and Transmission Facilities;\n(g) Act as Single Point of Contact for transmission Outages; (h) Maintain continuous communication (24x7) with ERCOT;\n(i) Ensure Dispatch Instructions, received for their system or on behalf of represented TSPs or Distribution Service Providers (DSPs), are carried out as issued;\n(j) Maintain operational metering; and\n(k) Implement Black Start.","TO"]
[131,"TO Operating Obligations","3 Resource Testing and Qualification Procedures, 3.7 Transmission Operators","3.7 Transmission Operators","3.7(3)","2015-09-25","TOs shall submit to ERCOT, by March 15 of each year, a written back-up control plan to continue operation in the event the TOs control center becomes inoperable.  Back-up control plans shall be submitted to ERCOT via secured webmail or encrypted data transfer.  TOs shall request that a secure email account be created with ERCOT by sending an email to shiftsupervisors@ercot.com. ","TO","EOP-008"]
[132,"TO Operating Obligations","3 Resource Testing and Qualification Procedures, 3.7 Transmission Operators","3.7 Transmission Operators","3.7(4)","2015-09-25","Each back-up control plan shall be reviewed and updated annually and shall meet the following minimum requirements: (a) Include descriptions of actions to be taken by TO personnel to avoid placing a prolonged burden on ERCOT and other Market Participants;\n(b) Include descriptions of specific functions and responsibilities to be performed to continue operations from an alternate location;\n(c) Include procedures and responsibilities for maintaining basic voice communications capabilities with ERCOT; and\n(d) Include procedures for back-up control function testing and the training of personnel.","TO","EOP-008"]
[133,"TO Operating Obligations","3 Resource Testing and Qualification Procedures, 3.7 Transmission Operators","3.7 Transmission Operators","3.7.(5)","2015-09-25","As an option, the back-up control plan may include arrangements made with another Entity to provide the minimum back-up control functions in the event the TO’s primary functions are interrupted.","TO","EOP-008"]
[134,"Vegetation Management","3 Resource Testing and Qualification Procedures, 3.7 Transmission Operators","3.7.1 Transmission Owner Responsibility of a Vegetation Management Program","3.7.1","2015-09-25","Each transmission owner shall have a vegetation management program outlining procedures to prevent transmission line contact with vegetation.  The transmission owner shall maintain documentation to verify the performance of the vegetation management program and shall provide that documentation to their respective TO and ERCOT upon request.","Transmission Owner","FAC-003-3"]
[135,"Transmission Facility Ratings","3 Resource Testing and Qualification Procedures, 3.7 Transmission Operators","3.7.2 Transmission Service Provider Responsibilities for Equipment Ratings","3.7.2(1)","2015-09-25","TSPs that own Transmission Facilities are responsible for determining the Ratings of their Transmission Facilities and shall send the methodology used to ERCOT in accordance with the Protocols.  Technical limits established for the operation of Transmission Facilities and associated equipment shall be applied consistently in engineering and planning studies, Real-Time security analyses, and operator actions.","TSP","FAC-008-3"]
[136,"Transmission Facility Ratings","3 Resource Testing and Qualification Procedures, 3.7 Transmission Operators","3.7.2 Transmission Service Provider Responsibilities for Equipment Ratings","3.7.2(2)","2015-09-25","TSPs owners of Transmission Facilities shall provide to ERCOT all nominal Transmission Facility Ratings.","TSP"]
[137,"Reporting Sabotage Information","3 Resource Testing and Qualification Procedures, 3.8 Requirements for Reporting Sabotage Information","3.8 Requirements for Reporting Sabotage Information","3.8(1)","2015-09-25","ERCOT Entities shall notify their designated Transmission Operator (TO) or Qualified Scheduling Entity (QSE) when experiencing disturbances or unusual occurrences suspected or determined to be caused by sabotage.  Disturbances and unusual occurrences related to bulk electric system Facilities within the ERCOT Region are the only Facilities subject to reporting.  ERCOT Entities shall have procedures for the recognition of sabotage events on its Facilities and multi-site sabotage.","QSE/\nRE/\nTO","EOP-004-2"]
[138,"Reporting Sabotage Information","3 Resource Testing and Qualification Procedures, 3.8 Requirements for Reporting Sabotage Information","3.8 Requirements for Reporting Sabotage Information","3.8(2)","2015-09-25","TOs or QSEs shall inform ERCOT of disturbances or unusual occurrences suspected or determined to be caused by sabotage.  TOs or QSEs may notify ERCOT by telephone or by email at shiftsupervisors@ercot.com. ","QSE/\nTO","EOP-004-2"]
[139,"Reporting Sabotage Information","3 Resource Testing and Qualification Procedures, 3.8 Requirements for Reporting Sabotage Information","3.8 Requirements for Reporting Sabotage Information","3.8(3)","2015-09-25","TOs and QSEs may inform other ERCOT Entities of the event(s), if, in the opinion of the TO or QSE, the situation impacts other Entities.","QSE/\nTO"]
[140,"Emergency Operations","4 Emergency Operations, 4.1 Introduction","4.1 Introduction","4.1(1)","2015-09-25","Emergency operation is intended to address operating conditions under which the reliability of the ERCOT System is inadequate and there is no solution readily apparent.  During a declared system emergency, ERCOT can instruct Transmission Operators (TOs) and Qualified Scheduling Entities (QSEs) to take specific operating actions that would otherwise be discretionary.  Upon receiving a Verbal Dispatch Instruction (VDI) from ERCOT, and in compliance with these Operating Guides, the QSEs shall direct relevant Resources or groups of Resources to respond to the instruction.  ERCOT shall coordinate with QSEs and TOs to assure that necessary actions are taken to maintain reliability.","QSE"]
[141,"Emergency Operations","4 Emergency Operations, 4.1 Introduction","4.1 Introduction","4.1(2)","2015-09-25","It is essential that good, timely, and accurate communication routinely occur between ERCOT, TOs, and QSEs.  QSE and TO personnel shall report unplanned equipment status changes as outlined in this Section.  ERCOT System Operators may ask for status updates as required in order to gather information to make decisions on system conditions to determine what type of emergency communication may be appropriate.","QSE/\nTO"]
[142,"Emergency Operations","4 Emergency Operations, 4.1 Introduction","4.1 Introduction","4.1(3)","2015-09-25","ERCOT may issue communications in the form of Operating Condition Notices (OCNs), Advisories, Watches and Emergency Notices.  These communications may relate to but are not limited to, weather, transmission, computer failure, or generation information.  ERCOT shall specify the severity of the situation, the area affected, the areas potentially affected, and the anticipated duration of the Emergency Condition.  These communications will be issued by ERCOT to inform all TOs and QSEs of the current operating situation.  TOs will notify their represented Transmission Service Providers (TSPs) and Load Serving Entities (LSEs).  QSEs will in turn notify the appropriate Resources, Retail Electric Providers (REPs) and LSEs.  QSEs and TOs shall establish and maintain internal procedures for contingency preparedness or to expedite the resolution of the conditions communicated by ERCOT that threaten system reliability.","QSE/\nTO"]
[143,"Emergency Operations","4 Emergency Operations, 4.2 Communication Under Emergency Conditions","4.2.1 Operating Condition Notice","4.2.1(3)","2015-09-25","ERCOT will provide verbal notice of an OCN to all TOs and QSEs and post the message electronically to the Market Information System (MIS) Public Area.  When an OCN is issued, it does not place ERCOT in an Emergency Condition.  QSEs should notify appropriate Resources, Retail Electric Providers (REPs) and Load Serving Entities (LSEs).  TOs should notify their represented Transmission Service Providers (TSPs) as appropriate.","QSE/\nTO"]
[144,"Emergency Operations","4 Emergency Operations, 4.2 Communication Under Emergency Conditions","4.2.2 Advisory","4.2.2(4)","2015-09-25","ERCOT shall provide verbal notice of an Advisory to all TOs and QSEs and shall post the message electronically to the MIS Public Area.  When an Advisory is issued, it does not place ERCOT in an Emergency Condition.  QSEs shall notify appropriate Resources, REPs and LSEs of Advisories.  TOs should notify their represented TSPs as appropriate of Advisories.","QSE/\nTO"]
[145,"Emergency Operations","4 Emergency Operations, 4.2 Communication Under Emergency Conditions","4.2.3 Watch","4.2.3(4)","2015-09-25","ERCOT shall provide verbal notice of the Watch to all TOs and QSEs and shall post the message electronically to the MIS Public Area.  QSEs shall notify appropriate Resources, REPs and LSEs.  TOs shall notify their represented TSPs.","QSE/\nTO"]
[146,"Emergency Operations","4 Emergency Operations, 4.2 Communication Under Emergency Conditions","4.3.4 Emergency Notice","4.2.4(3)","2015-09-25","When an Emergency Notice is issued, ERCOT is operating in an Emergency Condition.  QSEs shall notify appropriate resources, REPs and LSEs.  TOs shall notify their represented TSPs and LSEs.","QSE/\nTO"]
[147,"Emergency Operations","4 Emergency Operations, 4.5 Energy Emergency Alert (EEA)","4.5.2 Operating Procedures","4.5.2(1)","2015-09-25","The ERCOT System Operators have the authority to make and carry through decisions that are required to operate the ERCOT System during emergency or adverse conditions.  ERCOT will have sufficiently detailed operating procedures for emergency or short supply situations and for restoration of service in the event of a Partial Blackout or Blackout.  These procedures will be distributed to the personnel responsible for performing specified tasks to handle emergencies, remedy short supply situations, or restore service.  Transmission Service Providers (TSPs) will develop procedures to be filed with ERCOT describing implementation of ERCOT requests in emergency and short supply situations, including interrupting Load, notifying others and restoration of service.","TSP","EOP-001-2.1b"]
[148,"Emergency Operations","4 Emergency Operations, 4.5 Energy Emergency Alert (EEA)","4.5.2 Operating Procedures","4.5.2(2)","2015-09-25","ERCOT and each TSP will endeavor to maintain transmission ties intact if at all possible.  This will: (a) Permit rendering the maximum assistance to an area experiencing a deficiency in generation;\n(b) Minimize the possibility of cascading loss to other parts of the system; and\n(c) Assist in restoring operation to normal.","TSP","EOP-001-2.1b"]
[149,"Emergency Operations","4 Emergency Operations, 4.5 Energy Emergency Alert (EEA)","4.5.3 Implementation","4.5.3(1)","2015-09-25","ERCOT shall be responsible for monitoring system conditions, initiating the EEA levels below, notifying all Qualified Scheduling Entities (QSEs) and Transmission Operators (TOs), and coordinating the implementation of the EEA conditions while maintaining transmission security limits.  QSEs and TOs will notify all the Market Participants they represent of each declared EEA level.","QSE/\nTO","EOP-001-2.1b\nEOP-003-2"]
[150,"Emergency Operations","4 Emergency Operations, 4.5 Energy Emergency Alert (EEA)","4.5.3 Implementation","4.5.3(6)","2015-09-25","The ERCOT System Operator shall declare the EEA levels to be taken by QSEs and TSPs.  QSEs and TSPs shall implement actions under that level (and all above if not previously accomplished) and if ordered by the ERCOT shift supervisor or his designate, shall report back to the ERCOT System Operator when the requested level has been completed.","QSE/\nTSP","EOP-001-2.1b\nEOP-003-2"]
[151,"Emergency Operations","4 Emergency Operations, 4.5 Energy Emergency Alert (EEA)","4.5.3 Implementation","4.5.3(7)","2015-09-25","During EEA Level 3, ERCOT must be capable of shedding sufficient firm Load to arrest frequency decay and to prevent generator tripping.  The amount of firm Load to be shed may vary depending on ERCOT Transmission Grid conditions during the event.  Each TSP will be capable of shedding its allocation of firm Load, without delay.  The maximum time for the TSP to interrupt firm Load will depend on how much Load is to be shed and whether the Load is to be interrupted by Supervisory Control and Data Acquisition (SCADA) or by the dispatch of personnel to substations.  Since the need for firm Load shed is immediate, interruption by SCADA is preferred.  The following requirements apply for an ERCOT instruction to shed firm Load: (a) Load interrupted by SCADA will be shed without delay and in a time period not to exceed 30 minutes;\n(b) Load interrupted by dispatch of personnel to substations to manually shed Load will be implemented within a time period not to exceed one hour;\n(c) The initial clock on the firm Load shed shall apply only to Load shed amounts up to 1000 MW total. Load shed amount requests exceeding 1000 MW on the initial clock may take longer to implement; and\n(d) If, after the first Load shed instruction, ERCOT determines that an additional amount of firm Load should be shed, another clock will begin anew. The time frames mentioned above will apply.","TSP","EOP-001-2.1b\nEOP-003-2"]
[152,"Emergency Operations","4 Emergency Operations, 4.5 Energy Emergency Alert (EEA)","4.5.3 Implementation","4.5.3(8)","2015-09-25","Each TSP, or its designated agent, will provide ERCOT a status report of Load shed progress within 30 minutes of the time of ERCOT’s instruction or upon ERCOT’s request.","TSP","EOP-001-2.1b\nEOP-003-2"]
[153,"Emergency Operations","4 Emergency Operations, 4.5 Energy Emergency Alert (EEA)","4.5.3 Implementation,  4.5.3.2 General Procedures During EEA Operations","4.5.3.2","2015-09-25","ERCOT Control Area authority will re-emphasize the following operational practices during EEA operations to minimize non-performance issues that may result from the pressures of the emergency situation. (c) QSEs and TOs shall notify each represented Market Participant of declared EEA level;\n(d) ERCOT, QSEs and TSPs shall continue to respect confidential market sensitive data;\n(e) QSEs shall update Current Operating Plans (COPs) to limit or remove capacity when unexpected start-up delays occur or when ramp limitations are encountered;\n(f) QSEs shall report when On-Line or available capacity is at risk due to adverse circumstances;\n(g) QSEs, TSPs, and all other Entities must not suspend efforts toward expeditious compliance with the applicable EEA level declared by ERCOT nor initiate any reversals of required actions without ERCOT authorization; (i) QSEs shall not remove an On-Line Generation Resource without prior ERCOT authorization unless such actions would violate safety, equipment, or regulatory or statutory requirements. Under these circumstances, QSEs shall immediately inform ERCOT of the need and reason for removing the On-Line Generation Resource from service.","-"]
[154,"Emergency Operations","4 Emergency Operations, 4.5 Energy Emergency Alert (EEA)","4.5.3 Implementation, 4.5.3.3(1) EEA Level 1 - Maintain a total of 2,300 MW of PRC MW (Protocol Section 6.5.7.5, Ancillary Services Capacity Monitor)","4.5.3.3(1)(a)(v)(D)","2015-09-25","Upon deployment, QSEs shall instruct their ERS Resources in ERS-30 to perform at contracted levels consistent with the criteria described in Section 8.1.3.1.4, Event Performance Criteria for Emergency Response Service Resources, until either ERCOT releases the ERS-30 deployment or the ERS-30 Resources have reached their maximum deployment time.","QSE"]
[155,"Emergency Operations","4 Emergency Operations, 4.5 Energy Emergency Alert (EEA)","4.5.3 Implementation, 4.5.3.3(1) EEA Level 1 - Maintain a total of 2,300 MW of PRC MW (Protocol Section 6.5.7.5, Ancillary Services Capacity Monitor)","4.5.3.3(1)(a)(v)(F)","2015-09-25","Upon release, an ERS Resource in ERS-30 shall return to a condition such that it is capable of meeting its ERS performance requirements as soon as practical, but no later than ten hours following the release.","RE"]
[156,"Emergency Operations","4 Emergency Operations, 4.5 Energy Emergency Alert (EEA)","4.5.3 Implementation, 4.5.3.3(1) EEA Level 1 - Maintain a total of 2,300 MW of PRC MW (Protocol Section 6.5.7.5, Ancillary Services Capacity Monitor)","4.5.3.3(1)(b)","2015-09-25","QSEs Shall: (i) Ensure COPs and telemetered High Sustained Limits (HSLs) are updated and reflect all Resource delays and limitation; and\n(ii) Suspend any ongoing ERCOT-required Resource performing testing.","QSE"]
[157,"Emergency Operations","4 Emergency Operations, 4.5 Energy Emergency Alert (EEA)","4.5.3 Implementation. 4.5.3.3(2) EEA Level 2 – Maintain system frequency at 60 Hz or maintain a total of 1,750 MW of PRC MW (Protocol Section 6.5.7.5)","4.5.3.3(2)(a)(iii)(D)","2015-09-25","Upon deployment, QSEs shall instruct ERS-10 Resources to perform at contracted levels consistent with the criteria described in Protocol Section 8.1.3.1.4 until ERCOT releases the ERS-10 deployment or the ERS-10 Resources have reached their maximum deployment times.","QSE"]
[158,"Emergency Operations","4 Emergency Operations, 4.5 Energy Emergency Alert (EEA)","4.5.3 Implementation. 4.5.3.3(2) EEA Level 2 – Maintain system frequency at 60 Hz or maintain a total of 1,750 MW of PRC MW (Protocol Section 6.5.7.5)","4.5.3.3(2)(a)(iii)(F)","2015-09-25","Upon release, an ERS-10 Resource shall return to a condition such that it is capable of meeting its ERS performance requirements as soon as practical, but no later than ten hours following the release.","RE"]
[159,"Emergency Operations","4 Emergency Operations, 4.5 Energy Emergency Alert (EEA)","4.5.3 Implementation, 4.5.3.3(3) EEA Level 3 – Maintain system frequency at 59.8 Hz or greater","4.5.3.3(3)(b)","2015-09-25","In addition to measures under EEA Levels 1 and 2, TSPs and DSPs or their agents will keep in mind the need to protect the safety and health of the community and the essential human needs of the citizens.  Whenever possible, TSPs and DSPs or their agents shall not manually drop Load connected to under-frequency relays during the implementation of the EEA.","DSP/\nTSP"]
[160,"Emergency Operations","4 Emergency Operations, 4.5 Energy Emergency Alert (EEA)","4.5.3 Implementation, 4.5.3.4 Load Shed Obligation","4.5.3.4","2015-09-25","Obligation for Load shed is by DSP.  Load shedding obligations need to be represented by an Entity with 24x7 operations and Hotline communications with ERCOT and control over breakers.  Percentages for Level 3 Load shedding will be based on the previous year’s TSP peak Loads, as reported to ERCOT, and will be reviewed by ERCOT and modified annually.\n\n                                           ERCOT Load Shed Table\nTransmission Operator\n2014 Total Transmission Operator Load (%MW)\nAmerican Electric Power Service Corp.  8.96\nBrazos Electric Power Cooperative Inc.  4.70\nBrownsville Public Utilities Board  0.42\nBryan Texas Utilities  0.51\nCenterPoint Energy Houston Electric LLC  25.12\nCity of Austin DBA Austin Energy  3.89\nCity of College Station  0.30\nCity of Garland  0.83\nCPS Energy (San Antonio)  7.07\nDenton Municipal Electric  0.50\nGEUS (Greenville)  0.16\nLCRA Transmission Services Corporation  5.64\nOncor Electric Delivery Company LLC  35.79\nRayburn Country Electric Cooperative Inc. DBA Rayburn Electric  1.10\nSharyland Utilities  0.58\nSouth Texas Electric Cooperative Inc.  2.02\nTexas-New Mexico Power Company  2.41\nERCOT Total  100.00","DSP"]
[161,"Emergency Operations","4 Emergency Operations, 4.5 Energy Emergency Alert (EEA)","4.5.3 Implementation, 4.5.3.5 EEA Termination","4.5.3.5(2)","2015-09-25","QSEs and TOs shall: (a) Implement actions to terminate previous actions as EEA levels are released in accordance with these Operating Guides;\n(b) Notify represented Market Participants of EEA levels changes;\n(c) Report back to the ERCOT System Operator when each level is accomplished; and\n(d) Loads will be restored when specifically authorized by the ERCOT.","QSE/\nTO"]
[162,"Black Start","4 Emergency Operations, 4.6 Black Start Service","4.6 Black Start Service","4.6(1)","2015-09-25","This section provides general guidelines to be followed in the event of a Partial Blackout or Blackout of the ERCOT System.  Timely implementation of a Black Start plan compiled in accordance with Section 8, Attachment E, Black Start Plan Template, should facilitate coordination between ERCOT, Qualified Scheduling Entities (QSEs) who represent Black Start Resources, Black Start Resources, and Transmission Operators (TOs) and ensure restoration of service to the ERCOT System at the earliest possible time.  The Authorized Representative for Resource Entities that own contracted Black Start Resources will provide their QSE and ERCOT with a copy of the individual plant start-up procedures for coordination of their activities with those of the appropriate TO.","RE","EOP-005-2"]
[163,"Black Start","4 Emergency Operations, 4.6 Black Start Service","4.6.1 Principles","4.6.1(2)","2015-09-25","Each contracted Black Start Resource and each QSE with contracted Black Start Resource(s) will have readily accessible and sufficiently detailed current operating procedures to assist in an orderly recovery.","QSE/\nRE","EOP-005-2"]
[164,"Black Start","4 Emergency Operations, 4.6 Black Start Service","4.6.2 Strategies","4.6.2(1)","2015-09-25","Each TO shall immediately initiate its portion of the ERCOT Black Start Plan and attempt to establish contact with ERCOT.  If communications with ERCOT are unavailable the TO shall immediately establish communications with its interconnected Black Start Resource(s) and the Black Start Resource’s QSE.","TO","EOP-005-2"]
[165,"Black Start","4 Emergency Operations, 4.6 Black Start Service","4.6.2 Strategies","4.6.2(2)","2015-09-25","Each QSE representing Black Start Resources shall initiate communications with its Black Start Resources and immediately notify ERCOT and the appropriate TO of their condition and status.","QSE","EOP-005-2"]
[166,"Black Start","4 Emergency Operations, 4.6 Black Start Service","4.6.2 Strategies","4.6.2(3)","2015-09-25","Available Black Start Resources shall immediately start their isolation and startup procedures and attempt to establish communications with the local TO.","RE","EOP-005-2"]
[167,"Black Start","4 Emergency Operations, 4.6 Black Start Service","4.6.4 Responsibilities","4.6.4(2)","2015-09-25","TOs’ responsibilities are as follows: (a) Shall review and submit their Black Start plans to ERCOT by November 1 of each year, or when the Black Start plan has changed, via secured webmail or encrypted data transfer. The TO may request that ERCOT post the TO’s new or revised Black Start plan on the MIS Certified Area for specified Market Participants. The TO will have the responsibility to notify specified Market Participants that the new or revised Black Start plan has been posted on the MIS Certified Area; and\n(b) In event of a Partial Blackout or Blackout of the ERCOT System:\n(i) Shall communicate with local Black Start Resources and the Black Start Resource’s QSE;\n(ii) Coordinate switching to next start Resources and local Load;\n(iii) Shall implement its local Black Start plan; (iv) Shall follow the direction of ERCOT on behalf of represented Transmission Service Providers (TSPs) and Distribution Service Providers (DSPs);\n(v) Shall act as the regional ERCOT representative in coordinating interconnection of Resources; and\n(vi) Shall follow the direction of ERCOT for reconnection of Islands.","TO","EOP-005-2"]
[168,"Black Start","4 Emergency Operations, 4.6 Black Start Service","4.6.4 Responsibilities","4.6.4(3)","2015-09-25","QSEs’ representing Black Start Resources responsibilities are as follows: (a) Verify that associated QSE personnel are proficient in implementation and use of the appropriate procedures for use in the event of a Partial Blackout or Blackout; and\n(b) In the event of a Partial Blackout or Blackout of the ERCOT System, QSEs representing Black Start Resources shall:\n(i) Take immediate steps to initiate and maintain communications with its Black Start Resources;\n(ii) Supply ERCOT and/or the local TO with information on the status of generation, fuel, transmission, and communication facilities;\n(iii) Follow the direction of the local TO or ERCOT in regards to output of its Generation Resources; and\n(iv) Provide available assistance as directed by ERCOT or the local TO.","QSE","EOP-005-2"]
[169,"Black Start","4 Emergency Operations, 4.6 Black Start Service","4.6.4 Responsibilities","4.6.4(4)","2015-09-25","Black Start Resources’ responsibilities are as follows: (a) Verify that associated Resource personnel are proficient in the implementation and use of appropriate individual plant start-up procedures for use in the event of a Partial Blackout or Blackout; and\n(b) In the event of a Partial Blackout or Blackout of the ERCOT System, Black Start Resources shall:\n(i) Isolate the Black Start Resource from the ERCOT Transmission Grid;\n(ii) Establish communications with the local TO who is the primary contact for the Black Start Resource;\n(iii) Supply the local TO and QSE with information on the status of generation, fuel, transmission isolation, and communication facilities;\n(iv) Follow the appropriate plant start-up procedures and request synchronization and auxiliary Load pickup from the TO; and (v) Follow the direction of the local TO or ERCOT until such time as normal system operations resume. The Black Start Resource should follow the direction of the QSE instructed by the TO or ERCOT when necessary.","RE","EOP-005-2"]
[170,"Black Start","4 Emergency Operations, 4.6 Black Start Service","4.6.4 Responsibilities","4.6.4(5)","2015-09-25","Generation Resources that are not Black Start Resources have the following responsibilities in the event of a Partial Blackout or Blackout of the ERCOT System: (a) Take immediate steps to initiate and maintain communications with its QSE; and\n(b) Follow the direction of the local TO or ERCOT until such time as normal system operations resume. The Generation Resource should follow the direction of the QSE as instructed by the TO or ERCOT when necessary.","RE","EOP-005-2"]
[171,"Black Start","4 Emergency Operations, 4.6 Black Start Service","4.6.4 Responsibilities","4.6.4(6)","2015-09-25","Section 8, Attachment A, Detailed Black Start Information, and Section 8, Attachment E, Black Start Plan Template, provide a detailed and specific Black Start information guide.  Interested parties should use this information for technical reference material, Black Start testing, development of Black Start plans, and training of personnel.","TO","EOP-005-2"]
[172,"Black Start","4 Emergency Operations, 4.6 Black Start Service","4.6.5 Black Start Emergency Back Up Communication Facilities Criteria","4.6.5(1)","2015-09-25","All back-up communications systems shall meet the following minimum requirements: (a) Be operational for 72 hours immediately following the start of a Blackout without external power from the ERCOT System;\n(b) Provide direct voice communications between Black Start Resource and TO, TO and other appropriate TOs, and TO and ERCOT; and\n(c) Maintain written procedures that address operator training and the testing of the communication system;","QSE/\nRE/\nTO","EOP-005-2"]
[173,"Black Start","4 Emergency Operations, 4.6 Black Start Service","4.6.5 Black Start Emergency Back Up Communication Facilities Criteria","4.6.5(2)","2015-09-25","TOs shall have a satellite phone that meets the minimum back up communication requirements as a back-up communication system and that is compatible with ERCOT’s satellite phone.","TO","EOP-005-2"]
[174,"GMD","4 Emergency Operations, 4.7 Geomagnetic Disturbance Operating Plan","4.7.2 Development and submission of TO GMD Operating Procedures or Processes","4.7.2(1)","2015-09-25","Each TO that operates transmission equipment that includes a power transformer with a high side wye-grounded winding with terminal voltage greater than 200 kV shall develop a GMD operating procedure or process to mitigate the effects of GMD events on the reliable operation of its system.","TO","EOP-010-1"]
[175,"GMD","4 Emergency Operations, 4.7 Geomagnetic Disturbance Operating Plan","4.7.2 Development and submission of TO GMD Operating Procedures or Processes","4.7.2(2)","2015-09-25","Each TO GMD operating procedure or process shall be provided to ERCOT as soon as practicable but no later than November 25, 2014.  Updates to the plan shall be provided to ERCOT by March 15 of each subsequent year.","TO","EOP-010-1"]
[176,"GMD","4 Emergency Operations, 4.7 Geomagnetic Disturbance Operating Plan","4.7.2 Development and submission of TO GMD Operating Procedures or Processes","4.7.2(3)","2015-09-25","Each TO GMD operating procedure or process shall include: (a) A procedure to receive GMD alerts and warnings from ERCOT;\n(b) A description of operational actions the TO intends to take to mitigate the effects of a GMD event. This description shall include:\n(i) The triggering event for each action;\n(ii) A detailed explanation of each operational action;\n(iii) A list of Entities with which the TO must coordinate, if any, including any actions requested of other Entities in the ERCOT Region in order to implement the TO’s GMD operating procedure or process; and\n(iv) The conditions under which each action would be terminated.\n(c) A procedure for reporting to ERCOT any unusual operational information that could be the result of GMD, such as high reactive loading, MVAr or voltage swings, high geomagnetically induced current on monitored transformers or equipment malfunctions.","TO","EOP-010-1"]
[177,"-","4 Emergency Operations, 4.7 Geomagnetic Disturbance Operating Plan","4.7.3 ERCOT’s GMD Operating Plan and ERCOT Review of TO GMD Operating Procedures or Processes","4.7.3(3)","2015-09-25","In preparing the ERCOT GMD operating plan, ERCOT shall identify and notify the relevant TOs of any conflicts between the different TO GMD operating procedures or processes and any unacceptable actions requested of ERCOT in the TO operating procedures or processes. (a) ERCOT and the TOs shall coordinate development of any required modifications to the TO GMD operating procedures or processes necessary to resolve these conflicts or unacceptable actions.\n(b) A TO shall make the resulting modifications to its GMD operating procedures or processes.","-","Context"]
[178,"Network Modeling","5 Network Operations Modeling Requirements, 5.1 System Modeling Information","5.1 System Modeling Information","5.1(a)","2015-09-25","Each Transmission Service Provider (TSP), or its Designated Agent, shall provide accurate modeling information for all Transmission Facilities owned or planned by the TSP.  The information provided shall include, but not be limited to, the following: (i) Information necessary to represent the TSP’s Transmission Facilities in any model of the ERCOT Transmission Grid whose creation has been approved by ERCOT, including modeling information detailed in procedures of the Steady State Working Group (SSWG), Dynamics Working Group (DWG), and System Protection Working Group (SPWG);\n(ii) Identification of a designated contact person, generally regarded as the working group TSP representative, responsible for providing answers to questions ERCOT may have regarding the information provided; and\n(iii) TSP owned or operated Transmission Facility data provided and used to accurately represent a Transmission Facility in a model shall be consistent to the extent practicable with data provided and used to represent that same Transmission Facility in any other model created to represent a time period during which the Transmission Facility is expected to be physically identical. All existing transmission lines’ and transformers’ impedances, or equivalent branch circuit impedance, and Ratings shall be identical, to the extent practicable. If all normally closed breakers and switches are closed and normally open breakers and switches are open in the Network Operations Model, the calculated line flows between substations in the Annual Planning Model shall be consistent, when all models use the same load magnitude and distribution, generation commitment and dispatch, and Voltage Profile.","TSP","MOD-032-1"]
[179,"Network Modeling","5 Network Operations Modeling Requirements, 5.1 System Modeling Information","5.1 System Modeling Information","5.1(b)","2015-09-25","Each TSP, or its Designated Agent, owning or planning Transmission Facilities shall attend the scheduled meetings and otherwise participate in the activities of the SSWG, DWG, and the SPWG, unless specifically exempted from these activities by ERCOT.","TSP"]
[180,"Network Modeling","5 Network Operations Modeling Requirements, 5.1 System Modeling Information","5.1 System Modeling Information","5.1(c)","2015-09-25","Each Generation Resource, or its Designated Agent, shall provide accurate modeling information for each existing or proposed Generation Resource meeting the criteria for inclusion in the SSWG, DWG, and SPWG base cases for which it is the majority owner.  The information provided shall include, but not be limited to, the following:(i) Information necessary to represent the Generation Resource’s generation and interconnection facilities in any model of the ERCOT System whose creation has been approved by ERCOT, including modeling information detailed in procedures of the SSWG, DWG, and SPWG; and\n(ii) Identification of a designated contact person responsible for providing answers to questions ERCOT may have regarding the information provided.","RE"]
[181,"Network Modeling","5 Network Operations Modeling Requirements, 5.1 System Modeling Information","5.1 System Modeling Information","5.1(d)","2015-09-25","Typical or representative information may be provided for planned facility additions or modifications for use in the SSWG, DWG, and SPWG base cases, but such information shall be revised using actual design or construction information in accordance with the time line for Network Operations Model changes outlined in Protocol Section 3.10.1, Time Line for Network Operations Model Changes.","RE/\nTSP"]
[182,"DME","6 Disturbance Monitoring and System Protection, 6.1 Disturbance Monitoring Requirements","6.1.2 Fault Recording Equipment","6.1.2","2015-09-25","Fault recording equipment includes digital fault recorders, certain protective relays and/or meters with fault recording capability, and dynamic disturbance recorders that meet the triggering requirements in Section 6.1.2.3, Data Recording Requirements.  Fault recording equipment required by these Operating Guides shall be time synchronized with a Global Positioning System-based clock, or ERCOT-approved alternative, with sub-cycle (2 millisecond) timing accuracy and performance.","TSP","PRC-018-1 & PRC-002-2"]
[183,"DME","6 Disturbance Monitoring and System Protection, 6.1 Disturbance Monitoring Requirements","6.1.2 Fault Recording Equipment","6.1.2.1","2015-09-25","Triggering Requirements\nFault recording equipment triggering must occur for system voltage magnitude and current magnitude disturbances (delta V and delta I) without requiring any circuit breaker operations or trip outputs from protective relay systems. Triggering shall be adjusted to operate for faults in the area to be monitored, which should overlap into the area of coverage of adjacent fault recorders.","TSP","PRC-018-1 & PRC-002-2"]
[184,"DME","6 Disturbance Monitoring and System Protection, 6.1 Disturbance Monitoring Requirements","6.1.2 Fault Recording Equipment","6.1.2.2","2015-09-25","Location Requirements\nThe location criteria listed below shall apply to Facilities operated at or above 100 kV.  The Facility owner(s), whether a Transmission Service Provider (TSP) or Generation Entity, shall install fault recording equipment at the following Facilities, at a minimum: (a) Interconnections with non-ERCOT Control Areas (i.e., outside ERCOT Region);\n(b) Substations where electrical transfers of equipment can be made between the ERCOT Control Area and non-ERCOT Control Area;\n(c) Substations having three or more non-radial 345 kV line terminals. If a switching station is one bus removed from a station with a larger number of line terminals, then the fault recorder shall be located at the larger station and not required at the smaller station;\n(d) Substations that are more than one circuit breaker-controlled bus away from a fault recorder and have five or more non-radial line terminals at or above 100 kV;\n(e) For the purpose of evaluating items (c) and (d) above, an individual autotransformer rated 150 MVA or greater (based upon minimum nameplate rating upon which transformer impedance is stated (i.e., base rating)) shall constitute a non-radial line terminal at the highest voltage level to which it is directly connected; and\n(f) At all generating station switchyards connected to the ERCOT System with an aggregated generating capacity above 100 MVA or at the remote line terminals of each generating station switchyard.","TSP","PRC-018-1 & PRC-002-2\nNote: The language in this requirements indicates that facility owners are either TSPs or Generation Entities."]
[185,"DME","6 Disturbance Monitoring and System Protection, 6.1 Disturbance Monitoring Requirements","6.1.2 Fault Recording Equipment","6.1.2.3(1)","2015-09-25","For Facilities operating at 100 kV or above where fault recording equipment is required, recorded electrical quantities shall be sufficient to determine the following: (a) Two sets of substation voltage measurements for breaker-and-a-half and ring bus substation configurations. One set of substation voltage measurements for each bus in other substation configurations. A set of voltage measurements shall consist of each phase voltage waveform;\n(b) For all lines, neutral (residual) current waveform;\n(c) Circuit breaker status;\n(d) Circuit breaker trip circuit status; and\n(e) Date and time stamp in a consistent manner; either Universal Coordinated Time (UTC) or Central Prevailing Time (CPT).","TSP","PRC-018-1 & PRC-002-2"]
[186,"DME","6 Disturbance Monitoring and System Protection, 6.1 Disturbance Monitoring Requirements","6.1.2 Fault Recording Equipment","6.1.2.3(2)","2015-09-25","For all new or upgraded fault recorder installations, recorded electrical quantities shall be sufficient to determine the following additional items: (a) For all autotransformers, high or low voltage terminal current waveform for three phases and either neutral/residual current waveform or current waveform in delta windings;\n(b) For all lines, two phase current waveforms;\n(c) Status – carrier transmitter control (i.e. start, stop, keying); and\n(d) Status – carrier received.","TSP","PRC-018-1 & PRC-002-2"]
[187,"DME","6 Disturbance Monitoring and System Protection, 6.1 Disturbance Monitoring Requirements","6.1.2 Fault Recording Equipment","6.1.2.4(1)","2015-09-25","The disturbance monitoring equipment owner storing the recorded data shall store all recorded fault data for at least a three year period.  This data shall be stored in the form of a computer file or files.","TSP","PRC-018-1 & PRC-002-2"]
[188,"DME","6 Disturbance Monitoring and System Protection, 6.1 Disturbance Monitoring Requirements","6.1.2 Fault Recording Equipment","6.1.2.4(2)","2015-09-25","Disturbance monitoring equipment owners shall provide fault recordings to ERCOT or the North American Electric Reliability Corporation (NERC) upon their request, within five Business Days, along with channel identification and scaling information to allow analysis of the recordings.  Fault recordings shall be shared between Facility owners, upon their request, for the analysis of ERCOT System disturbances.","TSP","PRC-018-1 & PRC-002-2"]
[189,"DME","6 Disturbance Monitoring and System Protection, 6.1 Disturbance Monitoring Requirements","6.1.2 Fault Recording Equipment","6.1.2.4(3)","2015-09-25","When multiple recordings exist for a single event, only provide data to ERCOT and NERC from the best available recording, usually the closest recorder is preferred.","TSP","PRC-018-1 & PRC-002-2"]
[190,"DME","6 Disturbance Monitoring and System Protection, 6.1 Disturbance Monitoring Requirements","6.1.2 Fault Recording Equipment","6.1.2.4(4)","2015-09-25","Data submissions shall be COMTRADE fault recordings, .cfg and .dat files, and one or more identification files that associate the COMTRADE recordings with ERCOT System disturbances and ERCOT short circuit database bus numbers.  The identification file shall be a Microsoft Excel© spreadsheet or comma delimited ASCII text that can be read into a Microsoft Excel© spreadsheet.  For this file, the data fields to be reported for each record, in the following order, are: [Please refer to Operating Guides for the table of data fields]","TSP","PRC-018-1 & PRC-002-2"]
[191,"DME","6 Disturbance Monitoring and System Protection, 6.1 Disturbance Monitoring Requirements","6.1.2 Fault Recording Equipment","6.1.2.5","2015-09-25","Facility/equipment owners shall maintain and test their fault recording equipment as follows: (a) In accordance with the manufacturer’s recommendations;\n(b) Calibration of the analog (waveform) channels shall be performed at installation and when records from the equipment indicate a calibration problem. Calibration can be monitored through the analysis and correlation of fault records with system models and the records of other fault recorders in the area; and\n(c) Fault recording equipment must be operationally tested at least annually to ensure that the equipment is functional. Acceptable tests are the production of a manually triggered record either remotely or at the device, or automatic record production due to a power system disturbance.","TSP","PRC-018-1 & PRC-002-2"]
[192,"DME","6 Disturbance Monitoring and System Protection, 6.1 Disturbance Monitoring Requirements","6.1.3 Phasor Measurement Recording Equipment","6.1.3(1)","2015-09-25","[Phasor measurement recording equipment includes digital fault recorders, certain protective relays and/or meters with phasor measurement recording capability that meet the requirements in Sections 6.1.3.1, Recording Requirements and 6.1.3.3, Data Recording and Redundancy Requirements.]  Phasor measurement recording equipment required by these Operating Guides shall be time synchronized with a Global Positioning System-based clock, or ERCOT-approved alternative, with sub-cycle (<1 microsecond) timing accuracy and performance.","TSP","PRC-018-1 & PRC-002-2"]
[193,"DME","6 Disturbance Monitoring and System Protection, 6.1 Disturbance Monitoring Requirements","6.1.3 Phasor Measurement Recording Equipment","6.1.3.1(1)","2015-09-25","Recorded electrical quantities shall be: (a) Provided in Institute of Electrical and Electronic Engineers (IEEE) C37.118.1-2011, IEEE Standard for Synchrophasor format;\n(b) A minimum output recording rate of 30 times per second;\n(c) A minimum input sampling rate of 960 samples per second; and\n(d) Transmitted to an ERCOT phasor data concentrator via a communication link or stored locally per retention requirements in Section 6.1.3.4, Data Retention and Reporting Requirements.","TSP","PRC-018-1 & PRC-002-2"]
[194,"DME","6 Disturbance Monitoring and System Protection, 6.1 Disturbance Monitoring Requirements","6.1.3 Phasor Measurement Recording Equipment","6.1.3.2(1)","2015-09-25","The Facility owner(s), whether a TSP or new Generation Entity, shall install phasor measurement recording equipment at the following Facilities.  The installation shall occur not later than 18 months after a written notification from ERCOT to the Facility owner.  (a) Flexible AC transmission system devices configured to actively control steady-state voltage or power transfer capability, operated at or above 100kV, and energized after July 1, 2015;\n(b) One Transmission Facility identified by ERCOT associated with each published generic transmission constraint as deemed necessary by ERCOT; and\n(c) New generating Facilities over 20 MVA aggregated at a single site placed into service after January 1, 2017;","TSP","PRC-018-1 & PRC-002-2"]
[195,"DME","6 Disturbance Monitoring and System Protection, 6.1 Disturbance Monitoring Requirements","6.1.3 Phasor Measurement Recording Equipment","6.1.3.3(1)","2015-09-25","Recorded electrical quantities shall be sufficient to determine the following: (a) For locations meeting paragraphs (1)(a) or (1)(b) of Section 6.1.3.2, Location Requirements:\n(i) Phase-to-neutral voltage magnitude/angle data for each phase from at least two distinct transmission level element measurements;\n(ii) Single phase current magnitude/angle data for each phase from at least two distinct transmission level lines; and\n(iii) Frequency and df/dt data for at least two transmission level element measurements.\n(b) For locations meeting paragraph (1)(c) of Section 6.1.3.2:\n(i) Phase-to-neutral voltage magnitude/angle data for each phase from at least one generator-interconnected bus measurement; (ii) Single phase current magnitude/angle data for each phase from each interconnected generator over 20 MVA; and\n(iii) Frequency and df/dt data for at least one generator-interconnected bus measurement.","TSP","PRC-018-1 & PRC-002-2"]
[196,"DME","6 Disturbance Monitoring and System Protection, 6.1 Disturbance Monitoring Requirements","6.1.3 Phasor Measurement Recording Equipment","6.1.3.4(1)","2015-09-25","The minimum recorded electrical quantities shall be retained per the following guidelines: (a) Rolling ten calendar day window for all data stored locally and not transmitted to an ERCOT phasor data concentrator;\n(b) Minimum three year data retention by the generating Facility owner for event data utilized for model validation in accordance with NERC Reliability Standards; and\n(c) Minimum three year data retention by the generating or Transmission Facility owner for event data provided to ERCOT via written request that is recorded in the context of an ERCOT-initiated disturbance analysis or event review.","TSP","PRC-018-1 & PRC-002-2"]
[197,"DME","6 Disturbance Monitoring and System Protection, 6.1 Disturbance Monitoring Requirements","6.1.4 Equipment Reporting Requirements","6.1.4(1)","2015-09-25","Disturbance monitoring equipment owners shall maintain a current database summarizing their disturbance monitoring equipment installations.","TSP","PRC-018-1 & PRC-002-2"]
[198,"DME","6 Disturbance Monitoring and System Protection, 6.1 Disturbance Monitoring Requirements","6.1.4 Equipment Reporting Requirements","6.1.4(2)","2015-09-25","The database shall include installation location, type of equipment, make and model of equipment, operational status, a listing of the major equipment being monitored and the date the equipment was last tested.  This database shall be submitted to ERCOT annually, by October 31.  Additionally, a complete list of all monitored points at each installation shall be maintained by disturbance monitoring equipment owners and provided, when requested specifically by ERCOT or NERC, within 30 days.","TSP","PRC-018-1 & PRC-002-2"]
[199,"DME","6 Disturbance Monitoring and System Protection, 6.1 Disturbance Monitoring Requirements","6.1.4 Equipment Reporting Requirements","6.1.4(3)","2015-09-25","ERCOT shall maintain and update annually, a comprehensive database of all disturbance monitoring equipment owners’ disturbance monitoring equipment submittals.","-"]
[200,"Protective Relay Systems","6 Disturbance Monitoring and System Protection, 6.2 System Protective Relaying","6.2.1 Introduction","6.2.1(2)","2015-09-25","Although relaying of tie points between Facility owners is of primary concern to the ERCOT System, internal protective relay systems often directly, or indirectly, affects the adjacent area also.  Facility owners are those Entities owning Facilities in the ERCOT System.  Facility owners have an obligation to implement relay application, operation, and preventive maintenance criteria that assure the highest practicable reliability and availability of service to the ultimate power consumers of the concerned area and neighboring areas.  Protective relay systems of individual Facility owners shall not adversely affect the stability of the ERCOT System.  Additional minimum protective relay system requirements are outlined in the North American Electric Reliability Corporation (NERC) Reliability Standards.","RE/\nTDSP"]
[201,"Protective Relay Systems","6 Disturbance Monitoring and System Protection, 6.2 System Protective Relaying","6.2.1 Introduction","6.2.1.1","2015-09-25","These objectives and design practices shall apply to all new protective relay systems applied at 60 kV and above unless otherwise specified.  It is recognized that there may be portions of the existing ERCOT System that do not meet these objectives.  It is the responsibility of individual facility owners to assess the protective relay systems at these locations and to make any modifications that they deem necessary.  Similar assessment and judgment should be used with respect to protective relay systems existing at the time of revisions to this guide.  Special local conditions or considerations may necessitate the use of more stringent design criteria and practices.","RE/\nTDSP"]
[202,"Protective Relay Systems","6 Disturbance Monitoring and System Protection, 6.2 System Protective Relaying","6.2.2 Design and Operating Requirements for ERCOT System Facilities","6.2.2(1)","2015-09-25","Protective relay systems shall be designed to provide reliability, a combination of dependability and security, so that protective relay systems will perform correctly to remove faulted equipment from the ERCOT System.","RE/\nTDSP"]
[203,"Protective Relay Systems","6 Disturbance Monitoring and System Protection, 6.2 System Protective Relaying","6.2.2 Design and Operating Requirements for ERCOT System Facilities","6.2.2(2)","2015-09-25","For planned ERCOT System conditions, protective relay systems shall be designed not to trip for swings which do not exceed the steady-state stability limit (note that when out-of-step blocking is used in one location, a method of out-of-step tripping should also be considered).  Protective relay systems shall not interfere with the operation of the ERCOT System under the procedures identified in the other sections of these Operating Guides.","RE/\nTDSP"]
[204,"Protective Relay Systems","6 Disturbance Monitoring and System Protection, 6.2 System Protective Relaying","6.2.2 Design and Operating Requirements for ERCOT System Facilities","6.2.2(4)","2015-09-25","The thermal capability of all protection system components shall be adequate to withstand the maximum short time and continuous loading conditions to which the associated protected Transmission elements may be subjected, even as a result of Credible Single Contingency conditions.","RE/\nTDSP"]
[205,"Protective Relay Systems","6 Disturbance Monitoring and System Protection, 6.2 System Protective Relaying","6.2.2 Design and Operating Requirements for ERCOT System Facilities","6.2.2(5)","2015-09-25","Applicable Institute of Electrical and Electronic Engineers (IEEE)/American National Standards Institute (ANSI) guidelines shall be considered when applying protective relay systems on the ERCOT System.","RE/\nTDSP"]
[206,"Protective Relay Systems","6 Disturbance Monitoring and System Protection, 6.2 System Protective Relaying","6.2.2 Design and Operating Requirements for ERCOT System Facilities","6.2.2(6)","2015-09-25","The planning and design of generation, transmission and substation configurations shall take into account the protective relay system requirements of dependability, security and simplicity.  If configurations are proposed that require protective relay systems that do not conform to these Operating Guides or to accepted IEEE/ANSI practice, then the Facility owners affected shall negotiate a solution.","RE/\nTDSP"]
[207,"Protective Relay Systems","6 Disturbance Monitoring and System Protection, 6.2 System Protective Relaying","6.2.2 Design and Operating Requirements for ERCOT System Facilities","6.2.2(7)","2015-09-25","The design, coordination, and maintainability of all existing protective relay systems shall be reviewed periodically by the Facility owner to ensure that protective relay systems continue to meet ERCOT System requirements.  This review shall include the need for redundancy.  Documentation of the review shall be maintained and supplied by the Facility owner to ERCOT or NERC on their request within 30 days.  This documentation shall be reviewed by ERCOT for verification of implementation.","RE/\nTDSP"]
[208,"Protective Relay Systems","6 Disturbance Monitoring and System Protection, 6.2 System Protective Relaying","6.2.2 Design and Operating Requirements for ERCOT System Facilities","6.2.2(8)","2015-09-25","Upon ERCOT’s request, within 30 days, Generation Entities shall provide ERCOT with the operating characteristics of any generating equipment protective relay systems or controls that may respond to temporary excursions in voltage, frequency, or loading with actions that could lead to tripping of the generator.","RE"]
[209,"Protective Relay Systems","6 Disturbance Monitoring and System Protection, 6.2 System Protective Relaying","6.2.2 Design and Operating Requirements for ERCOT System Facilities","6.2.2(9)","2015-09-25","Upon ERCOT’s request, within 30 days, Generation Entities shall provide ERCOT with information that describes how generator controls coordinate with the generator’s short-term capabilities and protective relay systems.","RE"]
[210,"Protective Relay Systems","6 Disturbance Monitoring and System Protection, 6.2 System Protective Relaying","6.2.2 Design and Operating Requirements for ERCOT System Facilities","6.2.2(10)","2015-09-25","Over-excitation limiters, when used, shall be coordinated with the thermal capability of the generator field winding.  After allowing temporary field current overload, the limiter shall operate through the automatic AC voltage regulator to reduce field current to the continuous rating.  Return to normal AC voltage regulation after current reduction shall be automatic.  The over-excitation limiter shall be coordinated with the over-excitation protection so that over-excitation protection only operates for failure of the voltage regulator/limiter.  Upon ERCOT’s request, within 30 days, Generation Entities shall provide documentation of coordination.","RE"]
[211,"Protective Relay Systems","6 Disturbance Monitoring and System Protection, 6.2 System Protective Relaying","6.2.3 Performance Analysis Requirements for ERCOT System Facilties","6.2.3(1)","2015-09-25","All ERCOT System disturbances (unwanted trips, faults, and protective relay system operations) shall be analyzed by the affected facility owner(s) promptly and any deficiencies shall be investigated and corrected.","RE/\nTSP"]
[212,"Protective Relay Systems","6 Disturbance Monitoring and System Protection, 6.2 System Protective Relaying","6.2.3 Performance Analysis Requirements for ERCOT System Facilties","6.2.3(2)","2015-09-25","All protective relay system misoperations and all associated corrective actions in Generation Resource systems or Transmission Facility systems 100 kV and above shall be documented, and documentation shall be supplied by the affected Facility owner(s) to ERCOT or the Texas Reliability Entity (Texas RE) upon request.  Any of the following events constitute a reportable protective relay system misoperation: (a) Failure to Trip – Any failure of a protective relay system to initiate a trip to the appropriate terminal when a fault is within the intended zone of protection of the device (zone of protection includes both the reach and time characteristics). Lack of targeting, such as when a high-speed pilot system is beat out of high-speed zone is not a reportable misoperation. Furthermore, if the fault clearing is consistent with the time normally expected with proper functioning of at least one protection system, then a primary or backup protection system failure to operate is not required to be reported;\n(b) Slow Trip – An operation of a protective relay system for a fault in the intended zone of protection where the relay system initiates tripping slower than the system design intent;\n(c) Unnecessary Trip During a Fault – Any unnecessary protective relay system operation for a fault not within the zone of protection. Operation as backup protection for a fault in an adjacent zone that is not cleared within the specified time for the protection for that adjacent zone is not a reportable operation; and\n(d) Unnecessary Trip Other Than Fault – Any unnecessary protective relay system operation when no fault or other abnormal condition has occurred. Note that an operation that occurs during on-site maintenance, testing, construction and/or commissioning activities is not a reportable misoperation.","RE/\nTSP","PRC-004-2.1a"]
[213,"Protective Relay Systems","6 Disturbance Monitoring and System Protection, 6.2 System Protective Relaying","6.2.3 Performance Analysis Requirements for ERCOT System Facilties","6.2.3(3)","2015-09-25","Any of the following events do not constitute a reportable protective relay system misoperation: (a) Trip Initiated by a Control System – Operations which are initiated by control systems (not by protective relay system), such as those associated with generator controls, or turbine/boiler controls, Static VAr Compensators, Flexible AC Transmission devices, HVDC terminal equipment, circuit breaker mechanism, or other facility control systems, are not considered protective relay system misoperations;\n(b) Facility owner authorized personnel action that directly initiates a trip is not considered a misoperation. It is the intent of this reporting process to identify misoperations of the protective relay system as it interrelates with the electrical system, not as it interrelates to personnel involved with the protective relay system. If an individual directly initiates an operation, it is not counted as a misoperation (i.e., unintentional operation during tests); however, if a technician leaves trip test switches or cut-off switches in an inappropriate position and a system fault or condition causes a misoperation, this would be counted as a protective relay system misoperation; and\n(c) Failure of Relay Communications – A communication failure in and of itself is not a misoperation if it does not result in misoperation of the associated protective relay system.","RE/\nTSP","PRC-004-2.1a"]
[214,"Protective Relay Systems","6 Disturbance Monitoring and System Protection, 6.2 System Protective Relaying","6.2.3 Performance Analysis Requirements for ERCOT System Facilties","6.2.3(4)","2015-09-25","All Special Protection System (SPS) misoperations shall be documented, including corrective actions and the documentation supplied to ERCOT and Texas RE upon request.  Any of the following events constitute a reportable SPS misoperation: (a) Failure to Operate – Any failure of a SPS to perform its intended function within the designed time when system conditions intended to trigger the SPS occurs;\n(b) Failure to Arm – Any failure of a SPS to automatically arm itself for system conditions that are intended to result in the SPS being automatically armed;\n(c) Unnecessary Operation – Any operation of a SPS that occurs without the occurrence of the intended system trigger condition(s);\n(d) Unnecessary Arming – Any automatic arming of a SPS that occurs without the occurrence of the intended arming system condition(s); and\n(e) Failure to Reset – Any failure of a SPS to automatically reset following a return of normal system conditions if that is the system design intent.","RE/\nTSP","PRC-015-0 & PRC-016-0.1"]
[215,"Protective Relay Systems","6 Disturbance Monitoring and System Protection, 6.2 System Protective Relaying","6.2.3 Performance Analysis Requirements for ERCOT System Facilties","6.2.3(5)","2015-09-25","Transmission Facility owners shall document the performance of their protective relay systems.  The performance data reported shall include the total number of protective relay system misoperations and the total number of events.","RE/\nTSP"]
[216,"Protective Relay Systems","6 Disturbance Monitoring and System Protection, 6.2 System Protective Relaying","6.2.3 Performance Analysis Requirements for ERCOT System Facilties","6.2.3(6)","2015-09-25","Protective relay system misoperations shall be reported to the Texas RE per Texas RE procedure, and to ERCOT using either the Relay Misoperations Report form on the ERCOT website or any other form that contains the same information and that is provided in a similar format as the ERCOT Relay Misoperations Report.  Relay Misoperation Reports and SPS misoperations reports shall be submitted to ERCOT on a quarterly basis per the following schedule:\nData submission Date*\nSubmission of the 1st Quarter data  May 31\nSubmission of the 2nd Quarter data  August 31\nSubmission of the 3rd Quarter data  November 30\nSubmission of 4th Quarter data February 28\n*Next Business Day if date specified is a non-Business Day","TSP","PRC-004-3"]
[217,"DME","6 Disturbance Monitoring and System Protection, 6.2 System Protective Relaying","6.2.3 Performance Analysis Requirements for ERCOT System Facilties","6.2.3(7)","2015-09-25","All Facility owners shall install, maintain, and operate disturbance monitoring equipment in accordance with the requirements in Section 6.1.2.3, Data Recording Requirements.","TSP","PRC-018-1"]
[218,"Protective Relay Systems","6 Disturbance Monitoring and System Protection, 6.2 System Protective Relaying","6.2.4 Protective Relay System Failure Response","6.2.4(3)","2015-09-25","The owner of protective relay systems will immediately notify the appropriate Qualified Scheduling Entity (QSE) and Transmission Operator (TO) via phone call, when the owner has determined that the protective relay system has failed. ","RE/\nTSP","PRC-001-2 R2."]
[219,"Protective Relay Systems","6 Disturbance Monitoring and System Protection, 6.2 System Protective Relaying","6.2.4 Protective Relay System Failure Response","6.2.4(4)","2015-09-25","The affected QSE or TO shall immediately notify the ERCOT Shift Supervisor via phone call and initiate prompt corrective action.  These corrective actions are to address reliability issues for the systems that the QSE and TO monitor and/or operate.","QSE/\nTO","PRC-001-2 R2."]
[220,"Protective Relay Systems","6 Disturbance Monitoring and System Protection, 6.2 System Protective Relaying","6.2.4 Protective Relay System Failure Response","6.2.4(5)","2015-09-25","Corrective action in this context means limiting exposure to the bulk electric system and does not include the maintenance or repair of relays. These actions shall be taken as prescribed by the Outage Coordination process in Section 2.4, Outage Coordination, and Protocol Section 3, Management Activities for the ERCOT System.  Examples of corrective actions include:\n(a) Removing the affected facility from service, and\n(b) Entering the status change into Outage Scheduler.","RE/\nTSP","PRC-001-2 R2."]
[221,"Protective Relay Systems","6 Disturbance Monitoring and System Protection, 6.2 System Protective Relaying","6.2.4 Protective Relay System Failure Response","6.2.4(7)","2015-09-25","The affected QSE and TO shall promptly notify the ERCOT Shift Supervisor via phone call of the return to service of the previously identified protective relay systems.","QSE/\nTO","PRC-001-2 R2."]
[222,"Protective Relay Systems","6 Disturbance Monitoring and System Protection, 6.2 System Protective Relaying","6.2.5 Maintenance and Testing Requirements for ERCOT System Facilities","6.2.5(1)","2015-09-25","The facility owner shall test and verify the proper operation of each new or modified protective relay system and associated communications channels prior to placing the equipment in its zone(s) of protection in service.  For protective relay systems that utilize a propagation-delay-sensitive operating principle and a communication channel with potentially significant propagation delay, time-synchronized “end-to-end” testing of the protective relay system shall be performed to verify that communication channel performance (including alternate routes) is adequate for proper operation.","RE/\nTSP","PRC-005-2"]
[223,"Protective Relay Systems","6 Disturbance Monitoring and System Protection, 6.2 System Protective Relaying","6.2.5 Maintenance and Testing Requirements for ERCOT System Facilities","6.2.5(2)","2015-09-25","Facility owners shall have documented protective relay system maintenance and testing programs in place.  Documentation shall include identification of protective relay system, a summary of testing procedures including requirements for frequency of tests, and the date last tested.","RE/\nTSP","PRC-005-2"]
[224,"Protective Relay Systems","6 Disturbance Monitoring and System Protection, 6.2 System Protective Relaying","6.2.5 Maintenance and Testing Requirements for ERCOT System Facilities","6.2.5(3)","2015-09-25","The facility owner shall periodically test and inspect all components of the protective relay system to assure continued reliability.  Identified deficiencies shall be corrected.  Documentation demonstrating compliance with the facility owner’s maintenance and testing programs shall be supplied to ERCOT or NERC upon their request within 30 days.","RE/\nTSP","PRC-005-2"]
[225,"Protective Relay Systems","6 Disturbance Monitoring and System Protection, 6.2 System Protective Relaying","6.2.6 Requirements and Recommendations for ERCOT System Facilities","6.2.6.1.1(1)","2015-09-25","Except as noted in paragraphs (4) and (5) below, all elements of the ERCOT System operated at 100 kV and above (i.e., lines, buses, transformers, generators, breakers, capacitor banks, etc.) shall be protected by two protective relay systems.  Each protective relay system shall be independently capable of detecting and isolating all faults thereon.","RE/\nTSP"]
[226,"Protective Relay Systems","6 Disturbance Monitoring and System Protection, 6.2 System Protective Relaying","6.2.6 Requirements and Recommendations for ERCOT System Facilities","6.2.6.1.1(2)","2015-09-25","The protective relay system design should avoid the use of components common to the two protective relay systems.  Areas of common exposure should be kept to a minimum to reduce the possibility of both protective relay systems being disabled by a single contingency.","RE/\nTSP"]
[227,"Protective Relay Systems","6 Disturbance Monitoring and System Protection, 6.2 System Protective Relaying","6.2.6 Requirements and Recommendations for ERCOT System Facilities","6.2.6.1.1(3)","2015-09-25","The use of two identical protective relay systems is not generally recommended, due to the risk of simultaneous failure of both protective relay systems because of design deficiencies or equipment problems.","-"]
[228,"Protective Relay Systems","6 Disturbance Monitoring and System Protection, 6.2 System Protective Relaying","6.2.6 Requirements and Recommendations for ERCOT System Facilities","6.2.6.1.1(4)","2015-09-25","Breaker failure protection should be provided to trip all necessary local and remote breakers in the event that a breaker fails to clear a fault.  This protection need not be duplicated.","RE/\nTSP"]
[229,"Protective Relay Systems","6 Disturbance Monitoring and System Protection, 6.2 System Protective Relaying","6.2.6 Requirements and Recommendations for ERCOT System Facilities","6.2.6.1.1(5)","2015-09-25","On installations where freestanding or column-type current transformers are provided on one side of the breaker only, the protective relay systems should be provided to detect a fault on the primaries of such current transformers.  This protection need not be duplicated.  Application of freestanding current transformers requires extra care to ensure that the relaying is proper and that the schemes overlap.","RE/\nTSP"]
[230,"Protective Relay Systems","6 Disturbance Monitoring and System Protection, 6.2 System Protective Relaying","6.2.6 Requirements and Recommendations for ERCOT System Facilities","6.2.6.1.2","2015-09-25","The protective relay systems should be designed to isolate only the faulted element, except in those circumstances where additional elements should be tripped intentionally to preserve system integrity.  For faults external to the protected zone, each protective relay systems should be designed to either not operate, or to operate selectively with other systems, including breaker failure.  In this context, the limits of the protected zone are defined by the circuit breakers.","RE/\nTSP"]
[231,"Protective Relay Systems","6 Disturbance Monitoring and System Protection, 6.2 System Protective Relaying","6.2.6 Requirements and Recommendations for ERCOT System Facilities","6.2.6.1.3(1)","2015-09-25","The protective relay systems should be no more complex than required for any given application.","RE/\nTSP"]
[232,"Protective Relay Systems","6 Disturbance Monitoring and System Protection, 6.2 System Protective Relaying","6.2.6 Requirements and Recommendations for ERCOT System Facilities","6.2.6.1.3(2)","2015-09-25","To the maximum degree practicable, the components used in the protective relay systems should be of proven quality, as demonstrated either by actual experience or by stringent tests under simulated operating conditions, to ensure that the reliability of the protective relay system(s) is not degraded by the components.","RE/\nTSP"]
[233,"Protective Relay Systems","6 Disturbance Monitoring and System Protection, 6.2 System Protective Relaying","6.2.6 Requirements and Recommendations for ERCOT System Facilities","6.2.6.1.3(3)","2015-09-25","The protective relay system shall be designed to minimize the possibility of component failure or malfunction due to electrical transients and electromagnetic interference or external effects such as vibration, shock and temperature.","RE/\nTSP"]
[234,"Protective Relay Systems","6 Disturbance Monitoring and System Protection, 6.2 System Protective Relaying","6.2.6 Requirements and Recommendations for ERCOT System Facilities","6.2.6.1.3(4)","2015-09-25","Critical features associated with protective relay systems and circuit breaker operation shall be annunciated or monitored.","RE/\nTSP"]
[235,"Protective Relay Systems","6 Disturbance Monitoring and System Protection, 6.2 System Protective Relaying","6.2.6 Requirements and Recommendations for ERCOT System Facilities","6.2.6.1.3(5)","2015-09-25","The protective relay system circuitry and physical arrangements shall be carefully designed so as to minimize the possibility of incorrect operations due to personnel error.","RE/\nTSP"]
[236,"Protective Relay Systems","6 Disturbance Monitoring and System Protection, 6.2 System Protective Relaying","6.2.6 Requirements and Recommendations for ERCOT System Facilities","6.2.6.1.3(6)","2015-09-25","Computerized fault studies shall be used during the planning or design stages to analyze the effects of an addition or modification to the ERCOT System and to determine proper protective relay system coordination.","RE/\nTSP"]
[237,"Protective Relay Systems","6 Disturbance Monitoring and System Protection, 6.2 System Protective Relaying","6.2.6 Requirements and Recommendations for ERCOT System Facilities","6.2.6.1.3(7)","2015-09-25","To the extent dynamic or transient analysis shows that a protection system, designed within the guidelines contained in these Operating Guides, is unable to operate in a manner that maintains continuity of service and/or system stability in accordance with NERC Reliability Standards and the Operating Guides, additional measures shall be considered for improvement to the operation of the protection system.  Additional measures may include redundant current transformers, voltage transformers, power supplies and communication paths.","RE/\nTSP"]
[238,"Protective Relay Systems","6 Disturbance Monitoring and System Protection, 6.2 System Protective Relaying","6.2.6 Requirements and Recommendations for ERCOT System Facilities","6.2.6.1.4","2015-09-25","The objective of the protective relay systems is to take corrective action in the shortest practical time with due regard to selectivity, dependability and security.  In cases where clearing times are deliberately extended, consideration should be given to the following:\n(a) Effect on ERCOT System stability or reduction of stability margins.\n(b) Possibility of causing or increasing damage to equipment and subsequent extended repair and/or outage time.\n(c) Effect of disturbances on service to customers and neighboring facility owners.","RE/\nTSP"]
[239,"Protective Relay Systems","6 Disturbance Monitoring and System Protection, 6.2 System Protective Relaying","6.2.6 Requirements and Recommendations for ERCOT System Facilities","6.2.6.1.5(1)","2015-09-25","The design of protective relay systems both in terms of circuitry and physical arrangement shall facilitate periodic testing and maintenance.  Test devices or switches should be provided to eliminate the necessity for removing or disconnecting wires during periodic testing.  Protective relays for transmission lines shall be designed to support periodic testing and maintenance while the transmission line remains in service.","RE/\nTSP"]
[240,"Protective Relay Systems","6 Disturbance Monitoring and System Protection, 6.2 System Protective Relaying","6.2.6 Requirements and Recommendations for ERCOT System Facilities","6.2.6.1.5(2)","2015-09-25","Commissioning of new equipment should consist of the following steps: (a) Relay installation wiring diagrams cross-checked against schematics;\n(b) After completion of construction, physical check of wiring and relay installation;\n(c) Check and testing before energizing of all equipment in the zone of protection, including relay testing. It is desirable to test the relays at the setting the relay will have in service;\n(d) Check of supporting paperwork, such as relay test reports;\n(e) Check that relays physically agree with the relay settings;\n(f) Check that proper settings have been made;\n(g) Written record of trip check and energize procedure;\n(h) In-service measurement of voltage and current magnitudes and phase angles, and comparison to expected values and to other instrumentation; and\n(i) Release to facility owner’s operating personnel for service.","RE/\nTSP"]
[241,"Protective Relay Systems","6 Disturbance Monitoring and System Protection, 6.2 System Protective Relaying","6.2.6 Requirements and Recommendations for ERCOT System Facilities","6.2.6.1.6(1)","2015-09-25","Relay operation and settings shall be reviewed periodically and whenever significant changes in generating sources, transmission facilities, or operating conditions are anticipated.","RE/\nTSP"]
[242,"Protective Relay Systems","6 Disturbance Monitoring and System Protection, 6.2 System Protective Relaying","6.2.6 Requirements and Recommendations for ERCOT System Facilities","6.2.6.1.6(2)","2015-09-25","Naturally occurring faults and other system disturbances should be analyzed as a source of information as to the health of relay schemes in the facility owner’s system and the ERCOT System.  Sources of information usually available are:\n(a) Short circuit study for the exact conditions of the fault;\n(b) Fault recorder traces;\n(c) Sequence of events data recording the opening and closing of contacts in the protective relay scheme and associated communication equipment;\n(d) Fault locator data;\n(e) SCADA logger output of breaker operation and alarms;\n(f) Interviews with operating personnel and/or other witnesses;\n(g) Field report of relay flags and breaker counter changes;\n(h) Field report of the fault location, if found;\n(i) Records of relay setting, relay testing, trip check and energize procedures as carried out, in-service measurements, relay wiring diagrams and schematics, manufacturers' information;\n(j) Other utility personnel and System Protection Working Group (SPWG) members; and\n(k) Manufacturers' application and design engineers.","RE/\nTSP"]
[243,"Protective Relay Systems","6 Disturbance Monitoring and System Protection, 6.2 System Protective Relaying","6.2.6 Requirements and Recommendations for ERCOT System Facilities","6.2.6.1.6(3)","2015-09-25","Steps that may be followed in analyzing a disturbance include:\n(a) Gather data;\n(b) Create a time line consisting of events and periods between events;\n(c) Compare actual and calculated values of current and voltage during the periods between events;\n(d) Compare actual and expected breaker operations and flags;\n(e) Choose the least complicated explanation for contradictory information and to fill in missing information;\n(f) Gather additional information as indicated to prove or disprove explanations;\n(g) Iterate;\n(h) Document by issuing a report of all findings, changes, and recommendations; and\n(i) After a reasonable time, check back to see if the recommendations have been carried out.","RE/\nTSP"]
[244,"Protective Relay Systems","6 Disturbance Monitoring and System Protection, 6.2 System Protective Relaying","6.2.6 Requirements and Recommendations for ERCOT System Facilities","6.2.6.2.1(1)","2015-09-25","Current transformers associated with protective relay systems shall have adequate steady state and transient characteristics for their intended function.","RE/\nTSP"]
[245,"Protective Relay Systems","6 Disturbance Monitoring and System Protection, 6.2 System Protective Relaying","6.2.6 Requirements and Recommendations for ERCOT System Facilities","6.2.6.2.1(2)","2015-09-25","The output of each current transformer shall remain within acceptable limits for the connected burdens under all anticipated fault currents to ensure correct operation of the protective relay system.","RE/\nTSP"]
[246,"Protective Relay Systems","6 Disturbance Monitoring and System Protection, 6.2 System Protective Relaying","6.2.6 Requirements and Recommendations for ERCOT System Facilities","6.2.6.2.1(3)","2015-09-25","Current transformers or their secondary windings shall be located so that adjacent protection zones overlap.","RE/\nTSP"]
[247,"Protective Relay Systems","6 Disturbance Monitoring and System Protection, 6.2 System Protective Relaying","6.2.6 Requirements and Recommendations for ERCOT System Facilities","6.2.6.2.1(4)","2015-09-25","Current transformer secondary wiring shall be grounded at only one point.  When multiple current transformers are interconnected, the combination shall have only one ground.","RE/\nTSP"]
[248,"Protective Relay Systems","6 Disturbance Monitoring and System Protection, 6.2 System Protective Relaying","6.2.6 Requirements and Recommendations for ERCOT System Facilities","6.2.6.2.1(5)","2015-09-25","For all newly installed protective relay systems, the two protective relay systems protecting a zone shall utilize isolated and separate current transformers, or isolated and separate secondary windings in the case of free-standing current transformers.","RE/\nTSP"]
[249,"Protective Relay Systems","6 Disturbance Monitoring and System Protection, 6.2 System Protective Relaying","6.2.6 Requirements and Recommendations for ERCOT System Facilities","6.2.6.2.1(6)","2015-09-25","Other considerations include: (a) Internal bushing current transformers are preferred over external slip-over current transformers;\n(b) 10L800 (C800) class current transformers are preferred for relaying;\n(c) Breakers and free-standing current transformers with four or more sets of current transformers are preferred;\n(d) Over-the-bushing external current transformers can sometimes solve problems when there aren't enough current transformers. Note that there may be an unprotected region between the external current transformer and the bushing current transformer; and\n(e) Shorting type terminal blocks should be provided for all current transformers.","-"]
[250,"Protective Relay Systems","6 Disturbance Monitoring and System Protection, 6.2 System Protective Relaying","6.2.6 Requirements and Recommendations for ERCOT System Facilities","6.2.6.2.2(1)","2015-09-25","Voltage transformers and potential devices associated with protective relay systems shall have adequate steady state and transient characteristics for their intended functions.","RE/\nTSP"]
[251,"Protective Relay Systems","6 Disturbance Monitoring and System Protection, 6.2 System Protective Relaying","6.2.6 Requirements and Recommendations for ERCOT System Facilities","6.2.6.2.2(2)","2015-09-25","Voltage transformers and potential devices shall have adequate volt-ampere capacity to supply the connected burden while maintaining their relay accuracy over their specified primary voltage range.","RE/\nTSP"]
[252,"Protective Relay Systems","6 Disturbance Monitoring and System Protection, 6.2 System Protective Relaying","6.2.6 Requirements and Recommendations for ERCOT System Facilities","6.2.6.2.2(3)","2015-09-25","Usually one set of voltage transformers and /or potential devices with two separate secondary windings per voltage transformer per bus (i.e., single bus substation configuration) or per power system element (i.e., ring bus and breaker-and-a-half substation configurations) is sufficient.  For existing systems, the two protective relay systems may use separate secondary windings or one of the secondary windings may be dedicated to supplying the polarizing potential and the other winding used to supply other protection and monitoring functions.  For all new installations, if the two protective relay systems protecting a zone each require a voltage transformer or potential device input for protection functions, they shall utilize isolated and separate secondary windings unless ERCOT determines that one of the secondary windings must be dedicated to metering applications.","RE/\nTSP"]
[253,"Protective Relay Systems","6 Disturbance Monitoring and System Protection, 6.2 System Protective Relaying","6.2.6 Requirements and Recommendations for ERCOT System Facilities","6.2.6.2.2(4)","2015-09-25","Voltage transformer and potential device secondary wiring shall be grounded at only one point.  ANSI/IEEE C57 recommends grounding at the panel.","RE/\nTSP"]
[254,"Protective Relay Systems","6 Disturbance Monitoring and System Protection, 6.2 System Protective Relaying","6.2.6 Requirements and Recommendations for ERCOT System Facilities","6.2.6.2.2(5)","2015-09-25","Voltage transformer installations shall be designed with due regard to ferroresonance due to capacitance across the interrupter at 138 kV and above.","RE/\nTSP"]
[255,"Protective Relay Systems","6 Disturbance Monitoring and System Protection, 6.2 System Protective Relaying","6.2.6 Requirements and Recommendations for ERCOT System Facilities","6.2.6.2.2(6)","2015-09-25","Other considerations include: (a) Special attention should be given to the physical properties of secondary circuit fuses;\n(b) Voltage transformers and potential devices should be suitable for relaying and SCADA telemetry; and\n(c) Loss of protective system voltage such as a fuse failure should be provided as SCADA alarm input.","RE/\nTSP"]
[256,"Protective Relay Systems","6 Disturbance Monitoring and System Protection, 6.2 System Protective Relaying","6.2.6 Requirements and Recommendations for ERCOT System Facilities","6.2.6.2.3(1)","2015-09-25","DC batteries associated with protective relay systems shall have a high degree of reliability.","RE/\nTSP"]
[257,"Protective Relay Systems","6 Disturbance Monitoring and System Protection, 6.2 System Protective Relaying","6.2.6 Requirements and Recommendations for ERCOT System Facilities","6.2.6.2.3(2)","2015-09-25","Two batteries each with its own charger should be provided at each location.  An acceptable alternative is one battery with two separately protected branches.  The two protective relay systems protecting a zone shall be supplied from the separate batteries or branches.  For transmission facilities at 100 kV and above, two batteries shall be required in locations that remote backup clearing of lines and substation faults is not achieved.  For new upgraded transmission facilities at 200 kV and above with two or more transmission voltage breakers, two batteries each with its own charger, are required.","RE/\nTSP"]
[258,"Protective Relay Systems","6 Disturbance Monitoring and System Protection, 6.2 System Protective Relaying","6.2.6 Requirements and Recommendations for ERCOT System Facilities","6.2.6.2.3(3)","2015-09-25","Each battery shall have sufficient capacity to permit operation of the station, in the event of a loss of its battery charger or the AC supply source, for the period of time necessary to transfer the load to the other battery or to re-establish the supply source.  Each battery and its associated charger shall have sufficient capacity to supply its share of the DC Load of the station.","RE/\nTSP"]
[259,"Protective Relay Systems","6 Disturbance Monitoring and System Protection, 6.2 System Protective Relaying","6.2.6 Requirements and Recommendations for ERCOT System Facilities","6.2.6.2.3(4)","2015-09-25","A fault at the battery terminals can only be interrupted by a mid-bank protective device.  If a mid-bank protective device is not used, then the connections between the battery terminals and the main protective devices shall possess the highest possible degree of reliability.","RE/\nTSP"]
[260,"Protective Relay Systems","6 Disturbance Monitoring and System Protection, 6.2 System Protective Relaying","6.2.6 Requirements and Recommendations for ERCOT System Facilities","6.2.6.2.3(5)","2015-09-25","Battery chargers and all associated circuits shall be protected against short circuits.  All protective devices shall be coordinated to minimize the number of DC circuits interrupted.","RE/\nTSP"]
[261,"Protective Relay Systems","6 Disturbance Monitoring and System Protection, 6.2 System Protective Relaying","6.2.6 Requirements and Recommendations for ERCOT System Facilities","6.2.6.2.3(6)","2015-09-25","The regulation of DC voltage shall be designed such that, under all possible loading conditions, voltage within acceptable limits will be supplied to all devices.","RE/\nTSP"]
[262,"Protective Relay Systems","6 Disturbance Monitoring and System Protection, 6.2 System Protective Relaying","6.2.6 Requirements and Recommendations for ERCOT System Facilities","6.2.6.2.3(7)","2015-09-25","DC systems shall be monitored to detect abnormal voltage levels, both high and low, DC grounds, and loss of AC to the battery chargers.  Loss of DC to relay schemes shall be alarmed.  Also, where possible the loss of AC to the battery chargers and loss of DC should be provided as SCADA alarm inputs.","RE/\nTSP"]
[263,"Protective Relay Systems","6 Disturbance Monitoring and System Protection, 6.2 System Protective Relaying","6.2.6 Requirements and Recommendations for ERCOT System Facilities","6.2.6.2.3(8)","2015-09-25","DC systems shall be designed to minimize AC ripple and voltage transients.","RE/\nTSP"]
[264,"Protective Relay Systems","6 Disturbance Monitoring and System Protection, 6.2 System Protective Relaying","6.2.6 Requirements and Recommendations for ERCOT System Facilities","6.2.6.2.3(9)","2015-09-25","The DC circuit protective devices used shall have published DC interrupting ratings suitable for the required circuit duty.","RE/\nTSP"]
[265,"Protective Relay Systems","6 Disturbance Monitoring and System Protection, 6.2 System Protective Relaying","6.2.6 Requirements and Recommendations for ERCOT System Facilities","6.2.6.2.4(1)","2015-09-25","There should be two sources of station service AC supply, each capable of carrying all the critical loads associated with protective relay systems.","RE/\nTSP"]
[266,"Protective Relay Systems","6 Disturbance Monitoring and System Protection, 6.2 System Protective Relaying","6.2.6 Requirements and Recommendations for ERCOT System Facilities","6.2.6.2.4(2)","2015-09-25","Failure of station service AC supply should be alarmed over SCADA.","RE/\nTSP"]
[267,"Protective Relay Systems","6 Disturbance Monitoring and System Protection, 6.2 System Protective Relaying","6.2.6 Requirements and Recommendations for ERCOT System Facilities","6.2.6.2.5(1)","2015-09-25","Two trip coils, one associated with each protection system, shall be provided for each operating mechanism.  The failure of one coil shall not damage or impair the operation of the other coil.","RE/\nTSP"]
[268,"Protective Relay Systems","6 Disturbance Monitoring and System Protection, 6.2 System Protective Relaying","6.2.6 Requirements and Recommendations for ERCOT System Facilities","6.2.6.2.5(2)","2015-09-25","The design shall be such that the breaker will operate if either both trip coils are energized simultaneously, or either trip coil alone, and verified by tests.","RE/\nTSP"]
[269,"Protective Relay Systems","6 Disturbance Monitoring and System Protection, 6.2 System Protective Relaying","6.2.6 Requirements and Recommendations for ERCOT System Facilities","6.2.6.2.5(3)","2015-09-25","Circuit breaker auxiliary switches used in protection systems should be highly reliable with a positive make-break action and good contact wipe.  Multiplier contacts simulating breaker auxiliary switches should be used with caution in protection systems.","RE/\nTSP"]
[270,"Protective Relay Systems","6 Disturbance Monitoring and System Protection, 6.2 System Protective Relaying","6.2.6 Requirements and Recommendations for ERCOT System Facilities","6.2.6.2.5(4)","2015-09-25","A three-phase and line-to-ground interrupting study to validate or indicate breaker interrupting rating shall be performed.","RE/\nTSP"]
[271,"Protective Relay Systems","6 Disturbance Monitoring and System Protection, 6.2 System Protective Relaying","6.2.6 Requirements and Recommendations for ERCOT System Facilities","6.2.6.2.6(1)","2015-09-25","Where communication channels are required for the protective relay system purposes, the communication facilities shall have a degree of reliability no less than that of the other protective relay system components.  For extra security, the output contacts from two independent channels may be wired in series.","RE/\nTSP"]
[272,"Protective Relay Systems","6 Disturbance Monitoring and System Protection, 6.2 System Protective Relaying","6.2.6 Requirements and Recommendations for ERCOT System Facilities","6.2.6.2.6(2)","2015-09-25","Where communication channels are required in each of the two protective relay systems, the channels shall be separated physically and designed to minimize the risk of both channels being disabled simultaneously by a single contingency.","RE/\nTSP"]
[273,"Protective Relay Systems","6 Disturbance Monitoring and System Protection, 6.2 System Protective Relaying","6.2.6 Requirements and Recommendations for ERCOT System Facilities","6.2.6.2.6(3)","2015-09-25","Communication channels shall be provided with means to verify signal performance.","RE/\nTSP"]
[274,"Protective Relay Systems","6 Disturbance Monitoring and System Protection, 6.2 System Protective Relaying","6.2.6 Requirements and Recommendations for ERCOT System Facilities","6.2.6.2.6(4)","2015-09-25","Other considerations include: (a) Report loss of channel over SCADA;\n(b) Automatic testing of power line carrier (PLC) is desirable to reduce false trips from failure to block; and\n(c) Split up PLC Loads between DC sources so that loss of one fuse does not disable all the carrier sets. If all the carrier sets were to be disabled, then multiple false trips during a fault could result.\n(e) See also Section 8.3.4, TDSP and QSE Supplied Communications.","RE/\nTSP"]
[275,"Protective Relay Systems","6 Disturbance Monitoring and System Protection, 6.2 System Protective Relaying","6.2.6 Requirements and Recommendations for ERCOT System Facilities","6.2.6.2.7(1)","2015-09-25","Control cables, wiring and auxiliary control devices should be such as to assure high reliability with due consideration to published codes and standards, fire hazards, current-carrying capacity, voltage drop, insulation level, mechanical strength, routing, shielding, grounding and environment.","RE/\nTSP"]
[276,"Protective Relay Systems","6 Disturbance Monitoring and System Protection, 6.2 System Protective Relaying","6.2.6 Requirements and Recommendations for ERCOT System Facilities","6.2.6.2.7(2)","2015-09-25","Other considerations include: (a) AC or DC go-and-return functions should be implemented in the same cable to avoid induction loops;\n(b) Individual wires in cables should have colored jackets, not black jackets with a \"color\" printed on the jacket;\n(c) Standardization of the relationship between wire colors and functions is desirable;\n(d) No splice in any wire or cable;\n(e) All cables terminated on terminal blocks; and (f) Shielded cable should be installed in locations where electric fields, magnetic fields, or electromagnetic interference is sufficient to disrupt the reliable operation of the control cable and it cannot be mitigated by other means.","RE/\nTSP"]
[277,"Protective Relay Systems","6 Disturbance Monitoring and System Protection, 6.2 System Protective Relaying","6.2.6 Requirements and Recommendations for ERCOT System Facilities","6.2.6.2.8(1)","2015-09-25","Means shall be employed to maintain environmental conditions that are favorable to the correct performance of protective relay systems.  Particular attention should be given to solid-state equipment installations","RE/\nTSP"]
[278,"Protective Relay Systems","6 Disturbance Monitoring and System Protection, 6.2 System Protective Relaying","6.2.6 Requirements and Recommendations for ERCOT System Facilities","6.2.6.3.1(1)","2015-09-25","Each of the two independent protective relay systems shall detect and initiate action to clear any line fault without undue system disturbance.  Protective relay systems shall operate for line faults so that, if ultimate clearing should be accomplished by a breaker failure scheme, a widespread disturbance will not result.  A protective relay system, which can operate for faults beyond the zone it is designed to protect, shall be selective in time with other protective relay systems, including breaker failure.","TSP"]
[279,"Protective Relay Systems","6 Disturbance Monitoring and System Protection, 6.2 System Protective Relaying","6.2.6 Requirements and Recommendations for ERCOT System Facilities","6.2.6.3.1(2)","2015-09-25","For newly installed transmission line protective relay systems: (a) Fuses shall not be used in the 3Vo polarizing supply for ground relays. (b) Loss-of-potential function shall be used for schemes dependent on voltage for correct operations. SCADA alarms shall be provided for loss-of-potential conditions.\n(c) Dual communication-aided protection over dual communications channels shall be used where dynamic and/or voltage stability studies indicate non-pilot protection operating times are inadequate.","TSP"]
[280,"Protective Relay Systems","6 Disturbance Monitoring and System Protection, 6.2 System Protective Relaying","6.2.6 Requirements and Recommendations for ERCOT System Facilities","6.2.6.3.1(3)","2015-09-25","Transmission line protection should include: (a) One independent protective relay system of phase and ground protection over a communications channel;\n(b) A secondary independent protective relay system of at least two zones of phase protection and at least two zones of ground protection, or ground directional overcurrent relaying (time delay and instantaneous);\n(c) “Ground chain protection” or switch-to-on-fault to recognize and trip for a three-phase fault right at the terminals, in service for a short period of time just as the line is energized, for lines with line side voltage transformers and protection elements dependent on distance measurement;\n(d) Recognition and trip for open conductor is desirable but not required;\n(e) Overload protection is provided by SCADA analog alarms and dispatcher discretion;\n(f) Fault detector relays to supervise phase distance relaying to prevent inadvertent trip due to voltage transformer failure;\n(g) Short lines may require special attention, such as dual primary schemes, etc;\n(h) For transmission facilities with series compensation, dual communication-aided protection should be used. At least one of the two protective relay systems should be differential type; and\n(i) For any transmission line that has dual communication-aided protection systems, at least one of the two protective relay schemes should be of a differential type in any location where an adequate communications infrastructure exists or is planned and there are no mitigating circumstances (e.g. tapped loads).","TSP"]
[281,"Protective Relay Systems","6 Disturbance Monitoring and System Protection, 6.2 System Protective Relaying","6.2.6 Requirements and Recommendations for ERCOT System Facilities","6.2.6.3.2(1)","2015-09-25","Each zone in a station shall be protected by two independent protective relay systems.  For zones not protected by line protection, at least one of the two protective relay systems shall be a differential type.","TSP"]
[282,"Protective Relay Systems","6 Disturbance Monitoring and System Protection, 6.2 System Protective Relaying","6.2.6 Requirements and Recommendations for ERCOT System Facilities","6.2.6.3.2(2)","2015-09-25","Protective relay systems shall be designed to operate for station faults so that, if ultimate clearing is accomplished by a breaker failure scheme, a widespread disturbance will not result.  Protective relay systems shall be designed to operate properly for the anticipated range of currents.","TSP"]
[283,"Protective Relay Systems","6 Disturbance Monitoring and System Protection, 6.2 System Protective Relaying","6.2.6 Requirements and Recommendations for ERCOT System Facilities","6.2.6.3.2(3)","2015-09-25","Station protection should consist of: (a) Bus differential or bus overcurrent protection of all buses;\n(b) All transformers protected by transformer differential, transformer overcurrent, or fuses (for small transformers). Note that ferroresonance is possible for fused transformers above 69 kV; and\n(c) Sudden pressure relay protection for transformer main tanks and transformer tap changer compartments.\n(d) For transformers with conservator tanks, gas accumulator relay (also known as a Buchholz relay) protection for the transformer main tanks and transformer tap changer compartments are preferred in addition to sudden pressure relay protection.","TSP"]
[284,"Protective Relay Systems","6 Disturbance Monitoring and System Protection, 6.2 System Protective Relaying","6.2.6 Requirements and Recommendations for ERCOT System Facilities","6.2.6.3.3(1)","2015-09-25","Breaker failure protection should be provided to trip all necessary local and remote breakers in the event that a breaker fails to clear a fault.","RE/\nTSP"]
[285,"Protective Relay Systems","6 Disturbance Monitoring and System Protection, 6.2 System Protective Relaying","6.2.6 Requirements and Recommendations for ERCOT System Facilities","6.2.6.3.3(2)","2015-09-25","The breaker failure protection should be initiated by each of the protection systems that trip that breaker.  It is not necessary to duplicate the breaker failure protection itself.","RE/\nTSP"]
[286,"Protective Relay Systems","6 Disturbance Monitoring and System Protection, 6.2 System Protective Relaying","6.2.6 Requirements and Recommendations for ERCOT System Facilities","6.2.6.3.3(3)","2015-09-25","Induction cup, solid state, or microprocessor based current detectors shall be used to determine if a breaker has failed to interrupt.","RE/\nTSP"]
[287,"Protective Relay Systems","6 Disturbance Monitoring and System Protection, 6.2 System Protective Relaying","6.2.6 Requirements and Recommendations for ERCOT System Facilities","6.2.6.3.3(4)","2015-09-25","Plunger or clapper type overcurrent relays are not recommended as breaker failure fault detectors.","RE/\nTSP"]
[288,"Protective Relay Systems","6 Disturbance Monitoring and System Protection, 6.2 System Protective Relaying","6.2.6 Requirements and Recommendations for ERCOT System Facilities","6.2.6.3.3(5)","2015-09-25","For all newly installed or upgraded relay systems, a cross-tripping means such that each protective relay system can operate both circuit breaker trip coils without compromising the separation of the DC supplies is recommended.","RE/\nTSP"]
[289,"Protective Relay Systems","6 Disturbance Monitoring and System Protection, 6.2 System Protective Relaying","6.2.6 Requirements and Recommendations for ERCOT System Facilities","6.2.6.3.3(6)","2015-09-25","Breaker failure schemes shall be designed such that if fault clearing should be accomplished through operation of the breaker failure scheme, an uncontrolled separation and collapse of the ERCOT System will not result.  Breaker failure schemes shall be designed to be selective in time with other protective relay systems and/or particular system requirements.","RE/\nTSP"]
[290,"Protective Relay Systems","6 Disturbance Monitoring and System Protection, 6.2 System Protective Relaying","6.2.6 Requirements and Recommendations for ERCOT System Facilities","6.2.6.3.4(1)","2015-09-25","Generator faults shall be detected by more than one protective relay system.  These may include faults in the generator or generator leads, unit transformer, and unit-connected station service transformer.","RE"]
[291,"Protective Relay Systems","6 Disturbance Monitoring and System Protection, 6.2 System Protective Relaying","6.2.6 Requirements and Recommendations for ERCOT System Facilities","6.2.6.3.4(2)","2015-09-25","Generators shall be protected to keep damage to the equipment and subsequent outage time to a minimum.  In view of the special consideration of generator unit protection, the following are some of the conditions that should be detected by the protection systems: It is recognized that the overall protection of a generator will also involve non-electrical considerations.  These have not been included as part of this criteria. (a) Unbalanced phase currents;\n(b) Loss of excitation;\n(c) Over-excitation;\n(d) Field ground;\n(e) Inadvertent energization or reverse power;\n(f) Uncleared system faults; and\n(g) Off-frequency.","RE"]
[292,"Protective Relay Systems","6 Disturbance Monitoring and System Protection, 6.2 System Protective Relaying","6.2.6 Requirements and Recommendations for ERCOT System Facilities","6.2.6.3.4(3)","2015-09-25","The apparatus shall be protected when the generator is starting up or shutting down as well as running at normal speed; this may require additional relays, as the normal relays may not function satisfactorily at low frequencies.","RE"]
[293,"Protective Relay Systems","6 Disturbance Monitoring and System Protection, 6.2 System Protective Relaying","6.2.6 Requirements and Recommendations for ERCOT System Facilities","6.2.6.3.4(4)","2015-09-25","A generator shall not be tripped for a system swing condition except when that particular generator is out of step with the remainder of the system.  This does not apply to protective relay systems designed to trip the generator as part of an overall plan to maintain stability of the ERCOT System.","RE"]
[294,"Protective Relay Systems","6 Disturbance Monitoring and System Protection, 6.2 System Protective Relaying","6.2.6 Requirements and Recommendations for ERCOT System Facilities","6.2.6.3.4(5)","2015-09-25","The loss of excitation relay shall be set with due regard to the performance of the excitation system.","RE"]
[295,"Protective Relay Systems","6 Disturbance Monitoring and System Protection, 6.2 System Protective Relaying","6.2.6 Requirements and Recommendations for ERCOT System Facilities","6.2.6.3.4(6)","2015-09-25","In the case of a generator bus fault or a primary transmission system relay failure, the generator protective relaying may clear the generator independent of the operation of any transmission protective relaying.","RE"]
[296,"Protective Relay Systems","6 Disturbance Monitoring and System Protection, 6.2 System Protective Relaying","6.2.6 Requirements and Recommendations for ERCOT System Facilities","6.2.6.3.4(7)","2015-09-25","If requested by ERCOT, within 30 days of ERCOT’s request, Generation Resources shall provide ERCOT with the operating characteristics of any generating unit’s equipment protective relay systems or controls that may respond to temporary excursions in voltage with actions that could lead to tripping of the generating unit.","RE"]
[297,"Protective Relay Systems","6 Disturbance Monitoring and System Protection, 6.2 System Protective Relaying","6.2.6 Requirements and Recommendations for ERCOT System Facilities","6.2.6.3.5(1)","2015-09-25","Automatic Under-Frequency Load Shedding (UFLS) systems are classified as protective relay systems.  The maintenance requirements, discussed in Section 6.2.5, Maintenance and Testing Requirements for ERCOT System Facilities, apply to UFLS protection systems as well.","TSP"]
[298,"Protective Relay Systems","6 Disturbance Monitoring and System Protection, 6.2 System Protective Relaying","6.2.6 Requirements and Recommendations for ERCOT System Facilities","6.2.6.3.5(2)","2015-09-25","Automatic UFLS systems are generally located on equipment operated below 60 kV; however, they have a direct effect on the operation of the ERCOT System during major emergencies.","-"]
[299,"Protective Relay Systems","6 Disturbance Monitoring and System Protection, 6.2 System Protective Relaying","6.2.6 Requirements and Recommendations for ERCOT System Facilities","6.2.6.3.5(3)","2015-09-25","The criteria for the operation of these protection systems are detailed in Section 2.6, Requirements for Under-Frequency Relaying.","-"]
[300,"Protective Relay Systems","6 Disturbance Monitoring and System Protection, 6.2 System Protective Relaying","6.2.6 Requirements and Recommendations for ERCOT System Facilities","6.2.6.3.5(4)","2015-09-25","Automatic UFLS protection systems need not be duplicated.","-"]
[301,"Protective Relay Systems","6 Disturbance Monitoring and System Protection, 6.2 System Protective Relaying","6.2.6 Requirements and Recommendations for ERCOT System Facilities","6.2.6.3.5(5)","2015-09-25","Generator and turbine under-frequency protection systems shall be coordinated with Section 2.6.","RE"]
[302,"Protective Relay Systems","6 Disturbance Monitoring and System Protection, 6.2 System Protective Relaying","6.2.6 Requirements and Recommendations for ERCOT System Facilities","6.2.6.3.5(6)","2015-09-25","On pressurized water reactor steam supply units where under-frequency related protection systems are installed to detect loss of coolant flow condition, these protection systems shall be coordinated with the automatic UFLS program.","-","Applies to nuclear power plants only"]
[303,"Protective Relay Systems","6 Disturbance Monitoring and System Protection, 6.2 System Protective Relaying","6.2.6 Requirements and Recommendations for ERCOT System Facilities","6.2.6.3.5(7)","2015-09-25","Automatic Load restoration for an under-frequency Load shedding operation is not currently utilized in ERCOT.","-"]
[304,"Protective Relay Systems","6 Disturbance Monitoring and System Protection, 6.2 System Protective Relaying","6.2.6 Requirements and Recommendations for ERCOT System Facilities","6.2.6.3.6(1)","2015-09-25","Automatic UVLS systems are classified as protective relay systems. The maintenance requirements, discussed in Section 6.2.5, Maintenance and Testing Requirements for ERCOT System Facilities, apply to UVLS protection systems as well.","TSP"]
[305,"Protective Relay Systems","6 Disturbance Monitoring and System Protection, 6.2 System Protective Relaying","6.2.6 Requirements and Recommendations for ERCOT System Facilities","6.2.6.3.6(2)","2015-09-25","The requirement for under-voltage relaying shall be determined by system studies performed/administered by ERCOT designated working groups or equipment owners. The system studies should indicate the following:\n(a) Amount of Load to be shed to restore voltage to minimum acceptable level or higher;\n(b) The minimum and maximum time delay allowed before automatically shedding Load;\n(c) The voltage level(s) at which to initiate automatic relay operation; and\n(d) The location(s) for effectively applying UVLS protection systems.","TSP"]
[306,"Protective Relay Systems","6 Disturbance Monitoring and System Protection, 6.2 System Protective Relaying","6.2.6 Requirements and Recommendations for ERCOT System Facilities","6.2.6.3.6(3)","2015-09-25","Automatic UVLS protection systems need not be duplicated.","TSP"]
[307,"Protective Relay Systems","6 Disturbance Monitoring and System Protection, 6.2 System Protective Relaying","6.2.6 Requirements and Recommendations for ERCOT System Facilities","6.2.6.3.6(4)","2015-09-25","Analyses shall be performed on UVLS schemes by working groups and/or equipment owners as assigned by ERCOT to demonstrate that they are expected to act before generators trip Off-Line due to the protective relay requirements, as specified in paragraph (3)(a) of Section 2.9, Voltage Ride-Through Requirements for Generation Resources. A specific exemption from this analysis requirement may be provided by the ROS.","TSP"]
[308,"Protective Relay Systems","6 Disturbance Monitoring and System Protection, 6.2 System Protective Relaying","6.2.6 Requirements and Recommendations for ERCOT System Facilities","6.2.6.3.6(5)","2015-09-25","Under-voltage protection systems shall be designed to coordinate with other protective devices and control schemes during momentary voltage dips, sustained faults, low voltages caused by stalled motors, motor starting, etc.","TSP"]
[309,"Protective Relay Systems","6 Disturbance Monitoring and System Protection, 6.2 System Protective Relaying","6.2.6 Requirements and Recommendations for ERCOT System Facilities","6.2.6.3.6(6)","2015-09-25","Automatic Load restoration for an UVLS operation is not currently utilized in ERCOT.","TSP"]
[310,"Protective Relay Systems","6 Disturbance Monitoring and System Protection, 6.2 System Protective Relaying","6.2.6 Requirements and Recommendations for ERCOT System Facilities","6.2.6.3.6(7)","2015-09-25","The UVLS scheme shall be designed to ensure reliable operation and to prevent false tripping.","TSP"]
[311,"Protective Relay Systems","6 Disturbance Monitoring and System Protection, 6.2 System Protective Relaying","6.2.6 Requirements and Recommendations for ERCOT System Facilities","6.2.6.3.6(8)","2015-09-25","In addition, protective relaying for Generation Resources must be designed to meet Voltage Ride-Through (VRT) criteria as detailed in Section 2.9.","TSP"]
[312,"Protective Relay Systems","6 Disturbance Monitoring and System Protection, 6.2 System Protective Relaying","6.2.6 Requirements and Recommendations for ERCOT System Facilities","6.2.6.3.6(9)","2015-09-25","Restoration of any Load shed by UVLS shall be coordinated with ERCOT.","TSP"]
[313,"WAN","7 Telemetry and Communication, 7.1 ERCOT Wide Area Network","7.1.2 QSE and TSP Responsibilities","7.1.2(a)","2015-09-25","TSPs and QSEs whose facilities connect to the ERCOT WAN are required to sign the ERCOT Private Wide Area Network (WAN) Agreement which governs installation, operation, and maintenance of the WAN hardware.  Appropriate WAN documents can be obtained by contacting the ERCOT Account Manager.","QSE/\nTSP"]
[314,"WAN","7 Telemetry and Communication, 7.1 ERCOT Wide Area Network","7.1.2 QSE and TSP Responsibilities","7.1.2(b)","2015-09-25","ERCOT WAN participants shall provide physical security systems compliant with the applicable Critical Infrastructure Protection (CIP) requirement of the North American Electric Reliability Corporation (NERC) Reliability Standards.","QSE/\nTSP"]
[315,"WAN","7 Telemetry and Communication, 7.1 ERCOT Wide Area Network","7.1.2 QSE and TSP Responsibilities","7.1.2(c)","2015-09-25","Any TSP or QSE facility, whether primary or backup, will be required to connect directly to the ERCOT WAN including connectivity to both the MPLS and point-to-point networks.  ERCOT will work with each Market Participant to determine the most appropriate WAN demarcation point.  Criteria for determining demarcation points include:  \n(i) Reliability;\n(ii) Location of data centers;\n(iii) Control centers;\n(iv) Disaster recovery facilities;\n(v) Energy and Market Management System (EMMS) equipment;\n(vi) ICCP equipment; and\n(vii) Private branch exchange (PBX) equipment installation.","QSE/\nTSP"]
[316,"WAN","7 Telemetry and Communication, 7.1 ERCOT Wide Area Network","7.1.2 QSE and TSP Responsibilities","7.1.2(d)","2015-09-25","ERCOT is responsible for the reliable transport of critical market communications and will make the ultimate determination of the demarcation point location.","-"]
[317,"WAN","7 Telemetry and Communication, 7.1 ERCOT Wide Area Network","7.1.2 QSE and TSP Responsibilities","7.1.2(e)","2015-09-25","Market Participants that serve both TSP and QSE functions at one location will only require one ERCOT WAN connection as defined in Section 7.1, ERCOT Wide Area Network, at that location.","QSE/\nTSP"]
[318,"WAN","7 Telemetry and Communication, 7.1 ERCOT Wide Area Network","7.1.2 QSE and TSP Responsibilities","7.1.2(f)","2015-09-25","If a TSP and QSE share a centralized PBX, separate OPX circuits will be terminated for each participant.","QSE/\nTSP"]
[319,"WAN","7 Telemetry and Communication, 7.1 ERCOT Wide Area Network","7.1.2 QSE and TSP Responsibilities","7.1.2(g)","2015-09-25","Each Market Participant is required to extend the ERCOT OPX and Hotline voice circuits into its 24x7 operations desk.  ERCOT will deliver the OPX and Hotline to a channel bank provided by the Market Participant.  The OPX and Hotline voice circuits are transported on separate DS0 channels.  In the event a Market Participant designated to represent other Entities through an agency agreement approved by ERCOT, each Entity represented must have dedicated OPX circuits.  In these cases, a single Hotline button will be used for the Market Participant and all of the represented Entities.  It is the Market Participant’s responsibility to deliver the Hotline and the OPX to the Market Participant’s 24x7 operations desk in a manner that reasonably assures continuous communication with ERCOT and is not affected by PBX features such as automatic transfer or roll to voice mail.  Also, a touchtone keypad is required for the Hotline to be able to provide an acknowledged receipt.  The demarcation point for all voice circuits is the Market Participant’s channel bank.","QSE/\nTSP"]
[320,"WAN","7 Telemetry and Communication, 7.1 ERCOT Wide Area Network","7.1.2 QSE and TSP Responsibilities","7.1.2(h)","2015-09-25","Each TSP and QSE must provide internal facilities and communications to collect and furnish data and voice signals to the ERCOT WAN as required by the Protocols.  For TSPs these include, but may not be limited to, voice communications, ICCP, and Supervisory Control and Data Acquisition (SCADA) for substations and other Transmission Facilities.  For QSEs these include, but may not be limited to, voice communications, ICCP, and SCADA for Resources.","QSE/\nTSP"]
[321,"WAN","7 Telemetry and Communication, 7.1 ERCOT Wide Area Network","7.1.2 QSE and TSP Responsibilities","7.1.2(i)","2015-09-25","ERCOT WAN participants shall provide adequate physical facilities to support the ERCOT WAN communications equipment.  The physical facilities and communications equipment requirements include the following: (i) Provide an analog business phone line or PBX analog extension for troubleshooting and maintenance of equipment;\n(ii) Provide a height of 24” of rack space in a 19” wide rack;\n(iii) Provide two separate uninterruptible power supply single-phase 115 VAC 20 amp circuits, each with four receptacles in the 19” rack listed above;\n(iv) Provide building wiring from circuit termination to equipment rack;\n(v) Within 24-hours notice, provide ERCOT employees or contractors access to the communication facility;\n(vi) Within one-hour notice, provide emergency access to the facility to ERCOT employees or contractors;\n(vii) Provide onsite personnel to escort ERCOT employees or contractors;\n(viii) Provide a firewall or router, located at the Market Participant site, for the network address translation of internal Market Participant addresses to external addresses on the ERCOT LAN; (ix) Provide connectivity from Market Participant firewall or router to ERCOT LAN located at Market Participant site. Market Participants are responsible for their own security through this connection;\n(x) Provide a channel bank with at least one T1 interface and four Foreign Exchange Station (FXS) ports. Connect FXS (e.g. PBX, key system) to the appropriate equipment. On the digital T1 stream, levels for voice are zero dpm for transmit and receive;\n(xi) Dual cable entrances to Market Participant, connecting to different Telco Central Offices is highly recommended; and\n(xii) Provide ERCOT with internal IP addressing scheme as needed for network design. This will be kept confidential.","QSE/\nTSP"]
[322,"WAN","7 Telemetry and Communication, 7.1 ERCOT Wide Area Network","7.1.2 QSE and TSP Responsibilities","7.1.2(j)","2015-09-25","QSEs and TSPs shall supply, implement, and maintain all data and voice communication facilities required to fulfill the obligations set forth in these Operating Guides.","QSE/\nTSP"]
[323,"WAN","7 Telemetry and Communication, 7.1 ERCOT Wide Area Network","7.1.3 Joint Responsibilities (Maintenance and Restoration)","7.1.3","2015-09-25","Joint responsibility of ERCOT WAN-connected Market Participants and ERCOT include the following:\n(a) Coordinate maintenance and restoration activities so its reliability is not compromised;\n(b) All primary and back-up circuits shall be tested annually or as otherwise requested by ERCOT for end-to-end performance;\n(c) ERCOT will specify test procedures for hotline and any back-up or alternate path voice circuits;\n(d) A Market Participant must be able to transmit and receive test voice signals. The test equipment must be capable of transmitting, receiving, and measuring frequency and decibel level. This will allow ERCOT and the Market Participant to isolate circuit and equipment problems for quick resolution and restoration of voice communication; and\n(e) Scheduled maintenance of any WAN hardware/software shall be coordinated between ERCOT and the affected Market Participant. The Market Participant shall provide reasonable outage windows for ERCOT support personnel to upgrade and repair equipment.","QSE/\nTSP"]
[324,"Telemetry","7 Telemetry and Communication, 7.2 ERCOT ICCP Interface","7.2 ERCOT ICCP Interface",7.2,"2015-09-25","The Inter-Control Center Communication Protocol (ICCP) over the ERCOT Wide Area Network (WAN) provides the Real-Time telemetry data from Market Participant computers, computer networks, or other devices.  Market Participants providing the data using an ICCP link must format their data and coordinate installation according to the ERCOT WAN Agreement found in the ERCOT Nodal ICCP Communication Handbook. The ERCOT Nodal ICCP Communication Handbook provides additional details and shall be used in conjunction with the Protocols and Operating Guides to facilitate the communication needs of ERCOT and Market Participants to effectively manage system and market requirements.  Updates to the ERCOT Nodal ICCP Communication Handbook shall be approved by the Technical Advisory Committee (TAC).","QSE/\nTSP"]
[325,"Telemetry","7 Telemetry and Communication, 7.2 ERCOT ICCP Interface","7.2.1 Quality Codes","7.2.1","2015-09-25","Status and analog telemetry data provided to ERCOT shall have the associated quality codes and associated attributes found in the ERCOT Nodal ICCP Communication Handbook.  ICCP quality codes to be provided to ERCOT by the Market Participant and to the Market Participants by ERCOT shall follow the standards set in the ERCOT Nodal ICCP Communication Handbook.","QSE/\nTSP"]
[326,"Telemetry","7 Telemetry and Communication, 7.2 ERCOT ICCP Interface","7.2.2 Metric of Availability","7.2.2(1)","2015-09-25","ICCP links must achieve availability as prescribed by the Telemetry Standards posted on the Market Information System (MIS) Public Area.  Availability metrics shall establish a process to coordinate downtime for ICCP links and database maintenance.","QSE/\nTSP"]
[327,"Telemetry","7 Telemetry and Communication, 7.2 ERCOT ICCP Interface","7.2.2 Metric of Availability","7.2.2(2)","2015-09-25","ICCP links shall use fully redundant data communication from the Qualified Scheduling Entity (QSE) and Transmission Service Provider (TSP) control systems to the ERCOT System as required by the Protocols.","QSE/\nTSP"]
[328,"Telemetry","7 Telemetry and Communication, 7.3 Telemetry","7.3 Telemetry","7.3(1)","2015-09-25","Qualified Scheduling Entities (QSEs) and Transmission Service Providers (TSPs) required to supply Real-Time telemetry data to ERCOT shall use an Inter-Control Center Communications Protocol (ICCP) interface through the ERCOT Wide Area Network (WAN).  TSPs and QSEs shall also receive signals from ERCOT over the ICCP interface.","QSE/\nTSP"]
[329,"Telemetry","7 Telemetry and Communication, 7.3 Telemetry","7.3 Telemetry","7.3(2)","2015-09-25","Each QSE and/or TSP shall continuously provide to ERCOT the telemetry data quantities that they are responsible for in the format described in the ERCOT Nodal ICCP Communications Handbook.  The frequency of updates, means of communication to ERCOT, and data format for each point provided by each Entity shall follow the specifications in the ERCOT ICCP Nodal Communications Handbook.  At the frequency specified, each update cycle shall provide current operating data for all points being monitored.  Design accuracy and availability of data points delivered to ERCOT shall satisfy the requirements of the Protocols and the Telemetry Standards.","QSE/\nTSP"]
[330,"Telemetry","7 Telemetry and Communication, 7.3 Telemetry","7.3 Telemetry","7.3(3)","2015-09-25","QSEs, Resources and TSPs are required to provide power operation data to ERCOT according to the Protocols and the ERCOT ICCP Nodal Communications Handbook.","QSE/\nRE/\nTSP"]
[331,"Telemetry","7 Telemetry and Communication, 7.3 Telemetry","7.3 Telemetry","7.3(4)","2015-09-25","The nomenclature format of data (i.e. structure of the ICCP Object Name) shall follow the standards in the ERCOT Nodal ICCP Communication Handbook.","QSE/\nTSP"]
[332,"Telemetry","7 Telemetry and Communication, 7.3 Telemetry","7.3.3 Data from QSEs and TSPs to ERCOT","7.3.3(1)","2015-09-25","Each TSP and QSE shall provide telemetered measurements on modeled Transmission Elements as required by the Protocols and the ERCOT Nodal ICCP Communications Handbook.","TSP"]
[333,"Telemetry","7 Telemetry and Communication, 7.3 Telemetry","7.3.3 Data from QSEs and TSPs to ERCOT","7.3.3(2)","2015-09-25","QSEs and TSPs shall provide Real-Time monitoring of power system quantities to ERCOT as defined in the Protocols and the ERCOT Nodal ICCP Communications Handbook.  ERCOT shall work with TSPs and QSEs to determine the required data using the methodology presented in the Protocols.  Transmission Element status and analog measurements that the TSPs and QSEs define in the Network Operations Model shall, at a minimum, be provided to ERCOT.  Ultimately, it is the responsibility of the TSPs and QSEs to provide all data requested by ERCOT. ","QSE/\nTSP"]
[334,"Telemetry","7 Telemetry and Communication, 7.3 Telemetry","7.3.3 Data from QSEs and TSPs to ERCOT","7.3.3(3)","2015-09-25","Real-Time telemetry data from QSEs used to supply power or Ancillary Services shall be integrated by ERCOT and checked against settlement meter values on a monthly basis.","-"]
[335,"Telemetry","7 Telemetry and Communication, 7.3 Telemetry","7.3.3 Data from QSEs and TSPs to ERCOT","7.3.3(4)","2015-09-25","Each QSE and TSP shall notify ERCOT as soon as practicable when telemetry will not be available or is unreliable for operational purposes.  The report, as outlined in Section 9.2.2, Real-Time Data Monitor, will contain unavailability data associated with Planned Outages of RTUs.","QSE/\nTSP"]
[336,"Telemetry","7 Telemetry and Communication, 7.3 Telemetry","7.3.3 Data from QSEs and TSPs to ERCOT","7.3.3(5)","2015-09-25","Each QSE and TSP shall notify ERCOT as soon as practicable when telemetry is returned to normal state.","QSE/\nTSP"]
[337,"Telemetry","7 Telemetry and Communication, 7.3 Telemetry","7.3.3 Data from QSEs and TSPs to ERCOT","7.3.3.1(1)","2015-09-25","A TSP that is responsible for providing Weather Zone tie-line measurement data to ERCOT is required to establish a backup to the primary source. ","-"]
[338,"Telemetry","7 Telemetry and Communication, 7.3 Telemetry","7.3.3 Data from QSEs and TSPs to ERCOT","7.3.3.1(2)","2015-09-25","TSPs having an Energy Management System (EMS) with a native ICCP application capable of four second periodic data set transfers with minimum 300 points per data set, and hot standby backup ICCP servers with automatic fail-over capability, shall provide an additional ICCP association across the ERCOT WAN for the transfer of Weather Zone tie line measurements.  ICCP nodes should exist at primary and backup facilities.","TSP"]
[339,"Telemetry","7 Telemetry and Communication, 7.3 Telemetry","7.3.4 TSP and QSE Telemetry Restoration","7.3.4","2015-09-25","Real-Time telemetry data shall be restored using criteria and procedures as established by the Telemetry Standards.","QSE/\nTSP"]
[340,"Telemetry","7 Telemetry and Communication, 7.3 Telemetry","7.3.5 General Telemetry Performance Criterion","7.3.5","2015-09-25","All Real-Time telemetry as required by the Protocols shall meet the State Estimator Standards and the Telemetry Standards.","QSE/\nTSP"]
[341,"Telemetry","7 Telemetry and Communication, 7.4 Calibration and Testing of Telemetry Responsibilities","7.4 Calibration and Testing of Telemetry Responsibilities",7.4,"2015-09-25","It is the responsibility of the owner of telemetry equipment to ensure that calibration, testing and other routine maintenance of equipment is performed consistently with the provisions of the Protocols, Telemetry Standards, and Good Utility Practice.","QSE/\nTSP"]
[342,"Telemetry","7 Telemetry and Communication, 7.5 Competitive Renewable Energy Zone Circuits and Stations","7.5 Competitive Renewable Energy Zone Circuits and Stations",7.5,"2015-09-25","For each new Competitive Renewable Energy Zone transmission line, listed below, an associated communications path should be established to provide a high degree of dependability, security, and immunity from interference.  Additionally this communications path should support high bandwidth (155 mb/s or greater), low latency (unidirectional delay no greater that one millisecond per 100 miles), and be engineered to meet 99.999% availability with capacity reserved for regulated utility protection, monitoring and control.  Redundant communication paths are required unless this necessitates retrofitting existing facilities.","-"]
[343,"Black Start","8 Attachment A, Detailed Black Start Information","Considerations for System Restoration",8,"2015-09-25","This attachment and Section 8, Attachment E, Black Start Plan Template, provide the minimum information necessary to be used in conjunction with the ERCOT Black Start Plan. Each Transmission Operator (TO), Qualified Scheduling Entity (QSE) representing Black Start Resources, and Black Start Generation Resource should use this information for technical reference, development of Black Start plans, and training of personnel.","TSP/\nQSE"]
[344,"Black Start","8 Attachment A, Detailed Black Start Information","Considerations for System Restoration, Determining System Status","8.1DSS(1)","2015-09-25","If a Generation Resource or Transmission Operator (TO) loses voltage on all busses and incoming transmission lines, then operators should assume there is a Partial Blackout or Blackout. If possible, the TO shall also immediately notify ERCOT. Contracted Black Start Resources shall implement Black Start procedures and establish contact with their TOs. Other Generation Resources shall contact their QSEs and then wait for instructions from the TOs. If possible, ERCOT will update TOs and QSEs concerning the status of the ERCOT System by use of the ERCOT Hotline or other available backup communications.","TSP/\nQSE"]
[345,"Black Start","8 Attachment A, Detailed Black Start Information","Considerations for System Restoration, Determining System Status","8.1DSS(2)","2015-09-25","It is expected that if communication with ERCOT is not possible, TOs will evaluate system conditions and proceed independently with their Black Start plans.","TSP"]
[346,"Black Start","8 Attachment A, Detailed Black Start Information","Considerations for System Restoration, Determining System Status","8.1DSS(3)","2015-09-25","Priority should be given to determining the status of nuclear Generation Resources and switchyards in order to re-establish offsite power supply."]
[347,"Black Start","8 Attachment A, Detailed Black Start Information","Considerations for System Restoration, Determining System Status","8.1DSS(4)","2015-09-25","System status conditions to be surveyed include but are not limited to:\n(a) Areas of the system that are de-energized;\n(b) Areas of the system that are functioning;\n(c) Amount of generating reserve available in functioning areas;\n(d) Generation Resource availability and time required to restart;\n(e) Status of transmission breakers and sectionalizing equipment along Cranking Paths and Synchronization Corridors, and at Generation Resources;\n(f) Status of transmission breakers and sectionalizing equipment at Direct Current Ties (DC Ties);\n(g) Status of fuel supply from external suppliers;\n(h) Under-frequency relay operation; and\n(i) Relay flags associated with circuits tripped by protective relays."]
[348,"Black Start","8 Attachment A, Detailed Black Start Information","Considerations for System Restoration, Verifying Communication","8.2VC(1)","2015-09-25","Reliable communications will be the key to a safe and timely restoration following a Partial Blackout or Blackout. As part of the initial assessment after a Partial Blackout or Blackout, communication facilities shall be tested and verified. It is possible, especially in case of a Blackout, that communications with out-of-state QSEs representing Generation Resources may not be possible. It is therefore critical that TOs and Generation Resources located within their transmission system be able to communicate directly during these times.\n(a) The ERCOT System Operators shall:\n(i) Verify or establish communication paths with TOs;\n(ii) Verify or establish communications paths with QSEs representing Generation Resources;\n(iii) Verify integrity of ERCOT Hotline;\n(iv) Periodically disseminate information to TOs and QSEs; and\n(v) Direct implementation of Black Start plan in areas of a Partial Blackout or Blackout.\n(b) The TO operators shall:\n(i) Contact ERCOT in order to report status;\n(ii) Establish contact with contracted Black Start Resources and their QSE(s);\n(iii) Initiate Black Start plan; and\n(iv) Establish communication paths with other Generation Resources necessary to the restoration of the ERCOT System.\n(c) The QSE representing Generation Resources shall:\n(i) Contact ERCOT to report status of Generation Resources within the ERCOT Region;\n(ii) Assist TOs as required; and\n(iii) Ensure Generation Resources are prepared to receive and follow instructions directly from the TO to which they are connected.\n(d) The Black Start Resources shall:\n(i) Isolate their Black Start Resource from the ERCOT Transmission Grid;\n(ii) Establish communications with their TOs;\n(iii) If no communications with the TOs are available, establish communications with ERCOT; and\n(iv) Start Black Start Resource and request load interconnection from TO. The Black Start Resource shall not connect to the ERCOT Transmission Grid without specific instructions to do so from either ERCOT or the designated TO responsible for the Black Start Resource.","TSP/\nQSE"]
[349,"Black Start","8 Attachment A, Detailed Black Start Information","Considerations for System Restoration, Verifying Communication","8.2VC(2)","2015-09-25","Should problems be encountered with any of the primary communication facilities, back-up facilities shall be deployed and appropriate personnel notified."]
[350,"Black Start","8 Attachment A, Detailed Black Start Information","Considerations for System Restoration, Verifying Communication","8.2VC(3)","2015-09-25","Communications will be vital to an orderly recovery. To keep communication facilities available, operating personnel shall ensure that three-part communication is used at all times."]
[351,"Black Start","8 Attachment A, Detailed Black Start Information","Considerations for System Restoration, Preparing for System Restoration","8.3PSR(1)","2015-09-25","Orderly restoration will usually require sectionalizing the de-energized parts of the ERCOT System into smaller, manageable blocks before they are energized."]
[352,"Black Start","8 Attachment A, Detailed Black Start Information","Considerations for System Restoration, Preparing for System Restoration","8.3PSR(2)","2015-09-25","The sectionalizing process should usually address but is not limited to the following objectives:\n(a) Priority shall be given to restoring offsite power to nuclear Generation Resources;\n(b) Ensure that blocks of load to be energized are sized to minimize the problems of cold load pickup; and\n(c) Operators shall verify that their switching orders as well as any standing emergency switching orders have been completed."]
[353,"Black Start","8 Attachment A, Detailed Black Start Information","Considerations for System Restoration, Bringing Up Generation Resources","8.3BUGR(1)","2015-09-25","First priority shall be given to preventing damage to Generation Resource equipment and to restoring offsite power to nuclear Generation Resources. Secondly, attention shall be given to preparing generators that can come On-Line most rapidly. All operators should remember that large steam Generation Resources will need an outlet for the minimum generation requirement soon after coming On-Line."]
[354,"Black Start","8 Attachment A, Detailed Black Start Information","Considerations for System Restoration, Bringing Up Generation Resources","8.3BUGR(2)","2015-09-25","A Black Start Resource has procedures to begin the process of bringing its generators back up when the switchyard and all incoming transmission lines are de-energized. The Generation Resource shall not synchronize or pick up load without communicating with the TO to which it is connected."]
[355,"Black Start","8 Attachment A, Detailed Black Start Information","Considerations for System Restoration, Bringing Up Generation Resources","8.3BUGR(3)","2015-09-25","A Generation Resource without Black Start capability shall have a written procedure in place to begin preparing the Generation Resource to be energized from an external line.  When the TO has energized the Generation Resource switchyard it will contact the Generation Resource directly and the QSE as soon as practical. The TO will coordinate starting of large motors, bringing Generation Resources On-Line, and synchronizing Generation Resources with the rest of the ERCOT Transmission Grid.","TSP"]
[356,"Black Start","8 Attachment A, Detailed Black Start Information","Considerations for System Restoration, Bringing Up Generation Resources","8.3BUGR(4)","2015-09-25","Generation Resource operators will be controlling system frequency during the recovery period and must keep it between trip points for generators’ under-frequency and over-frequency relays. It is preferable to use the generators with lowest under-speed trip for initial restoration."]
[357,"Black Start","8 Attachment A, Detailed Black Start Information","Considerations for System Restoration, Bringing Up Generation Resources","8.3BUGR(5)","2015-09-25","Automatic Voltage Regulators (AVRs) should be placed in service as soon as practical after bringing Generators On-Line and should remain in-service to improve machine stability."]
[358,"Black Start","8 Attachment A, Detailed Black Start Information","Considerations for System Restoration, Bringing Up Generation Resources","8.3BUGR(6)","2015-09-25","As soon as possible, after bringing a Generator On-Line, automatic Governor controls should be placed in the \"automatic\" position to ensure instantaneous Governor response to changes in frequency."]
[359,"Black Start","8 Attachment A, Detailed Black Start Information","Considerations for System Restoration, Picking Up Lines","8.4PLI(1)","2015-09-25","Ties between nearby Generation Resources shall be established as soon as possible. Priority shall be given to restoring at least one circuit to nuclear Generation Resources to provide offsite power for safe shutdown."]
[360,"Black Start","8 Attachment A, Detailed Black Start Information","Considerations for System Restoration, Picking Up Lines","8.4PLI(2)","2015-09-25","A line should be energized from the strongest electrical source. Switching devices on all substation or transmission capacitor banks along the line should be open unless needed for voltage control."]
[361,"Black Start","8 Attachment A, Detailed Black Start Information","Considerations for System Restoration, Picking Up Lines","8.4PLI(4)","2015-09-25","Caution should be exercised in the use of 345 kV transmission system. Because of high values of line charging, energizing one of these circuits with little or no load can produce excessive voltage and can damage substation equipment (Note: 345kV lines supply approximately 1 MVAr/mile of line charging while 138kV lines supply approximately 0.1 MVAr/mile)."]
[362,"Black Start","8 Attachment A, Detailed Black Start Information","Considerations for System Restoration, Picking Up Lines","8.4PLI(5)","2015-09-25","Operators in TO control rooms should exercise care when energizing transmission lines, so that they do not close a breaker into a fault. Operators in TO control rooms should be aware of any transmission lines that tripped while the system was going down and have field personnel check the relay flags before energizing the line.","TSP"]
[363,"Black Start","8 Attachment A, Detailed Black Start Information","Considerations for System Restoration, Picking Up Lines","8.4PLI(6)","2015-09-25","Ferroresonance may occur while energizing a line or while picking up a transformer from an unloaded line. Operators in TO control rooms should be on guard for unusually high and sustained voltages during such switching. 345 kV lines may be highly susceptible to this phenomenon and their use should be minimized in the early stages of restoration.","TSP"]
[364,"Black Start","8 Attachment A, Detailed Black Start Information","Considerations for System Restoration, Picking Up Load","8.5PLO(1)","2015-09-25","In general, 69 kV and 138 kV lines along with radial 345 kV lines to autotransformers may be used to energize load. When energizing a 345 kV circuit and autotransformer combination, both the line and transformer should be energized at the same time to avoid the problem of excessive voltage. The more lightly loaded a generator is, the less load increment it can safely pick up."]
[365,"Black Start","8 Attachment A, Detailed Black Start Information","Considerations for System Restoration, Picking Up Load","8.5PLO(3)","2015-09-25","Priority shall be given to restoring offsite power to nuclear Generation Resources. As critical and priority loads are restored, consideration should be given to restoration of loads controlled by under-frequency relays."]
[366,"Black Start","8 Attachment A, Detailed Black Start Information","Considerations for System Restoration, Picking Up Load","8.5PLO(4)","2015-09-25","When energizing load, the operators in TO control rooms must be in close contact with the Generation Resource in order that excessive load is not picked up on a generator in one operation. Generally, the operators in TO control rooms should pick up no more than 5% of the total generating capability in an Island in a single step. If load is picked up in blocks that are too large, then the inrush current may operate over current relays that trip the loads off the ERCOT System again. There should be sufficient time between switching operations to allow the generator to recover from the sudden increase in load.","TSP"]
[367,"Black Start","8 Attachment A, Detailed Black Start Information","Considerations for System Restoration, Picking Up Load","8.5PLO(5)","2015-09-25","The operators in TO control rooms should exercise caution when loading a single generator to more than 50% of its control range until additional generators have been brought back On-Line in that Island. Generally, no generator should be loaded to more than 80% of its available capability until ERCOT System conditions return to normal.","TSP"]
[368,"Black Start","8 Attachment A, Detailed Black Start Information","Considerations for System Restoration, Picking Up Load","8.5PLO(6)","2015-09-25","Since each Generation Resource may be operating independently, Generation Resource operators will have to monitor and adjust their generators voltage and frequency. Frequency should be kept above 59.8 Hz and as close as possible to 60 Hz. Voltage should be kept as close as possible to normal schedules. As more generators are brought up and more load is added, the voltage and frequency will tend to stabilize."]
[369,"Black Start","8 Attachment A, Detailed Black Start Information","Considerations for System Restoration, Picking Up Load","8.5PLO(8)","2015-09-25","The operators in TO control rooms should exercise caution when re-energizing capacitor banks after load has been picked up. The change in system voltage that occurs will be much larger than normal because of the reduced system fault duty.","TSP"]
[370,"Black Start","8 Attachment A, Detailed Black Start Information","Considerations for System Restoration, Synchronizing Between Islands","8.6SBI(1)","2015-09-25","TOs shall have field personnel in area Islands to check breakers at each end of a line being used to synchronize between Islands to ensure they are open regardless of supervisory indication. The area with the largest amount of generation On-Line shall energize the line first.","TSP"]
[371,"Black Start","8 Attachment A, Detailed Black Start Information","Considerations for System Restoration, Synchronizing Between Islands","8.6SBI(2)","2015-09-25","Where available, field personnel shall synchronize and close the tie breakers at the synchronization point. If there is a sufficient frequency difference that the Islands cannot be synchronized, the Island with the least generation On-Line shall adjust its frequency to achieve synchronization.","TSP"]
[372,"Black Start","8 Attachment A, Detailed Black Start Information","Considerations for System Restoration, Synchronizing Between Islands","8.6SBI(3)","2015-09-25","When synchronizing, both the phase angle across the breaker, and the voltage on each side of the breaker shall be measured. If possible, the phase rotation should be stopped and the phase angle reduced to 10° or less before closing the breakers.","TSP"]
[373,"Black Start","8 Attachment A, Detailed Black Start Information","Considerations for System Restoration, Synchronizing Between Islands","8.6SBI(4)","2015-09-25","In general, lines should not be loaded to more than 50% of thermal rating until multiple tie paths have been established. Additional ties should be closed as soon as possible.","TSP"]
[374,"Black Start","8 Attachment A, Detailed Black Start Information","Considerations for System Restoration, Considterations For Balck Start Testing","8.8BST(2)","2015-09-25","The owner or operator of each Black Start Resource shall demonstrate through the testing procedures outlined in Protocol Section 8.1.1.2.1.5, System Black Start Capability Qualification and Testing, that the Black Start Resource can perform its intended functions as required in the ERCOT Black Start Plan. ERCOT may also order random simulation or testing of Black Start capabilities. Documentation of the analysis shall be provided to NERC or the Texas Reliability Entity (Texas RE) upon request as required by the NERC Reliability Standards."]
[375,"Black Start","8 Attachment A, Detailed Black Start Information","Considerations for System Restoration, Criteria for ERCOT and Transmission Operator Black Start Plans","8.9BSP(3)","2015-09-25","TO’s Black Start plans shall include sections on the Black Start Purpose, Scope, Roles and Responsibilities, Strategies, Priorities, Operations, Communication, and Contingency plans and shall follow the format outlined in Appendix 8E."]
[376,"Monitoring","9 Monitoring Programs","9.1.2 Reactive Testing For Generation Resources","9.1.2(1)","2015-09-25","In addition to the requirements in the Protocols and applicable North American Electric Reliability Corporation (NERC) Reliability Standards, SPSs shall also meet the following requirements:\n(a) Unit name; \n(b) QSE; \n(c) Date;\n(d) Time;\n(e) Tested generation real power capability;\n(f) Reported time; and\n(g) Corrected Unit Reactive Limit (CURL) and Unit Reactive Limit (URL).","QSE"]
[377,"Monitoring","9 Monitoring Programs","9.1.2 Reactive Testing For Generation Resources","9.1.2(2)","2015-09-25","ERCOT shall produce reports annually which describe when the last lagging reactive capability test took place, what the MW and Mega Volt-Ampere Reactive (MVAr) outputs were during the test period, how long the output was held, and a minimum of four MW/MVAr pairs describing the CURL of the unit and any limiting conditions that created the need for a CURL. This data shall be provided by the QSE to ERCOT when reactive testing indicates a change in unit reactive capability and at a minimum of once every two years.","QSE"]
[378,"Monitoring","9 Monitoring Programs","9.1.8 Qualified Staffing Requirement","9.1.8","2015-09-25","A QSE shall maintain a continuously operating scheduling center staffed with qualified personnel with the authority to commit and bind the QSE. ERCOT shall report to the Texas Reliability Entity (Texas RE), instances of suspected non-performance.","QSE"]
[379,"Monitoring","9 Monitoring Programs","9.3.9 Voltage and Reactive Control Performance Monitoring","9.3.9(2)","2015-09-25","Transmission owners shall provide switching plans for automatically controlled reactors, capacitors, and other reactive controlled sources to ERCOT. For manually switched reactive devices, the transmission owner shall provide its guidelines for the operation of these devices. These plans and guidelines shall be posted annually to the MIS Secure Area and must be provided in accordance with the NOMCR or other prescribed process.","TSP"]
[380,"Monitoring","9 Monitoring Programs","9.4.2 Annula Black Start Plan Receipt Confirmation Report","9.4.2","2015-09-25","ERCOT shall produce annual reports containing record(s) showing if and when a Black Start plan was last received at ERCOT. The report should include the name of Resources participating in Black Start Service (BSS) and the Transmission Operator (TO) name, as well as the date the Black Start plan was received. TOs shall provide an updated Black Start plan to ERCOT as required by paragraph (2)(a) of Section 4.6.4, Responsibilities, and when the Black Start plan changed."]
[381,"SPS","11 Constraint Management Plans and Special Protection Systems, 11.2 Special Protection System","11.2 Special Protection System","11.2(2)","2015-09-25","In addition to the requirements in the Protocols and applicable North American Electric Reliability Corporation (NERC) Reliability Standards, SPSs shall also meet the following requirements: (a) The SPS owner shall coordinate the design and implementation of the SPS with the owners and operators of Facilities included in the SPS, including but not limited to Generation Resources, Transmission Service Providers (TSPs) and Direct Current Ties (DC Ties);\n(b) The SPS shall be automatically armed when appropriate;\n(c) The SPS shall not operate unnecessarily. To avoid unnecessary SPS operation, the SPS owner may provide a Real-Time status indication to the owner of any Generation Resource controlled by the SPS to show when the flow on one or more of the SPS monitored Facilities exceeds 90% of the flow necessary to arm the SPS. The cost necessary to provide such status indication shall be the responsibility of the SPS owner;\n(d) The status indication of any automatic or manual arming/activation or operation of the SPS shall be provided as Supervisory Control and Data Acquisition (SCADA) alarm inputs to the owners of any Facility controlled by the SPS;\n(e) When an SPS is removed from service, the SPS owner or its Designated Agent shall immediately notify ERCOT;\n(f) When an SPS is returned to service, the SPS owner or its Designated Agent shall immediately notify ERCOT. ERCOT shall modify its reliability constraints to recognize the availability of the SPS;\n(g) The SPS owner shall telemeter the status indication of the following items by SCADA to ERCOT for incorporation into ERCOT systems:\n(i) Any automatic or manual arming/activation or operation of the SPS;\n(ii) The in-service/out-of-service status of the SPS; and\n(iii) Any additional related telemetry that already exists pertinent to the monitoring of the SPS (e.g. status indication of communications links between associated SPS equipment and the owner’s control center, arming limits of associated SPS equipment).\n(h) The TSP may receive telemetry for a Resource Entity owned SPS through ERCOT or through the SPS owner, at the option of the TSP. The SPS owner, at its own cost, must provide telemetry for Resource Entity owned SPSs to the TSP upon request.","-"]
[382,"SPS","11 Constraint Management Plans and Special Protection Systems, 11.2 Special Protection System","11.2 Special Protection System","11.2(4)","2015-09-25","The owners of an existing, modified, or proposed SPS shall submit documentation of the SPS to ERCOT for review and compilation into an ERCOT SPS database.  The documentation shall detail the design, operation, functional testing, and coordination of the SPS with other protection and control systems. (b) The review of a proposed SPS shall be completed before the SPS is placed in service, unless ERCOT specifically determines that exemption of the proposed SPS from the review completion requirement is warranted. The timing of placing the SPS into service must be coordinated with and approved by ERCOT. The implementation schedule must be confirmed through submission of a Network Operations Model Change Request (NOMCR) to ERCOT.\n(c) Existing SPSs that have already undergone at least one review shall remain in service during any subsequent review. Modifications to existing SPSs may be implemented upon approval by ERCOT.\n(d) The process and schedule for placing an SPS into service must be consistent with documented ERCOT Procedures. The schedule must be coordinated among ERCOT and the owners of the Facility controlled by the SPS, and shall provide sufficient time to perform any necessary testing prior to its being placed in service. (f) If deficiencies are identified by ERCOT or other parties’ comments, the SPS owner shall either submit an amended SPS proposal or withdraw the SPS proposal. The amended SPS proposal shall undergo the review process specified in item (e) above until the identified deficiencies have been resolved to the satisfaction of ERCOT.","-"]
[383,"SPS","11 Constraint Management Plans and Special Protection Systems, 11.2 Special Protection System","11.2.1 Reporting of SPS Operations","11.2.1(1)","2015-09-25","SPS owners shall notify ERCOT of all SPS operations.  Documentation of SPS failures or misoperations shall be provided to ERCOT using the Relay Misoperation Report form on the ERCOT website.  The SPS owner shall conduct an analysis of all SPS operations, misoperations, and failures.  If deficiencies are identified, a plan to correct the deficiencies shall be developed by the SPS owner subject to the approval of ERCOT and implemented by the SPS owner. ","-"]
[384,"SPS","11 Constraint Management Plans and Special Protection Systems, 11.2 Special Protection System","11.2.1 Reporting of SPS Operations","11.2.1(2)","2015-09-25","ERCOT shall report all SPS operations and misoperations to the Texas Reliability Entity (Texas RE) for review.  SPS arming or activation that ramps generation back is not considered an operation or misoperation with respect to reporting requirements to the Texas RE.  An operation and misoperation of an SPS with respect to reporting requirements to the Texas RE occurs when changes to the transmission system occur, including, but not limited to circuit breaker operation.  Owners of SPSs will provide a monthly report to ERCOT by the 15th of each month describing each instance an SPS armed/activated and reset during the previous month.  The report will include the date and time of arming/activation and reset.  ERCOT shall consolidate the monthly reports and forward to the Texas RE.","-"]
[385,"SPS","11 Constraint Management Plans and Special Protection Systems, 11.2 Special Protection System","11.2.1 Reporting of SPS Operations","11.2.1(3)","2015-09-25","If an SPS which removes generation from service operates more than two times within a six month period and the operations are not a direct result of an ERCOT System disturbance or a contingency operation, ERCOT may require the Generation Resource owner(s) to decrease the available capability on the affected Generation Resource(s). The amount of available capacity to be decreased shall be determined by ERCOT. The decreased available capacity on the Generation Resource(s) shall remain until the Generation Resource owner(s) provides documentation that demonstrates the Generation Resource(s) can properly control output in a pre-contingency or normal ERCOT System condition."]
[386,"SPS","11 Constraint Management Plans and Special Protection Systems, 11.2 Special Protection System","11.2.1 Reporting of SPS Operations","11.2.1(4)","2015-09-25","For each SPS, the owner shall either identify a preferred exit strategy or explain why no exit strategy is needed to ERCOT.  This shall take place according to a timetable documented in ERCOT Procedures and posted on the MIS Secure Area.  Once an exit strategy is complete and a SPS is no longer needed, the owner of an existing SPS shall notify ERCOT, whenever the SPS is to be permanently disabled, and shall do so according to a timetable coordinated with and approved by ERCOT and the owners of all Facilities controlled by the SPS.","-"]