One Minute Summary - TPL-001-5

Transmission System Planning Performance Requirements 

Purpose:

• Establish transmission system planning performance requirements 

• Ensuring the reliable operation of a Bulk Electric System (BES) under various system conditions and contingencies 

Functional Entity:

• Planning Coordinator 

• Transmission Planner 

Requirement R1

• Maintain system models with MOD-032 standard

Requirement R2

Annual planning assessment:

• Use current or qualified past studies

• Document assumptions

• Steady State Analyses 

• Short Circuit Analyses

• Stability Analyses 

Requirement R2 2.1 Near-Term Steady State Analyses 

• Assessed annually and supported by current or qualified past studies

• Qualifying studies need to include the following conditions: 

System Peak Load (2.1.1): 

• Maximum load that the system experiences for either the first or second year, and for the fifth year of the study period

System Off-Peak Load (2.1.2)

• Lowest load at least one of the five years in the study period.

Sensitivity Analysis (2.1.3)

By varying one or more of the conditions, the study should analyze how the system responds.

• Real and reactive forecasted load

• Expected transfers

• Expected in-service dates of new or modified transmission facilities

• Reactive resource capability

• Generation additions, retirements, or other dispatch scenarios

• Controllable loads and demand side management

• Duration or timing of known transmission outages

Impact of Known Outages (2.1.4): 

• Impact of planned outages of generation or transmission facilities 

• The known outages selected for the assessment must adhere to a documented outage coordination procedure or technical rationale

• Should not be limited by the duration of the outage and should include the worst-case scenarios. 

• P0 and P1 category with peak and off-peak load

Impact of Spare Equipment Strategy (2.1.5):

• Major transmission equipment being unavailable, and such equipment has a lead time of a year or more (e.g. Transformer)

• P0, P1, and P2 category with equipment unavailability 

Requirement R2 2.2 Long-Term Steady State Analyses 

• Assessed annually and supported by current or qualified past studies

• Expected System peak Load conditions for one of the years in the Long-Term Transmission Planning Horizon

Requirement R2 2.3 Near-Term Short Circuit Analyses

• Assessed annually and supported by current or qualified past studies

• Determine whether circuit breakers have interrupting capability for Faults

Requirement R2 2.4 Near-Term Stability Analyses 

• Assessed annually and supported by current or qualified past studies

System Peak Load (2.4.1): 

• Maximum load that the system experiences for one of the five years.

• Load model with expected dynamic load behavior, Considering the behavior of induction motor Loads.

• Aggregate System Load model of overall dynamic behavior of the Load

System Off-Peak Load (2.4.2): 

• Lowest load that the system experiences for one of the five years.

Sensitivity Analysis (2.4.3): 

By varying one or more of the conditions, the study should analyze how the system responds.

• Load level, load forecast, or dynamic load model assumptions

• Expected transfers

• Expected in-service dates of new or modified transmission facilities

• Reactive resource capability

• Generation additions, retirements, or other dispatch scenarios

Impact of Known Outages (2.4.4):

• Impact of planned outages of generation or transmission facilities 

• The known outages selected for the assessment must adhere to a documented outage coordination procedure or technical rationale

• Should not be limited by the duration of the outage and should include the worst-case scenarios 

• P1 category with peak and off-peak load must include, at a minimum, known outages that are expected to produce more severe system impacts

Impact of Spare Equipment Strategy(2.4.5):

• Major transmission equipment being unavailable, and such equipment has a lead time of a year or more (e.g. Transformer)

• P1, and P2 category with equipment unavailability which is expected to impact more severe

Requirement R2 2.5 Long-Term Stability Analyses 

• Assessed annually and supported by current or qualified past studies

  • Impact of generation additions or changes

Requirement R2 2.6 Past studies' requirement 

• Past steady state, short circuit, or Stability analysis are used to support 

• Five calendar years old or less

• No material changes with supporting documents

Requirement R2 2.7 Corrective Action Plan for System inability 

• Addressing how the inability system to meet performance requirements (Table 1)

• Can be revised in subsequent Planning Assessments

List System Deficiencies and Actions (2.7.1):

Examples:

• Installing, modifying, retiring, or removing transmission and generation facilities and associated equipment

• Installing, modifying, or removing Protection Systems or Remedial Action Schemes

• Installing or modifying automatic generation tripping in response to single or multiple contingencies to mitigate Stability performance violations

• Installing or modifying manual and automatic generation runback/tripping in response to single or multiple contingencies to mitigate steady state performance violations.

• Using Operating Procedures specifying their duration as part of the Corrective Action Plan

• Using rate applications, Demand-Side Management (DSM), new technologies, or other initiatives

Address Multiple Sensitivity Studies (2.7.2):

• ○ actions to address performance deficiencies identified in multiple sensitivity studies or 

• OR provide a rationale explaining why actions are not necessary. 

Handling Situations Beyond Control (2.7.3):

•  When situations are beyond the control and prevent the implementation of a Corrective Action Plan

• Actions to the use:  

  • Non-Consequential Load Loss and 

  • curtailment of Firm Transmission Service 

• Document that they are taking 

  • Actions to resolve the situation and must document 

  • The situation causing the problem 

  • Alternatives evaluated

  • The use of Non-Consequential Load Loss or curtailment of Firm Transmission Service

Review in Subsequent Planning Assessments (2.7.4):

• The Corrective Action Plan must be reviewed in subsequent annual Planning Assessments 

Requirement R2 2.8 Corrective Action Plan for interrupting duty in short circuit analysis 

• List System Deficiencies and Actions

• The Corrective Action Plan must be reviewed in subsequent annual Planning Assessments 

Requirement R3 Requirement for Near-Term and Long-Term Steady State Analyses  R2 2.1 and R2 2.2

Planning Events Studies (3.1): 

• Studies need to be performed for planning events in Requirement R3, Part 3.4.

Extreme Events Studies (3.2):

• Studies should assess the impact of extreme events identified in Requirement R3, Part 3.5. 

• If cascading due to extreme events are concluded, an evaluation is needed to reduce or mitigate the consequences 

Contingency Analysis (3.3):

• Simulate the removal of all relay elements and other automatic controls 

  • • • • Include the tripping of generators when generator voltage is less than minimum voltage or ride-through voltage

        • Include the tripping of Transmission elements where relay loadability limits are exceeded

• Simulate the expected automatic operation for steady-state control, such as: 

  • Phase-shifting transformers

  • Load tap changing transformers 

  • Switched capacitors and inductors

Identification of Severe Planning Events in Requirement R3, Part 3.1 (3.4):

• Planning events produce more severe system impacts

• Create list of contingencies 

• Coordination between the Planning Coordinator and Transmission Planner with adjacent entities 

Identification of Severe Extreme Events in Requirement R3, Part 3.2 (3.5):

• Extreme events produce more severe system impacts

• Create list of contingencies 

• Coordination between the Planning Coordinator and Transmission Planner with adjacent entities 

Requirement R4 Requirement for Near-Term and Long-Term Stability Analyses  R2 2.4 and R2 2.5

Planning Events Studies (4.1): 

• Studies need to be performed for planning events in Requirement R4, Part 4.4.

P1 category

• Generating unit should pull out of synchronism.

P2 through P7 categories

• Generating unit pulls out of synchronism.

• Resulting apparent impedance swings should not result in the tripping of any transmission system 

P1 through P7 categories

• Power oscillations must exhibit acceptable damping 

Extreme Events Studies (4.2):

• Studies should assess the impact of extreme events identified in Requirement R3, Part 3.5. 

• If  cascading due to extreme events are concluded, an evaluation is needed to reduce or mitigate the consequences 

Contingency Analysis (4.3):

• Simulate the removal of all relay elements and other automatic controls 

  • Include successful and unsuccessful high-speed (less than one second) reclosing into a fault.

  • Include the tripping of generators when generator voltage is less than minimum voltage or  ride-through voltage

  • Include the tripping of Transmission elements where transient swings cause it

• Simulate the expected automatic operation for dynamic control, such as 

  • Generation exciter control and power system stabilizers, 

  • Static VAR compensators 

  • Power flow controllers

  • DC Transmission controllers

Identification of Severe Planning Events in Requirement R4, Part 4.1 (4.4):

• Planning events produce more severe system impacts

• Create list of contingencies 

• Coordination between the Planning Coordinator and Transmission Planner with adjacent entities 

Identification of Severe Extreme Events in Requirement R4, Part 4.2 (4.5):

• Extreme events produce more severe system impacts

• Create list of contingencies 

• Coordination between the Planning Coordinator and Transmission Planner with adjacent entities 

Requirement R5 Establish voltage criteria 

• Steady state voltage levels 

• Post-Contingency voltage deviations 

• Transient voltage response 

  • Minimum low voltage level 

  • Maximum duration for which transient voltages can be below that level.

Requirement R6 Document the criteria or methodology

Includes identify system instability for conditions such as:

• Cascading 

• Voltage instability

• Uncontrolled islanding

Requirement R7 Determine each entity's responsibilities 

Requirement R8 Sharing Planning assessment results

• Share with adjacent Planning Coordinators and adjacent Transmission Planners within 90 calendar days of completing

• Within 30 days of a request of Planning assessment results