SIXTH FLOOR, 900 HOWE STREET, BOX 250 VANCOUVER, BC V6Z 2N3 CANADA web site: http://www.bcuc.com BRITISH COLUMBIA UTILITIES COMMISSION ORDER NUMBER G‐162‐11 TELEPHONE: (604) 660‐4700 BC TOLL FREE: 1‐800‐663‐1385 FACSIMILE: (604) 660‐1102 BEFORE: IN THE MATTER OF the Utilities Commission Act, R.S.B.C. 1996, Chapter 473 and A Mandatory Reliability Standards Assessment Report No. 3 by British Columbia Hydro and Power Authority and the Determination of Reliability Standards for Adoption in British Columbia L.F. Kelsey, Commissioner D. Morton, Commissioner September 1, 2011 O R D E R WHEREAS: A. Pursuant to section 125.2(2) of the Utilities Commission Act (the Act), the British Columbia Utilities Commission (the Commission) has exclusive jurisdiction to determine whether a “reliability standard” as defined in the Act is in the public interest and should be adopted in British Columbia; B. Ministerial Order MO39 dated February 22, 2009, made a Mandatory Reliability Standards Regulation which prescribes the parties that are subject to reliability standards adopted under section 125.2(6) of the Act; C. In order to facilitate the Commission’s consideration of reliability standards, British Columbia Hydro and Power Authority (BC Hydro) is required under section 125.2(3) of the Act to review each reliability standard and provide the Commission with a report assessing: (a) any adverse impact of the reliability standard on the reliability of electricity transmission for British Columbia if the reliability standard were adopted; (b) the suitability of the reliability standard for British Columbia; (c) the potential cost of the reliability standard if it were adopted; (d) any other matter prescribed by regulation or identified by order of the Commission; D. On March 3, 2011, BC Hydro filed a report (Mandatory Reliability Standards Assessment Report No. 3) pursuant to section 125.2(3) of the Act assessing one new reliability standard (PRC‐023‐1) and revisions to 19 existing reliability standards developed by the North American Electric Reliability Corporation (NERC) and the Western Electricity Coordinating Council (WECC). The 19 existing reliability standards were adopted in British Columbia by the Commission under Orders G‐67‐09 and G‐167‐10; E. BC Hydro concluded that one new reliability standard and all revisions, 27 in total, to the 19 existing standards are suitable for adoption in British Columbia; F. Pursuant to section 125.2(5)(a) of the Act, the Commission posted the Mandatory Reliability Standards Assessment Report No. 3 on its website at www.bcuc.com and by Order G‐66‐11 dated March 31, 2011, directed BC Hydro to publish a Notice of Mandatory Reliability Standards Assessment Report No. 3 and Process for Public Comments, and established the Regulatory Timetable for comments; …/2 BRITISH COLUMBIA UTILITIES COMMISSION 2 ORDER NUMBER G‐162‐11 G. The Commission received no comments to the Report; H. The Commission has reviewed and considered the Mandatory Reliability Standards Assessment Report No. 3 and the reliability standards assessed in it. The Commission determines that the standards assessed in BC Hydro’s Mandatory Reliability Standards Assessment Report No. 3 are in the public interest and should be adopted in British Columbia to maintain or achieve consistency with other jurisdictions that have adopted the reliability standards, subject to the terms of this Order; I. The Commission considers that it is appropriate to provide an effective date for entities to come into compliance with the reliability standards to be adopted in this Order; J. Following the issuance of Order G‐151‐11, approving Mandatory Reliability Standards Assessment Report No. 3, the Commission was advised that the clauses requiring the rescinding of certain standards posed a potential problem for the Administrator’s auditing procedures. In addition, BC Hydro‘s Mandatory Reliability Standards Assessment Report No. 3 recommended adopting the April 20, 2010 NERC Glossary. This glossary however was superseded by the May 24, 2011 updated glossary (Order G‐151‐11 adopted the May 24, 2010 Glossary in error). This glossary has now also been updated by an August 4, 2011 Glossary which is currently used by NERC and WECC for the administration of all adopted standards. K. The Commission therefore determines that Order G‐151‐11 should be replaced by this Order. NOW THEREFORE the Commission orders as follows: 1. Order G‐151‐11 is rescinded as of the date of that Order, and replaced with this Order. 2. The Effective Date of each of the standards adopted in this Order is the latter of October 30, 2011 or that which is stated in a standard adopted by this Order. 3. The Commission adopts Version 3 of the eight CIP standards listed in the table found in Attachment A to this Order. These standards’ Effective Dates shall be as provided in Directive 2. Version 2 of the eight CIP standards, although adopted, shall not become effective, being superseded by Version 3. 4. Version 1 of the eight CIP standards adopted by this order remains in effect until the Effective Dates of Version 3 of those standards. 5. The Commission adopts, subject to Directive 2, the 11 other revised standards that are listed in the table found in Attachment A to this Order under the heading “Subsequent Version of Standard.” 6. The Commission adopts the new standard PRC‐023‐1. 7. Attachment C to this Order contains the text of the standards adopted by this Order. 8. The Commission adopts the NERC Glossary of Terms Used in Reliability Standards dated August 4, 2011, which defines terms employed in the reliability standards, and which is posted to the WECC and NERC websites, to be effective as of the date of this Order and is attached as Attachment D. .../3 BRITISH COLUMBIA
UTILITIES COMMISSION
ORDER
NUMBER
G-162-11
3
9.
The Commission directs that individual requirements within reliability standards that incorporate by reference
reliability standards that have not been adopted by the Commission are of no force or effect.
10. The Commission adopts the Compliance Provisions, as defined in the Rules of Procedure for Reliability Standards in
British Columbia, that accompany each of the adopted British Columbia reliability standards, in the form directed by
the Commission to be posted in the WECC website, as amended from time to time.
11. As a result of this Order and Orders G-67-09 and G-167-10, the standards listed in the table found in Attachment B to
this Order are the reliability standards adopted in British Columbia as of the date of this Order.
;;...(.,
DATED at the City of Vancouver, in the Province of British Columbia, this
/
;;:~
L.F. Kelsey
Commissioner
Attachments
Order/G-162-11_MRS Assessment Report #3-Revised Standards
day of October 2011.
"-.-/'....-- '--"
,,"'----
ATTACHMENT A to Order G‐162‐11 Page 1 of 1 Revised Standards Prior Version of Standard Subsequent Version of Standard Standard Name CIP‐002‐1 CIP‐002‐2 Cyber Security – Critical Cyber Asset Identification CIP‐002‐2 CIP‐002‐3 Cyber Security – Critical Cyber Asset Identification CIP‐003‐1 CIP‐003‐2 Cyber Security – Security Management Controls CIP‐003‐2 CIP‐003‐3 Cyber Security – Security management Controls CIP‐004‐1 CIP‐004‐2 Cyber Security – Personnel and Training CIP‐004‐2 CIP‐004‐3 Cyber Security – Personnel and Training CIP‐005‐1 CIP‐005‐2 Cyber Security – Electronic Security Perimeter(s) CIP‐005‐2 CIP‐005‐3 Cyber Security – Electronic Security Perimeter(s) CIP‐006‐1 CIP‐006‐2c Cyber Security – Physical Security of Critical Cyber Assets CIP‐006‐2c CIP‐006‐3c Cyber Security – Physical Security of Critical Cyber Assets CIP‐007‐1 CIP‐007‐2a Cyber Security – Systems Security Management CIP‐007‐2a CIP‐007‐3 Cyber Security – Systems Security Management CIP‐008‐1 CIP‐008‐2 Cyber Security – Incident Reporting and Response Planning CIP‐008‐2 CIP‐008‐3 Cyber Security – Incident Reporting and Response Planning CIP‐009‐1 CIP‐009‐2 Cyber Security – Recovery Plans for Critical Cyber Assets CIP‐009‐2 CIP‐009‐3 Cyber Security – Recovery Plans for Critical Cyber Assets FAC‐010‐2 FAC‐010‐2.1 System Operating Limits Methodology for the Planning Horizon INT‐005‐2 INT‐005‐3 Interchange Authority Distributes Arranged Interchange INT‐006‐2 INT‐006‐3 Response to Interchange Authority INT‐008‐2 INT‐008‐3 Interchange Authority Distributes Status IRO‐006‐4 IRO‐006‐4.1 Reliability Coordination‐Transmission Loading Relief MOD‐021‐0 MOD‐021‐0.1 Documentation of the Accounting Methodology for the Effects of Demand‐Side management in Demand and Energy Forecasts PER‐001‐0 PER‐001‐0.1 Operating Personnel Responsibility and Authority TOP‐002‐2 TOP‐002‐2a Normal Operations Planning TPL‐002‐0 TPL‐002‐0a System Performance Following Loss of a Single Bulk Electric System Element (Category B) TPL‐003‐0 TPL‐003‐0a System Performance Following Loss of a Single Bulk Electric System Element (Category C) VAR‐002‐1.1a VAR‐002‐1.1b Generator Operation for Maintaining Network Voltage Schedules ATTACHMENT B to Order G‐162‐11 Page 1 of 5 Approved Standards for B.C.
(Standards shaded in grey are the standards assessed in BC Hydro’s Assessment Report No. 3)
Standard Standard Name BAL‐001‐01a Real Power Balancing Control Performance
G‐167‐10 BAL‐002‐0 Disturbance Control Performance
G‐67‐09 BAL‐003‐0.1b Frequency Response and Bias
G‐167‐10 BAL‐004‐0 Time Error Correction
G‐67‐09 BAL‐004‐WECC‐01 Automatic Time Error Correction
G‐167‐10 BAL‐005‐0.1b Automatic Generation Control
G‐167‐10 BAL‐006‐1.1 Inadvertent Interchange
G‐167‐10 BAL‐STD‐002‐1 Operating Reserves
G‐67‐09 CIP‐001‐1 Sabotage Reporting
G‐67‐09 CIP‐002‐1 Cyber Security – Critical Cyber Asset Identification G‐67‐09 CIP‐002‐1 Cyber Security – Critical Cyber Asset Identification G‐67‐09 CIP‐002‐2 CIP‐002‐3 Cyber Security – Critical Cyber Asset Identification Cyber Security – Critical Cyber Asset Identification
G‐67‐09 G‐162‐11 CIP‐003‐1 Cyber Security – Security Management Controls G‐67‐09 CIP‐003‐2 CIP‐003‐3 Cyber Security – Security management Controls Cyber Security – Security Management Controls
G‐67‐09 G‐162‐11 CIP‐004‐1 Cyber Security – Personnel and Training G‐67‐09 CIP‐004‐2 CIP‐004‐3 Cyber Security – Personnel and Training Cyber Security – Personnel and Training
G‐67‐09 G‐162‐11 CIP‐005‐1 Cyber Security – Electronic Security Perimeter(s) G‐67‐09 CIP‐005‐2 CIP‐005‐3 Cyber Security – Electronic Security Perimeter(s) Cyber Security – Electronic Security Perimeter(s)
G‐67‐09 G‐162‐11 CIP‐006‐1 Cyber Security – Physical Security of Critical Cyber Assets G‐67‐09 CIP‐006‐2c CIP‐006‐3c Cyber Security – Physical Security of Critical Cyber Assets Cyber Security – Physical Security of Critical Cyber Assets
G‐67‐09 G‐162‐11 CIP‐007‐1 Cyber Security – Systems Security Management G‐67‐09 CIP‐007‐2a CIP‐007‐3 Cyber Security – Systems Security Management Cyber Security – Systems Security Management
G‐67‐09 CIP‐008‐1 CIP‐008‐2 CIP‐008‐3 Cyber Security – Incident Reporting and Response Planning Cyber Security – Incident Reporting and Response Planning Cyber Security – Incident Reporting and Response Planning BCUC Order Adopting
G‐162‐11 G‐67‐09 G‐67‐09 G‐162‐11 CIP‐009‐1 Cyber Security – Recovery Plans for Critical Cyber Assets G‐67‐09 CIP‐009‐2 CIP‐009‐3 Cyber Security – Recovery Plans for Critical Cyber Assets Cyber Security – Recovery Plans for Critical Cyber Assets
G‐67‐09 G‐162‐11 COM‐001‐1.1 Telecommunications
G‐167‐10 COM‐002‐2 Communication and Coordination
G‐67‐09 ATTACHMENT B to Order G‐162‐11 Page 2 of 5 Standard Standard Name EOP‐001‐0 Emergency Operations Planning
G‐67‐09 EOP‐002‐2.1 Capacity and Energy Emergencies
G‐167‐10 EOP‐003‐1 Load Shedding Plans
G‐67‐09 EOP‐004‐1 Disturbance Reporting
G‐67‐09 EOP‐005‐1 System Restoration Plans
G‐67‐09 EOP‐006‐1 Reliability Coordination – System Restoration
G‐67‐09 EOP‐008‐0 Plans for Loss of Control Center Functionality
G‐67‐09 EOP‐009‐0 Documentation of Blackstart Generating Unit Test Results
G‐67‐09 FAC‐001‐0 Facility Connector Requirements
G‐67‐09 FAC‐002‐0 Coordination of Plans for New Generation, Transmission, and End‐User G‐67‐09 FAC‐003‐1 Transmission Vegetation Management Program
G‐67‐09 FAC‐008‐1 Facility Ratings Methodology
G‐67‐09 FAC‐009‐1 Establish and Communicate Facility Ratings
G‐67‐09 System Operating Limits Methodology for the Planning Horizon System Operating Limits Methodology for the Planning Horizon G‐167‐10 FAC‐010‐2 FAC‐010‐2.1 BCUC Order Adopting
G‐162‐11 FAC‐011‐2 System Operating Limits Methodology for the Operations Horizon G‐167‐10 FAC‐013‐1 Establish and Communicate Transfer Capability
G‐67‐09 FAC‐014‐2 Establish and Communicate System Operating Limits
G‐167‐10 INT‐001‐3 Interchange Information
G‐67‐09 INT‐003‐2 Interchange Transaction Implementation
G‐67‐09 INT‐004‐2 Dynamic Interchange Transaction Modifications
G‐67‐09 INT‐005‐2 INT‐005‐3 Interchange Authority Distributes Arranged Interchange Interchange Authority Distributes Arranged Interchange
G‐67‐09 INT‐006‐2 INT‐006‐3 Response to Interchange Authority Response to Interchange Authority
G‐67‐09 INT‐007‐1 Interchange Confirmation
G‐67‐09 INT‐008‐2 INT‐008‐3 Interchange Authority Distributes Status Interchange Authority Distributes Status
G‐67‐09 G‐162‐11 INT‐009‐1 Implementation of Interchange
G‐67‐09 INT‐010‐1 Interchange Coordination Exemptions
G‐67‐09 IRO‐001‐1.1 Reliability Coordination Responsibilities and Authorities
G‐167‐10 IRO‐002‐1 Reliability Coordination – Facilities
G‐67‐09 IRO‐003‐2 Reliability Coordination – Wide Area View
G‐67‐09 IRO‐004‐1 Reliability Coordination – Operations planning
G‐67‐09 IRO‐005‐2 Reliability Coordination – Current Day Operations
G‐167‐10 IRO‐006‐4 IRO‐006‐4.1 Reliability Coordination‐Transmission Loading Relief Reliability Coordination – Transmission Loading Relief
G‐67‐09 G‐162‐11 G‐162‐11 G‐162‐11 ATTACHMENT B to Order G‐162‐11 Page 3 of 5 Standard Standard Name IRO‐014‐1 Procedures, Processes, or Plans to Support Coordination Between Reliability coordinators G‐67‐09 IRO‐015‐1 Notification and Information Exchange
G‐97‐09 IRO‐016‐1 Coordination of Real‐Time Activities
G‐67‐09 IRO‐STD‐006‐0 Qualified Path Unscheduled Flow Relief
G‐67‐09 MOD‐006‐0.1 Procedure for the Use of Capacity Benefit Margin Value
G‐167‐10 MOD‐007‐0 Documentation of the Use of Capacity Benefit Margin
G‐67‐09 MOD‐010‐0 Steady‐State Data for Modeling and Simulation for the Interconnected Transmission System G‐67‐09 MOD‐012‐0 Dynamics Data for Modeling and Simulation of the Interconnected Transmission System G‐67‐09 MOD‐016‐1.1 Documentation of Data Reporting Requirements for Actual and Forecast Demand, New Energy for Load, and Controllable Demand‐Side Management G‐167‐10 MOD‐017‐0.1 Aggregated Actual and Forecast Demands and Net Energy for Load G‐167‐10 MOD‐018‐0 Treatment of Non member Demand Data and How Uncertainties are Addressed in the Forecasts of Demand and Net Energy for Load G‐67‐09 MOD‐019‐0.1 Reporting of Interruptible Demands and Direct Control Load Management Data to System Operators and Reliability Coordinators G‐167‐10 MOD‐020‐0 Providing Interruptible Demands and Direct Control Load management Data to System Operators and Reliability Coordinators G‐67‐09 MOD‐021‐0 Documentation of the Accounting Methodology for the Effects of Demand‐Side management in Demand and Energy Forecasts Documentation of the Accounting Methodology for the Effects of Demand‐Side Management in Demand and Energy Forecasts G‐67‐09 MOD‐021‐0.1 BCUC Order Adopting
G‐162‐11 NUC‐001‐2 Nuclear Plant Interface Coordination
G‐167‐10 PER ‐004‐1 Reliability Coordination – Staffing
G‐67‐09 PER‐001‐0 PER‐001‐0.1 Operating Personnel Responsibility and Authority Operating Personnel Responsibility and Authority 2009/06/08 G‐67‐09 G‐162‐11 PER‐002‐0 Operating Personnel Training
G‐67‐09 PER‐003‐0 Operating Personnel Credentials
G‐67‐09 PRC‐001‐1 System Protection Coordination
G‐67‐09 PRC‐004‐1 Analysis and Mitigation of Transmission and Generation Protection Misoperations G‐67‐09 PRC‐005‐1 Transmission and Generation Protection System Maintenance and Testing G‐67‐09 PRC‐007‐0 Assuring consistency of entity Underfrequency Load Shedding Program Requirements G‐67‐09 ATTACHMENT B to Order G‐162‐11 Page 4 of 5 Standard Standard Name PRC‐008‐0 Implementation and Documentation of Underfrequency Load Shedding Equipment Maintenance Program G‐67‐09 PRC‐009‐0 Analysis and Documentation of Underfrequency Load Shedding Performance Following an Underfrequency Event G‐67‐09 PRC‐010‐0 Technical Assessment of the Design and Effectiveness of Undervoltage Load Shedding Program G‐67‐09 PRC‐011‐0 Undervoltage Load Shedding system Maintenance and Testing G‐67‐09 PRC‐015‐0 Special Protection System Data and Documentation
G‐67‐09 PRC‐016‐0.1 Special Protection System Misoperations
G‐167‐10 PRC‐017‐0 Special Protection System Maintenance and Testing
G‐67‐09 PRC‐018‐1 Disturbance Monitoring Equipment Installation and Data Reporting G‐67‐09 PRC‐021‐1 Under Voltage Load Shedding Program Data
G‐67‐09 PRC‐022‐1 Under Voltage Load Shedding Program Performance
G‐67‐09 PRC‐023‐1 Transmission Relay Loadability
G‐162‐11 PRC‐STD‐001‐1 Certification of Protective Relay Applications and Settings
G‐67‐09 PRC‐STD‐003‐1 Protective Relay and Remedial Action Misoperation
Scheme G‐67‐09 PRC‐STD‐005‐1 Transmission Maintenance
G‐67‐09 TOP‐001‐1 Reliability Responsibilities and Authorities
G‐67‐09 TOP‐002‐2 TOP‐002‐2a Normal Operations Planning Normal Operations Planning
G‐67‐09 G‐162‐11 TOP‐003‐0 Planned Outage Coordination
G‐67‐09 TOP‐004‐2 Transmission Operations
G‐167‐10 TOP‐005‐1.1 Operational Reliability Information
G‐167‐10 TOP‐006‐1 Monitoring System Conditions
G‐67‐09 TOP‐007‐0 Reporting System Operating Unit (SOL) and Interconnection Reliability Operating Limit (IROL) Violations G‐67‐09 TOP‐008‐1 Response to Transmission Unit Violations
G‐67‐09 TOP‐STD‐007‐0 Operating Transfer Capability
G‐67‐09 TPL‐001‐0.1 System Performance Under Normal (No Contingency) Conditions (Category A) G‐167‐10 TPL‐002‐0 System Performance Following Loss of a Single Bulk Electric System Element (Category B) System Performance Following Loss of a Single Bulk Electric System Element (Category B) G‐67‐09 TPL‐002‐0a TPL‐003‐0 TPL‐003‐0a System Performance Following Loss of a Single Bulk Electric System Element (Category C) System Performance Following Loss of a Single Bulk Electric System Element (Category C) BCUC Order Adopting
G‐162‐11 G‐67‐09 G‐162‐11 ATTACHMENT B to Order G‐162‐11 Page 5 of 5 Standard Standard Name TPL‐004‐0 System Performance Following Loss of a Single Bulk Electric System Element (Category D) G‐67‐09 VAR‐001‐1 Voltage and Reactive Control
G‐67‐09 Generator Operation for Maintaining Network Voltage Schedules Generator Operation for Maintaining Network Voltage Schedules G‐167‐10 VAR‐002‐1.1a VAR‐002‐1.1b BCUC Order Adopting
G‐162‐11 VAR‐STD‐002a‐1 Automatic Voltage Regulators
G‐67‐09 VAR‐STD‐002b‐1 Power System Stabilizer
G‐67‐09 ATTACHMENT C
to Order G-162-11
Page 1 of 143
Standard CIP–002–3 — Cyber Security — Critical Cyber Asset Identification
A. Introduction
1.
Title:
Cyber Security — Critical Cyber Asset Identification
2.
Number:
CIP-002-3
3.
Purpose:
NERC Standards CIP-002-3 through CIP-009-3 provide a cyber security
framework for the identification and protection of Critical Cyber Assets to support reliable
operation of the Bulk Electric System.
These standards recognize the differing roles of each entity in the operation of the Bulk Electric
System, the criticality and vulnerability of the assets needed to manage Bulk Electric System
reliability, and the risks to which they are exposed.
Business and operational demands for managing and maintaining a reliable Bulk Electric
System increasingly rely on Cyber Assets supporting critical reliability functions and processes
to communicate with each other, across functions and organizations, for services and data. This
results in increased risks to these Cyber Assets.
Standard CIP-002-3 requires the identification and documentation of the Critical Cyber Assets
associated with the Critical Assets that support the reliable operation of the Bulk Electric
System. These Critical Assets are to be identified through the application of a risk-based
assessment.
4.
Applicability:
4.1. Within the text of Standard CIP-002-3, “Responsible Entity” shall mean:
4.1.1
Reliability Coordinator.
4.1.2
Balancing Authority.
4.1.3
Interchange Authority.
4.1.4
Transmission Service Provider.
4.1.5
Transmission Owner.
4.1.6
Transmission Operator.
4.1.7
Generator Owner.
4.1.8
Generator Operator.
4.1.9
Load Serving Entity.
4.1.10 NERC.
4.1.11 Regional Entity.
4.2. The following are exempt from Standard CIP-002-3:
5.
4.2.1
Facilities regulated by the U.S. Nuclear Regulatory Commission or the Canadian
Nuclear Safety Commission.
4.2.2
Cyber Assets associated with communication networks and data communication
links between discrete Electronic Security Perimeters.
*Effective Date: The first day of the third calendar quarter after applicable regulatory
approvals have been received (or the Reliability Standard otherwise becomes effective the first
day of the third calendar quarter after BOT adoption in those jurisdictions where regulatory
approval is not required.)
Approved by Board of Trustees: December 16, 2009
* per BCUC Order G-162-11
1
ATTACHMENT C
to Order G-162-11
Page 2 of 143
Standard CIP–002–3 — Cyber Security — Critical Cyber Asset Identification
B. Requirements
R1.
Critical Asset Identification Method — The Responsible Entity shall identify and document a
risk-based assessment methodology to use to identify its Critical Assets.
R1.1.
The Responsible Entity shall maintain documentation describing its risk-based
assessment methodology that includes procedures and evaluation criteria.
R1.2.
The risk-based assessment shall consider the following assets:
R1.2.1. Control centers and backup control centers performing the functions of the
entities listed in the Applicability section of this standard.
R1.2.2. Transmission substations that support the reliable operation of the Bulk
Electric System.
R1.2.3. Generation resources that support the reliable operation of the Bulk Electric
System.
R1.2.4. Systems and facilities critical to system restoration, including blackstart
generators and substations in the electrical path of transmission lines used
for initial system restoration.
R1.2.5. Systems and facilities critical to automatic load shedding under a common
control system capable of shedding 300 MW or more.
R1.2.6. Special Protection Systems that support the reliable operation of the Bulk
Electric System.
R1.2.7. Any additional assets that support the reliable operation of the Bulk Electric
System that the Responsible Entity deems appropriate to include in its
assessment.
R2.
Critical Asset Identification — The Responsible Entity shall develop a list of its identified
Critical Assets determined through an annual application of the risk-based assessment
methodology required in R1. The Responsible Entity shall review this list at least annually,
and update it as necessary.
R3.
Critical Cyber Asset Identification — Using the list of Critical Assets developed pursuant to
Requirement R2, the Responsible Entity shall develop a list of associated Critical Cyber Assets
essential to the operation of the Critical Asset. Examples at control centers and backup control
centers include systems and facilities at master and remote sites that provide monitoring and
control, automatic generation control, real-time power system modeling, and real-time interutility data exchange. The Responsible Entity shall review this list at least annually, and
update it as necessary. For the purpose of Standard CIP-002-3, Critical Cyber Assets are
further qualified to be those having at least one of the following characteristics:
R4.
R3.1.
The Cyber Asset uses a routable protocol to communicate outside the Electronic
Security Perimeter; or,
R3.2.
The Cyber Asset uses a routable protocol within a control center; or,
R3.3.
The Cyber Asset is dial-up accessible.
Annual Approval — The senior manager or delegate(s) shall approve annually the risk-based
assessment methodology, the list of Critical Assets and the list of Critical Cyber Assets. Based
on Requirements R1, R2, and R3 the Responsible Entity may determine that it has no Critical
Assets or Critical Cyber Assets. The Responsible Entity shall keep a signed and dated record of
Approved by Board of Trustees: December 16, 2009
* per BCUC Order G-162-11
2
ATTACHMENT C
to Order G-162-11
Page 3 of 143
Standard CIP–002–3 — Cyber Security — Critical Cyber Asset Identification
the senior manager or delegate(s)’s approval of the risk-based assessment methodology, the list
of Critical Assets and the list of Critical Cyber Assets (even if such lists are null.)
C. Measures
M1.
The Responsible Entity shall make available its current risk-based assessment methodology
documentation as specified in Requirement R1.
M2.
The Responsible Entity shall make available its list of Critical Assets as specified in
Requirement R2.
M3.
The Responsible Entity shall make available its list of Critical Cyber Assets as specified in
Requirement R3.
M4.
The Responsible Entity shall make available its approval records of annual approvals as
specified in Requirement R4.
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Enforcement Authority
The British Columbia Utilities Commission
1.2. Compliance Monitoring Period and Reset Time Frame
Not applicable.
1.3. Compliance Monitoring and Enforcement Processes
Compliance Audits
Self-Certifications
Spot Checking
Compliance Violation Investigations
Self-Reporting
Complaints
1.4. Data Retention
1.4.1
The Responsible Entity shall keep documentation required by Standard CIP-0023 from the previous full calendar year unless directed by its Compliance
Enforcement Authority to retain specific evidence for a longer period of time as
part of an investigation.
1.4.2
The Compliance Enforcement Authority in conjunction with the Registered
Entity shall keep the last audit records and all requested and submitted
subsequent audit records.
1.5. Additional Compliance Information
1.5.1
None.
2. Violation Severity Levels (To be developed later.)
E. Regional Variances
None identified.
Approved by Board of Trustees: December 16, 2009
* per BCUC Order G-162-11
3
ATTACHMENT C
to Order G-162-11
Page 4 of 143
Standard CIP–002–3 — Cyber Security — Critical Cyber Asset Identification
Version History
Version
1
Date
Action
Change Tracking
January 16, 2006
R3.2 — Change “Control Center” to “control
center”
Errata
2
Modifications to clarify the requirements and to
bring the compliance elements into conformance
with the latest guidelines for developing
compliance elements of standards.
Removal of reasonable business judgment.
Replaced the RRO with the RE as a responsible
entity.
Rewording of Effective Date.
Changed compliance monitor to Compliance
Enforcement Authority.
3
Updated version number from -2 to -3
3
December 16, 2009
Approved by the NERC Board of Trustees
Approved by Board of Trustees: December 16, 2009
* per BCUC Order G-162-11
Update
4
ATTACHMENT C
to Order G-162-11
Page 5 of 143
Standard CIP–003–3 — Cyber Security — Security Management Controls
A. Introduction
1.
Title:
Cyber Security — Security Management Controls
2.
Number:
CIP-003-3
3.
Purpose:
Standard CIP-003-3 requires that Responsible Entities have minimum security
management controls in place to protect Critical Cyber Assets. Standard CIP-003-3 should be
read as part of a group of standards numbered Standards CIP-002-3 through CIP-009-3.
4.
Applicability:
4.1. Within the text of Standard CIP-003-3, “Responsible Entity” shall mean:
4.1.1
Reliability Coordinator.
4.1.2
Balancing Authority.
4.1.3
Interchange Authority.
4.1.4
Transmission Service Provider.
4.1.5
Transmission Owner.
4.1.6
Transmission Operator.
4.1.7
Generator Owner.
4.1.8
Generator Operator.
4.1.9
Load Serving Entity.
4.1.10 NERC.
4.1.11 Regional Entity.
4.2. The following are exempt from Standard CIP-003-3:
5.
4.2.1
Facilities regulated by the U.S. Nuclear Regulatory Commission or the Canadian
Nuclear Safety Commission.
4.2.2
Cyber Assets associated with communication networks and data communication
links between discrete Electronic Security Perimeters.
4.2.3
Responsible Entities that, in compliance with Standard CIP-002-3, identify that
they have no Critical Cyber Assets shall only be required to comply with CIP003-3 Requirement R2.
*Effective Date: The first day of the third calendar quarter after applicable regulatory
approvals have been received (or the Reliability Standard otherwise becomes effective the first
day of the third calendar quarter after BOT adoption in those jurisdictions where regulatory
approval is not required).
B. Requirements
R1. Cyber Security Policy — The Responsible Entity shall document and implement a cyber
security policy that represents management’s commitment and ability to secure its Critical
Cyber Assets. The Responsible Entity shall, at minimum, ensure the following:
R1.1.
The cyber security policy addresses the requirements in Standards CIP-002-3 through
CIP-009-3, including provision for emergency situations.
Approved by Board of Trustees: December 16, 2009
* per BCUC Order G-162-11
1
ATTACHMENT C
to Order G-162-11
Page 6 of 143
Standard CIP–003–3 — Cyber Security — Security Management Controls
R1.2.
The cyber security policy is readily available to all personnel who have access to, or are
responsible for, Critical Cyber Assets.
R1.3.
Annual review and approval of the cyber security policy by the senior manager
assigned pursuant to R2.
R2. Leadership — The Responsible Entity shall assign a single senior manager with overall
responsibility and authority for leading and managing the entity’s implementation of, and
adherence to, Standards CIP-002-3 through CIP-009-3.
R2.1.
The senior manager shall be identified by name, title, and date of designation.
R2.2.
Changes to the senior manager must be documented within thirty calendar days of the
effective date.
R2.3.
Where allowed by Standards CIP-002-3 through CIP-009-3, the senior manager may
delegate authority for specific actions to a named delegate or delegates. These
delegations shall be documented in the same manner as R2.1 and R2.2, and approved
by the senior manager.
R2.4.
The senior manager or delegate(s), shall authorize and document any exception from
the requirements of the cyber security policy.
R3. Exceptions — Instances where the Responsible Entity cannot conform to its cyber security
policy must be documented as exceptions and authorized by the senior manager or delegate(s).
R3.1.
Exceptions to the Responsible Entity’s cyber security policy must be documented
within thirty days of being approved by the senior manager or delegate(s).
R3.2.
Documented exceptions to the cyber security policy must include an explanation as to
why the exception is necessary and any compensating measures.
R3.3.
Authorized exceptions to the cyber security policy must be reviewed and approved
annually by the senior manager or delegate(s) to ensure the exceptions are still
required and valid. Such review and approval shall be documented.
R4. Information Protection — The Responsible Entity shall implement and document a program to
identify, classify, and protect information associated with Critical Cyber Assets.
R4.1.
The Critical Cyber Asset information to be protected shall include, at a minimum and
regardless of media type, operational procedures, lists as required in Standard CIP002-3, network topology or similar diagrams, floor plans of computing centers that
contain Critical Cyber Assets, equipment layouts of Critical Cyber Assets, disaster
recovery plans, incident response plans, and security configuration information.
R4.2.
The Responsible Entity shall classify information to be protected under this program
based on the sensitivity of the Critical Cyber Asset information.
R4.3.
The Responsible Entity shall, at least annually, assess adherence to its Critical Cyber
Asset information protection program, document the assessment results, and
implement an action plan to remediate deficiencies identified during the assessment.
R5. Access Control — The Responsible Entity shall document and implement a program for
managing access to protected Critical Cyber Asset information.
R5.1.
The Responsible Entity shall maintain a list of designated personnel who are
responsible for authorizing logical or physical access to protected information.
R5.1.1.
Personnel shall be identified by name, title, and the information for which
they are responsible for authorizing access.
Approved by Board of Trustees: December 16, 2009
* per BCUC Order G-162-11
2
ATTACHMENT C
to Order G-162-11
Page 7 of 143
Standard CIP–003–3 — Cyber Security — Security Management Controls
R5.1.2.
The list of personnel responsible for authorizing access to protected
information shall be verified at least annually.
R5.2.
The Responsible Entity shall review at least annually the access privileges to protected
information to confirm that access privileges are correct and that they correspond with
the Responsible Entity’s needs and appropriate personnel roles and responsibilities.
R5.3.
The Responsible Entity shall assess and document at least annually the processes for
controlling access privileges to protected information.
R6. Change Control and Configuration Management — The Responsible Entity shall establish and
document a process of change control and configuration management for adding, modifying,
replacing, or removing Critical Cyber Asset hardware or software, and implement supporting
configuration management activities to identify, control and document all entity or vendorrelated changes to hardware and software components of Critical Cyber Assets pursuant to the
change control process.
C. Measures
M1. The Responsible Entity shall make available documentation of its cyber security policy as
specified in Requirement R1. Additionally, the Responsible Entity shall demonstrate that the
cyber security policy is available as specified in Requirement R1.2.
M2. The Responsible Entity shall make available documentation of the assignment of, and changes
to, its leadership as specified in Requirement R2.
M3. The Responsible Entity shall make available documentation of the exceptions, as specified in
Requirement R3.
M4. The Responsible Entity shall make available documentation of its information protection
program as specified in Requirement R4.
M5. The Responsible Entity shall make available its access control documentation as specified in
Requirement R5.
M6. The Responsible Entity shall make available its change control and configuration management
documentation as specified in Requirement R6.
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Enforcement Authority
The British Columbia Utilities Commission
1.2. Compliance Monitoring Period and Reset Time Frame
Not applicable.
1.3. Compliance Monitoring and Enforcement Processes
Compliance Audits
Self-Certifications
Spot Checking
Compliance Violation Investigations
Self-Reporting
Approved by Board of Trustees: December 16, 2009
* per BCUC Order G-162-11
3
ATTACHMENT C
to Order G-162-11
Page 8 of 143
Standard CIP–003–3 — Cyber Security — Security Management Controls
Complaints
1.4. Data Retention
1.4.1
The Responsible Entity shall keep all documentation and records from the
previous full calendar year unless directed by its Compliance Enforcement
Authority to retain specific evidence for a longer period of time as part of an
investigation.
1.4.2
The Compliance Enforcement Authority in conjunction with the Registered
Entity shall keep the last audit records and all requested and submitted
subsequent audit records.
1.5. Additional Compliance Information
1.5.1
2.
None
Violation Severity Levels (To be developed later.)
E. Regional Variances
None identified.
Version History
Version
Date
Action
2
Modifications to clarify the requirements and to bring the
compliance elements into conformance with the latest
guidelines for developing compliance elements of
standards.
Removal of reasonable business judgment.
Replaced the RRO with the RE as a responsible entity.
Rewording of Effective Date.
Requirement R2 applies to all Responsible Entities,
including Responsible Entities which have no Critical
Cyber Assets.
Modified the personnel identification information
requirements in R5.1.1 to include name, title, and the
information for which they are responsible for
authorizing access (removed the business phone
information).
Changed compliance monitor to Compliance
Enforcement Authority.
3
Update version number from -2 to -3
3
12/16/09
Approved by the NERC Board of Trustees
Approved by Board of Trustees: December 16, 2009
* per BCUC Order G-162-11
Change Tracking
Update
4
ATTACHMENT C
to Order G-162-11
Page 9 of 143
Standard CIP–004–3 — Cyber Security — Personnel and Training
A. Introduction
1.
Title:
Cyber Security — Personnel & Training
2.
Number:
CIP-004-3
3.
Purpose:
Standard CIP-004-3 requires that personnel having authorized cyber or
authorized unescorted physical access to Critical Cyber Assets, including contractors and
service vendors, have an appropriate level of personnel risk assessment, training, and security
awareness. Standard CIP-004-3 should be read as part of a group of standards numbered
Standards CIP-002-3 through CIP-009-3.
4.
Applicability:
4.1. Within the text of Standard CIP-004-3, “Responsible Entity” shall mean:
4.1.1
Reliability Coordinator.
4.1.2
Balancing Authority.
4.1.3
Interchange Authority.
4.1.4
Transmission Service Provider.
4.1.5
Transmission Owner.
4.1.6
Transmission Operator.
4.1.7
Generator Owner.
4.1.8
Generator Operator.
4.1.9
Load Serving Entity.
4.1.10 NERC.
4.1.11 Regional Entity.
4.2. The following are exempt from Standard CIP-004-3:
5.
4.2.1
Facilities regulated by the U.S. Nuclear Regulatory Commission or the Canadian
Nuclear Safety Commission.
4.2.2
Cyber Assets associated with communication networks and data communication
links between discrete Electronic Security Perimeters.
4.2.3
Responsible Entities that, in compliance with Standard CIP-002-3, identify that
they have no Critical Cyber Assets.
*Effective Date: The first day of the third calendar quarter after applicable regulatory
approvals have been received (or the Reliability Standard otherwise becomes effective the first
day of the third calendar quarter after BOT adoption in those jurisdictions where regulatory
approval is not required).
B. Requirements
R1. Awareness — The Responsible Entity shall establish, document, implement, and maintain a
security awareness program to ensure personnel having authorized cyber or authorized
unescorted physical access to Critical Cyber Assets receive on-going reinforcement in sound
security practices. The program shall include security awareness reinforcement on at least a
quarterly basis using mechanisms such as:
•
Direct communications (e.g., emails, memos, computer based training, etc.);
•
Indirect communications (e.g., posters, intranet, brochures, etc.);
Approved by Board of Trustees: December 16, 2009
* per BCUC Order G-162-11
1
ATTACHMENT C
to Order G-162-11
Page 10 of 143
Standard CIP–004–3 — Cyber Security — Personnel and Training
•
Management support and reinforcement (e.g., presentations, meetings, etc.).
R2. Training — The Responsible Entity shall establish, document, implement, and maintain an
annual cyber security training program for personnel having authorized cyber or authorized
unescorted physical access to Critical Cyber Assets. The cyber security training program shall
be reviewed annually, at a minimum, and shall be updated whenever necessary.
R2.1.
This program will ensure that all personnel having such access to Critical Cyber Assets,
including contractors and service vendors, are trained prior to their being granted such
access except in specified circumstances such as an emergency.
R2.2.
Training shall cover the policies, access controls, and procedures as developed for the
Critical Cyber Assets covered by CIP-004-3, and include, at a minimum, the following
required items appropriate to personnel roles and responsibilities:
R2.3.
R2.2.1.
The proper use of Critical Cyber Assets;
R2.2.2.
Physical and electronic access controls to Critical Cyber Assets;
R2.2.3.
The proper handling of Critical Cyber Asset information; and,
R2.2.4.
Action plans and procedures to recover or re-establish Critical Cyber Assets
and access thereto following a Cyber Security Incident.
The Responsible Entity shall maintain documentation that training is conducted at least
annually, including the date the training was completed and attendance records.
R3. Personnel Risk Assessment —The Responsible Entity shall have a documented personnel risk
assessment program, in accordance with federal, state, provincial, and local laws, and subject to
existing collective bargaining unit agreements, for personnel having authorized cyber or
authorized unescorted physical access to Critical Cyber Assets. A personnel risk assessment
shall be conducted pursuant to that program prior to such personnel being granted such access
except in specified circumstances such as an emergency.
The personnel risk assessment program shall at a minimum include:
R3.1.
The Responsible Entity shall ensure that each assessment conducted include, at least,
identity verification (e.g., Social Security Number verification in the U.S.) and sevenyear criminal check. The Responsible Entity may conduct more detailed reviews, as
permitted by law and subject to existing collective bargaining unit agreements,
depending upon the criticality of the position.
R3.2.
The Responsible Entity shall update each personnel risk assessment at least every seven
years after the initial personnel risk assessment or for cause.
R3.3.
The Responsible Entity shall document the results of personnel risk assessments of its
personnel having authorized cyber or authorized unescorted physical access to Critical
Cyber Assets, and that personnel risk assessments of contractor and service vendor
personnel with such access are conducted pursuant to Standard CIP-004-3.
R4. Access — The Responsible Entity shall maintain list(s) of personnel with authorized cyber or
authorized unescorted physical access to Critical Cyber Assets, including their specific
electronic and physical access rights to Critical Cyber Assets.
R4.1.
The Responsible Entity shall review the list(s) of its personnel who have such access to
Critical Cyber Assets quarterly, and update the list(s) within seven calendar days of any
change of personnel with such access to Critical Cyber Assets, or any change in the
access rights of such personnel. The Responsible Entity shall ensure access list(s) for
contractors and service vendors are properly maintained.
Approved by Board of Trustees: December 16, 2009
* per BCUC Order G-162-11
2
ATTACHMENT C
to Order G-162-11
Page 11 of 143
Standard CIP–004–3 — Cyber Security — Personnel and Training
R4.2.
The Responsible Entity shall revoke such access to Critical Cyber Assets within 24
hours for personnel terminated for cause and within seven calendar days for personnel
who no longer require such access to Critical Cyber Assets.
C. Measures
M1. The Responsible Entity shall make available documentation of its security awareness and
reinforcement program as specified in Requirement R1.
M2. The Responsible Entity shall make available documentation of its cyber security training
program, review, and records as specified in Requirement R2.
M3. The Responsible Entity shall make available documentation of the personnel risk assessment
program and that personnel risk assessments have been applied to all personnel who have
authorized cyber or authorized unescorted physical access to Critical Cyber Assets, as specified
in Requirement R3.
M4. The Responsible Entity shall make available documentation of the list(s), list review and
update, and access revocation as needed as specified in Requirement R4.
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Enforcement Authority
The British Columbia Utilities Commission
1.2. Compliance Monitoring Period and Reset Time Frame
Not Applicable.
1.3. Compliance Monitoring and Enforcement Processes
Compliance Audits
Self-Certifications
Spot Checking
Compliance Violation Investigations
Self-Reporting
Complaints
1.4. Data Retention
1.4.1
The Responsible Entity shall keep personnel risk assessment documents in
accordance with federal, state, provincial, and local laws.
1.4.2
The Responsible Entity shall keep all other documentation required by Standard
CIP-004-3 from the previous full calendar year unless directed by its Compliance
Enforcement Authority to retain specific evidence for a longer period of time as
part of an investigation.
1.4.3
The Compliance Enforcement Authority in conjunction with the Registered
Entity shall keep the last audit records and all requested and submitted
subsequent audit records.
1.5. Additional Compliance Information
2.
Violation Severity Levels (To be developed later.)
E. Regional Variances
Approved by Board of Trustees: December 16, 2009
* per BCUC Order G-162-11
3
ATTACHMENT C
to Order G-162-11
Page 12 of 143
Standard CIP–004–3 — Cyber Security — Personnel and Training
None identified.
Version History
Version
Date
Action
Change Tracking
1
01/16/06
D.2.2.4 — Insert the phrase “for cause” as
intended. “One instance of personnel termination
for cause…”
03/24/06
1
06/01/06
D.2.1.4 — Change “access control rights” to
“access rights.”
06/05/06
2
Modifications to clarify the requirements and to
bring the compliance elements into conformance
with the latest guidelines for developing
compliance elements of standards.
Removal of reasonable business judgment.
Replaced the RRO with the RE as a responsible
entity.
Rewording of Effective Date.
Reference to emergency situations.
Modification to R1 for the Responsible Entity to
establish, document, implement, and maintain the
awareness program.
Modification to R2 for the Responsible Entity to
establish, document, implement, and maintain the
training program; also stating the requirements for
the cyber security training program.
Modification to R3 Personnel Risk Assessment to
clarify that it pertains to personnel having
authorized cyber or authorized unescorted physical
access to “Critical Cyber Assets”.
Removal of 90 day window to complete training
and 30 day window to complete personnel risk
assessments.
Changed compliance monitor to Compliance
Enforcement Authority.
3
Update version number from -2 to -3
3
12/16/09
Approved by NERC Board of Trustees
Approved by Board of Trustees: December 16, 2009
* per BCUC Order G-162-11
Update
4
ATTACHMENT C
to Order G-162-11
Page 13 of 143
Standard CIP–005–3 — Cyber Security — Electronic Security Perimeter(s)
A. Introduction
1.
Title:
Cyber Security — Electronic Security Perimeter(s)
2.
Number:
CIP-005-3
3.
Purpose:
Standard CIP-005-3 requires the identification and protection of the Electronic
Security Perimeter(s) inside which all Critical Cyber Assets reside, as well as all access points
on the perimeter. Standard CIP-005-3 should be read as part of a group of standards numbered
Standards CIP-002-3 through CIP-009-3.
4.
Applicability
4.1. Within the text of Standard CIP-005-3, “Responsible Entity” shall mean:
4.1.1
Reliability Coordinator.
4.1.2
Balancing Authority.
4.1.3
Interchange Authority.
4.1.4
Transmission Service Provider.
4.1.5
Transmission Owner.
4.1.6
Transmission Operator.
4.1.7
Generator Owner.
4.1.8
Generator Operator.
4.1.9
Load Serving Entity.
4.1.10 NERC.
4.1.11 Regional Entity
4.2. The following are exempt from Standard CIP-005-3:
5.
4.2.1
Facilities regulated by the U.S. Nuclear Regulatory Commission or the Canadian
Nuclear Safety Commission.
4.2.2
Cyber Assets associated with communication networks and data communication
links between discrete Electronic Security Perimeters.
4.2.3
Responsible Entities that, in compliance with Standard CIP-002-3, identify that
they have no Critical Cyber Assets.
*Effective Date: The first day of the third calendar quarter after applicable regulatory
approvals have been received (or the Reliability Standard otherwise becomes effective in
those jurisdictions where regulatory approval is not required).
B. Requirements
R1. Electronic Security Perimeter — The Responsible Entity shall ensure that every Critical Cyber
Asset resides within an Electronic Security Perimeter. The Responsible Entity shall identify and
document the Electronic Security Perimeter(s) and all access points to the perimeter(s).
R1.1.
Access points to the Electronic Security Perimeter(s) shall include any externally
connected communication end point (for example, dial-up modems) terminating at any
device within the Electronic Security Perimeter(s).
R1.2.
For a dial-up accessible Critical Cyber Asset that uses a non-routable protocol, the
Responsible Entity shall define an Electronic Security Perimeter for that single access
point at the dial-up device.
Approved by Board of Trustees: December 16, 2009
* per BCUC Order G-162-11
1
ATTACHMENT C
to Order G-162-11
Page 14 of 143
Standard CIP–005–3 — Cyber Security — Electronic Security Perimeter(s)
R1.3.
Communication links connecting discrete Electronic Security Perimeters shall not be
considered part of the Electronic Security Perimeter. However, end points of these
communication links within the Electronic Security Perimeter(s) shall be considered
access points to the Electronic Security Perimeter(s).
R1.4.
Any non-critical Cyber Asset within a defined Electronic Security Perimeter shall be
identified and protected pursuant to the requirements of Standard CIP-005-3.
R1.5.
Cyber Assets used in the access control and/or monitoring of the Electronic Security
Perimeter(s) shall be afforded the protective measures as a specified in Standard CIP003-3; Standard CIP-004-3 Requirement R3; Standard CIP-005-3 Requirements R2
and R3; Standard CIP-006-3 Requirement R3; Standard CIP-007-3 Requirements R1
and R3 through R9; Standard CIP-008-3; and Standard CIP-009-3.
R1.6.
The Responsible Entity shall maintain documentation of Electronic Security
Perimeter(s), all interconnected Critical and non-critical Cyber Assets within the
Electronic Security Perimeter(s), all electronic access points to the Electronic Security
Perimeter(s) and the Cyber Assets deployed for the access control and monitoring of
these access points.
R2. Electronic Access Controls — The Responsible Entity shall implement and document the
organizational processes and technical and procedural mechanisms for control of electronic
access at all electronic access points to the Electronic Security Perimeter(s).
R2.1.
These processes and mechanisms shall use an access control model that denies access
by default, such that explicit access permissions must be specified.
R2.2.
At all access points to the Electronic Security Perimeter(s), the Responsible Entity shall
enable only ports and services required for operations and for monitoring Cyber Assets
within the Electronic Security Perimeter, and shall document, individually or by
specified grouping, the configuration of those ports and services.
R2.3.
The Responsible Entity shall implement and maintain a procedure for securing dial-up
access to the Electronic Security Perimeter(s).
R2.4.
Where external interactive access into the Electronic Security Perimeter has been
enabled, the Responsible Entity shall implement strong procedural or technical controls
at the access points to ensure authenticity of the accessing party, where technically
feasible.
R2.5.
The required documentation shall, at least, identify and describe:
R2.6.
R2.5.1.
The processes for access request and authorization.
R2.5.2.
The authentication methods.
R2.5.3.
The review process for authorization rights, in accordance with Standard
CIP-004-3 Requirement R4.
R2.5.4.
The controls used to secure dial-up accessible connections.
Appropriate Use Banner — Where technically feasible, electronic access control
devices shall display an appropriate use banner on the user screen upon all interactive
access attempts. The Responsible Entity shall maintain a document identifying the
content of the banner.
R3. Monitoring Electronic Access — The Responsible Entity shall implement and document an
electronic or manual process(es) for monitoring and logging access at access points to the
Electronic Security Perimeter(s) twenty-four hours a day, seven days a week.
Approved by Board of Trustees: December 16, 2009
* per BCUC Order G-162-11
2
ATTACHMENT C
to Order G-162-11
Page 15 of 143
Standard CIP–005–3 — Cyber Security — Electronic Security Perimeter(s)
R3.1.
For dial-up accessible Critical Cyber Assets that use non-routable protocols, the
Responsible Entity shall implement and document monitoring process(es) at each
access point to the dial-up device, where technically feasible.
R3.2.
Where technically feasible, the security monitoring process(es) shall detect and alert for
attempts at or actual unauthorized accesses. These alerts shall provide for appropriate
notification to designated response personnel. Where alerting is not technically
feasible, the Responsible Entity shall review or otherwise assess access logs for
attempts at or actual unauthorized accesses at least every ninety calendar days.
R4. Cyber Vulnerability Assessment — The Responsible Entity shall perform a cyber vulnerability
assessment of the electronic access points to the Electronic Security Perimeter(s) at least
annually. The vulnerability assessment shall include, at a minimum, the following:
R4.1.
A document identifying the vulnerability assessment process;
R4.2.
A review to verify that only ports and services required for operations at these access
points are enabled;
R4.3.
The discovery of all access points to the Electronic Security Perimeter;
R4.4.
A review of controls for default accounts, passwords, and network management
community strings;
R4.5.
Documentation of the results of the assessment, the action plan to remediate or mitigate
vulnerabilities identified in the assessment, and the execution status of that action plan.
R5. Documentation Review and Maintenance — The Responsible Entity shall review, update, and
maintain all documentation to support compliance with the requirements of Standard CIP-0053.
R5.1.
The Responsible Entity shall ensure that all documentation required by Standard CIP005-3 reflect current configurations and processes and shall review the documents and
procedures referenced in Standard CIP-005-3 at least annually.
R5.2.
The Responsible Entity shall update the documentation to reflect the modification of
the network or controls within ninety calendar days of the change.
R5.3.
The Responsible Entity shall retain electronic access logs for at least ninety calendar
days. Logs related to reportable incidents shall be kept in accordance with the
requirements of Standard CIP-008-3.
C. Measures
M1. The Responsible Entity shall make available documentation about the Electronic Security
Perimeter as specified in Requirement R1.
M2. The Responsible Entity shall make available documentation of the electronic access controls to
the Electronic Security Perimeter(s), as specified in Requirement R2.
M3. The Responsible Entity shall make available documentation of controls implemented to log and
monitor access to the Electronic Security Perimeter(s) as specified in Requirement R3.
M4. The Responsible Entity shall make available documentation of its annual vulnerability
assessment as specified in Requirement R4.
M5. The Responsible Entity shall make available access logs and documentation of review, changes,
and log retention as specified in Requirement R5.
D. Compliance
1.
Compliance Monitoring Process
Approved by Board of Trustees: December 16, 2009
* per BCUC Order G-162-11
3
ATTACHMENT C
to Order G-162-11
Page 16 of 143
Standard CIP–005–3 — Cyber Security — Electronic Security Perimeter(s)
1.1. Compliance Enforcement Authority
The British Columbia Utilities Commission
1.2. Compliance Monitoring Period and Reset Time Frame
Not applicable.
1.3. Compliance Monitoring and Enforcement Processes
Compliance Audits
Self-Certifications
Spot Checking
Compliance Violation Investigations
Self-Reporting
Complaints
1.4. Data Retention
1.4.1
The Responsible Entity shall keep logs for a minimum of ninety calendar days,
unless: a) longer retention is required pursuant to Standard CIP-008-3,
Requirement R2; b) directed by its Compliance Enforcement Authority to retain
specific evidence for a longer period of time as part of an investigation.
1.4.2
The Responsible Entity shall keep other documents and records required by
Standard CIP-005-3 from the previous full calendar year.
1.4.3
The Compliance Enforcement Authority in conjunction with the Registered
Entity shall keep the last audit records and all requested and submitted
subsequent audit records.
1.5. Additional Compliance Information
2.
Violation Severity Levels (To be developed later.)
E. Regional Variances
None identified.
Version History
Version
1
2
Date
Action
Change Tracking
01/16/06
D.2.3.1 — Change “Critical Assets,” to “Critical Cyber Assets”
as intended.
03/24/06
Modifications to clarify the requirements and to bring the
compliance elements into conformance with the latest guidelines
for developing compliance elements of standards.
Removal of reasonable business judgment.
Replaced the RRO with the RE as a responsible entity.
Rewording of Effective Date.
Revised the wording of the Electronic Access Controls
requirement stated in R2.3 to clarify that the Responsible Entity
shall “implement and maintain” a procedure for securing dial-up
access to the Electronic Security Perimeter(s).
Changed compliance monitor to Compliance Enforcement
Approved by Board of Trustees: December 16, 2009
* per BCUC Order G-162-11
4
ATTACHMENT C
to Order G-162-11
Page 17 of 143
Standard CIP–005–3 — Cyber Security — Electronic Security Perimeter(s)
Authority.
3
3
Update version from -2 to -3
12/16/09
Approved by the NERC Board of Trustees
Approved by Board of Trustees: December 16, 2009
* per BCUC Order G-162-11
Update
5
ATTACHMENT C
to Order G-162-11
Page 18 of 143
Standard CIP-006-3c — Cyber Security — Physical Security
A. Introduction
1.
Title:
Cyber Security — Physical Security of Critical Cyber Assets
2.
Number:
CIP-006-3c
3.
Purpose:
Standard CIP-006-3 is intended to ensure the implementation of a physical
security program for the protection of Critical Cyber Assets. Standard CIP-006-3 should be
read as part of a group of standards numbered Standards CIP-002-3 through CIP-009-3.
4.
Applicability:
4.1. Within the text of Standard CIP-006-3, “Responsible Entity” shall mean:
4.1.1
Reliability Coordinator
4.1.2
Balancing Authority
4.1.3
Interchange Authority
4.1.4
Transmission Service Provider
4.1.5
Transmission Owner
4.1.6
Transmission Operator
4.1.7
Generator Owner
4.1.8
Generator Operator
4.1.9
Load Serving Entity
4.1.10 NERC
4.1.11 Regional Entity
4.2. The following are exempt from Standard CIP-006-3:
5.
4.2.1
Facilities regulated by the U.S. Nuclear Regulatory Commission or the Canadian
Nuclear Safety Commission.
4.2.2
Cyber Assets associated with communication networks and data communication
links between discrete Electronic Security Perimeters.
4.2.3
Responsible Entities that, in compliance with Standard CIP-002-3, identify that
they have no Critical Cyber Assets
*Effective Date: The first day of the third calendar quarter after applicable regulatory
approvals have been received (or the Reliability Standard otherwise becomes effective the first
day of the third calendar quarter after BOT adoption in those jurisdictions where regulatory
approval is not required).
B. Requirements
R1.
Physical Security Plan — The Responsible Entity shall document, implement, and maintain a
physical security plan, approved by the senior manager or delegate(s) that shall address, at a
minimum, the following:
R1.1.
All Cyber Assets within an Electronic Security Perimeter shall reside within an
identified Physical Security Perimeter. Where a completely enclosed (“six-wall”)
border cannot be established, the Responsible Entity shall deploy and document
alternative measures to control physical access to such Cyber Assets.
R1.2.
Identification of all physical access points through each Physical Security Perimeter
and measures to control entry at those access points.
* Mandatory BC effective date October 16, 2011
* per BCUC Order G-162-11
1
ATTACHMENT C
to Order G-162-11
Page 19 of 143
Standard CIP-006-3c — Cyber Security — Physical Security
R1.3.
Processes, tools, and procedures to monitor physical access to the perimeter(s).
R1.4.
Appropriate use of physical access controls as described in Requirement R4
including visitor pass management, response to loss, and prohibition of inappropriate
use of physical access controls.
R1.5.
Review of access authorization requests and revocation of access authorization, in
accordance with CIP-004-3 Requirement R4.
R1.6.
A visitor control program for visitors (personnel without authorized unescorted
access to a Physical Security Perimeter), containing at a minimum the following:
R1.6.1. Logs (manual or automated) to document the entry and exit of visitors,
including the date and time, to and from Physical Security Perimeters.
R1.6.2. Continuous escorted access of visitors within the Physical Security
Perimeter.
R2.
R1.7.
Update of the physical security plan within thirty calendar days of the completion of
any physical security system redesign or reconfiguration, including, but not limited
to, addition or removal of access points through the Physical Security Perimeter,
physical access controls, monitoring controls, or logging controls.
R1.8.
Annual review of the physical security plan.
Protection of Physical Access Control Systems — Cyber Assets that authorize and/or log
access to the Physical Security Perimeter(s), exclusive of hardware at the Physical Security
Perimeter access point such as electronic lock control mechanisms and badge readers, shall:
R2.1.
Be protected from unauthorized physical access.
R2.2.
Be afforded the protective measures specified in Standard CIP-003-3; Standard CIP004-3 Requirement R3; Standard CIP-005-3 Requirements R2 and R3; Standard CIP006-3 Requirements R4 and R5; Standard CIP-007-3; Standard CIP-008-3; and
Standard CIP-009-3.
R3.
Protection of Electronic Access Control Systems — Cyber Assets used in the access control
and/or monitoring of the Electronic Security Perimeter(s) shall reside within an identified
Physical Security Perimeter.
R4.
Physical Access Controls — The Responsible Entity shall document and implement the
operational and procedural controls to manage physical access at all access points to the
Physical Security Perimeter(s) twenty-four hours a day, seven days a week. The Responsible
Entity shall implement one or more of the following physical access methods:
R5.
•
Card Key: A means of electronic access where the access rights of the card holder are
predefined in a computer database. Access rights may differ from one perimeter to
another.
•
Special Locks: These include, but are not limited to, locks with “restricted key” systems,
magnetic locks that can be operated remotely, and “man-trap” systems.
•
Security Personnel: Personnel responsible for controlling physical access who may reside
on-site or at a monitoring station.
•
Other Authentication Devices: Biometric, keypad, token, or other equivalent devices that
control physical access to the Critical Cyber Assets.
Monitoring Physical Access — The Responsible Entity shall document and implement the
technical and procedural controls for monitoring physical access at all access points to the
Physical Security Perimeter(s) twenty-four hours a day, seven days a week. Unauthorized
* Mandatory BC effective date October 16, 2011
* per BCUC Order G-162-11
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access attempts shall be reviewed immediately and handled in accordance with the procedures
specified in Requirement CIP-008-3. One or more of the following monitoring methods shall
be used:
R6.
•
Alarm Systems: Systems that alarm to indicate a door, gate or window has been opened
without authorization. These alarms must provide for immediate notification to personnel
responsible for response.
•
Human Observation of Access Points: Monitoring of physical access points by authorized
personnel as specified in Requirement R4.
Logging Physical Access — Logging shall record sufficient information to uniquely identify
individuals and the time of access twenty-four hours a day, seven days a week. The
Responsible Entity shall implement and document the technical and procedural mechanisms
for logging physical entry at all access points to the Physical Security Perimeter(s) using one or
more of the following logging methods or their equivalent:
•
Computerized Logging: Electronic logs produced by the Responsible Entity’s selected
access control and monitoring method.
•
Video Recording: Electronic capture of video images of sufficient quality to determine
identity.
•
Manual Logging: A log book or sign-in sheet, or other record of physical access
maintained by security or other personnel authorized to control and monitor physical
access as specified in Requirement R4.
R7.
Access Log Retention — The Responsible Entity shall retain physical access logs for at least
ninety calendar days. Logs related to reportable incidents shall be kept in accordance with the
requirements of Standard CIP-008-3.
R8.
Maintenance and Testing — The Responsible Entity shall implement a maintenance and testing
program to ensure that all physical security systems under Requirements R4, R5, and R6
function properly. The program must include, at a minimum, the following:
R8.1.
Testing and maintenance of all physical security mechanisms on a cycle no longer
than three years.
R8.2.
Retention of testing and maintenance records for the cycle determined by the
Responsible Entity in Requirement R8.1.
R8.3.
Retention of outage records regarding access controls, logging, and monitoring for a
minimum of one calendar year.
C. Measures
M1. The Responsible Entity shall make available the physical security plan as specified in
Requirement R1 and documentation of the implementation, review and updating of the plan.
M2. The Responsible Entity shall make available documentation that the physical access control
systems are protected as specified in Requirement R2.
M3. The Responsible Entity shall make available documentation that the electronic access control
systems are located within an identified Physical Security Perimeter as specified in
Requirement R3.
M4. The Responsible Entity shall make available documentation identifying the methods for
controlling physical access to each access point of a Physical Security Perimeter as specified in
Requirement R4.
* Mandatory BC effective date October 16, 2011
* per BCUC Order G-162-11
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M5. The Responsible Entity shall make available documentation identifying the methods for
monitoring physical access as specified in Requirement R5.
M6. The Responsible Entity shall make available documentation identifying the methods for
logging physical access as specified in Requirement R6.
M7. The Responsible Entity shall make available documentation to show retention of access logs as
specified in Requirement R7.
M8. The Responsible Entity shall make available documentation to show its implementation of a
physical security system maintenance and testing program as specified in Requirement R8.
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Enforcement Authority
The British Columbia Utilities Commission
1.2. Compliance Monitoring Period and Reset Time Frame
Not applicable.
1.3. Compliance Monitoring and Enforcement Processes
Compliance Audits
Self-Certifications
Spot Checking
Compliance Violation Investigations
Self-Reporting
Complaints
1.4. Data Retention
1.4.1
The Responsible Entity shall keep documents other than those specified in
Requirements R7 and R8.2 from the previous full calendar year unless directed
by its Compliance Enforcement Authority to retain specific evidence for a longer
period of time as part of an investigation.
1.4.2
The Compliance Enforcement Authority in conjunction with the Registered
Entity shall keep the last audit records and all requested and submitted
subsequent audit records.
1.5. Additional Compliance Information
2.
1.5.1
The Responsible Entity may not make exceptions in its cyber security policy to
the creation, documentation, or maintenance of a physical security plan.
1.5.2
For dial-up accessible Critical Cyber Assets that use non-routable protocols, the
Responsible Entity shall not be required to comply with Standard CIP-006-3 for
that single access point at the dial-up device.
Violation Severity Levels (Under development by the CIP VSL Drafting Team)
E. Regional Variances
None identified.
* Mandatory BC effective date October 16, 2011
* per BCUC Order G-162-11
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Standard CIP-006-3c — Cyber Security — Physical Security
Version History
Version
Date
Action
2
Modifications to remove extraneous information from the
requirements, improve readability, and to bring the compliance
elements into conformance with the latest guidelines for
developing compliance elements of standards.
Replaced the RRO with RE as a responsible entity.
Modified CIP-006-1 Requirement R1 to clarify that a physical
security plan to protect Critical Cyber Assets must be
documented, maintained, implemented, and approved by the
senior manager.
Revised the wording in R1.2 to identify all “physical” access
points. Added Requirement R2 to CIP-006-2 to clarify the
requirement to safeguard the Physical Access Control Systems
and exclude hardware at the Physical Security Perimeter access
point, such as electronic lock control mechanisms and badge
readers from the requirement. Requirement R2.1 requires the
Responsible Entity to protect the Physical Access Control
Systems from unauthorized access. CIP-006-1 Requirement
R1.8 was moved to become CIP-006-2 Requirement R2.2.
Added Requirement R3 to CIP-006-2, clarifying the
requirement for Electronic Access Control Systems to be
safeguarded within an identified Physical Security Perimeter.
The sub requirements of CIP-006-2 Requirements R4, R5, and
R6 were changed from formal requirements to bulleted lists of
options consistent with the intent of the requirements.
Changed the Compliance Monitor to Compliance Enforcement
Authority.
3
Updated version numbers from -2 to -3
Revised Requirement 1.6 to add a Visitor Control program
component to the Physical Security Plan, in response to FERC
order issued September 30, 2009.
In Requirement R7, the term “Responsible Entity” was
capitalized.
Change Tracking
11/18/2009
Updated Requirements R1.6.1 and R1.6.2 to be responsive to
FERC Order RD09-7
3
12/16/09
Approved by NERC Board of Trustees
Update
1a
Board
approved
02/12/ 2008
Interpretation of R1 and Additional Compliance Information
Section 1.4.4 (Appendix 1)
Interpretation
(Project 2007-27)
1b/2b
Board
approved
08/05/2009
Interpretation of R4 (Appendix 2)
Interpretation
(Project 2008-15)
3c
Board
approved
02/16/2010
Interpretation of R1 and R1.1 (Appendix 3)
Interpretation
(Project 2009-13)
* Mandatory BC effective date October 16, 2011
* per BCUC Order G-162-11
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Standard CIP-006-3c — Cyber Security — Physical Security
Appendix 1
Interpretation of Requirement R1.1.
Request: Are dial-up RTUs that use non-routable protocols and have dial-up access required to have a six-wall
perimeters or are they exempted from CIP-006-1 and required to have only electronic security perimeters? This has
a direct impact on how any identified RTUs will be physically secured.
Interpretation:
Dial-up assets are Critical Cyber Assets, assuming they meet the criteria in CIP-002-1, and they must
reside within an Electronic Security Perimeter. However, physical security control over a critical cyber
asset is not required if that asset does not have a routable protocol. Since there is minimal risk of
compromising other critical cyber assets dial-up devices such as Remote Terminals Units that do not use
routable protocols are not required to be enclosed within a “six-wall” border.
CIP-006-1 — Requirement 1.1 requires a Responsible Entity to have a physical security plan that
stipulate cyber assets that are within the Electronic Security Perimeter also be within a Physical Security
Perimeter.
R1.
Physical Security Plan — The Responsible Entity shall create and maintain a physical
security plan, approved by a senior manager or delegate(s) that shall address, at a
minimum, the following:
R1.1. Processes to ensure and document that all Cyber Assets within an Electronic
Security Perimeter also reside within an identified Physical Security Perimeter.
Where a completely enclosed (“six-wall”) border cannot be established, the
Responsible Entity shall deploy and document alternative measures to control
physical access to the Critical Cyber Assets.
CIP-006-1 — Additional Compliance Information 1.4.4 identifies dial-up accessible assets that use
non-routable protocols as a special class of cyber assets that are not subject to the Physical Security
Perimeter requirement of this standard.
1.4.
Additional Compliance Information
1.4.4 For dial-up accessible Critical Cyber Assets that use non-routable protocols, the
Responsible Entity shall not be required to comply with Standard CIP-006 for that
single access point at the dial-up device.
* Mandatory BC effective date October 16, 2011
* per BCUC Order G-162-11
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Standard CIP-006-3c — Cyber Security — Physical Security
Appendix 2
The following interpretation of CIP-006-1a — Cyber Security — Physical Security of Critical Cyber
Assets, Requirement R4 was developed by the standard drafting team assigned to Project 2008-14 (Cyber
Security Violation Severity Levels) on October 23, 2008.
Request:
1. For physical access control to cyber assets, does this include monitoring when an individual
leaves the controlled access cyber area?
2. Does the term, “time of access” mean logging when the person entered the facility or does it
mean logging the entry/exit time and “length” of time the person had access to the critical asset?
Interpretation:
No, monitoring and logging of access are only required for ingress at this time. The term “time of access”
refers to the time an authorized individual enters the physical security perimeter.
Requirement Number and Text of Requirement
R4.
Logging Physical Access — Logging shall record sufficient information to uniquely
identify individuals and the time of access twenty-four hours a day, seven days a week.
The Responsible Entity shall implement and document the technical and procedural
mechanisms for logging physical entry at all access points to the Physical Security
Perimeter(s) using one or more of the following logging methods or their equivalent:
R4.1.
Computerized Logging: Electronic logs produced by the Responsible Entity’s
selected access control and monitoring method.
R4.2.
Video Recording: Electronic capture of video images of sufficient quality to
determine identity.
R4.3.
Manual Logging: A log book or sign-in sheet, or other record of physical access
maintained by security or other personnel authorized to control and monitor
physical access as specified in Requirement R2.3.
* Mandatory BC effective date October 16, 2011
* per BCUC Order G-162-11
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Appendix 3
Requirement Number and Text of Requirement
R1. Physical Security Plan — The Responsible Entity shall create and maintain a physical security
plan, approved by a senior manager or delegate(s) that shall address, at a minimum, the following:
R1.1. Processes to ensure and document that all Cyber Assets within an Electronic Security
Perimeter also reside within an identified Physical Security Perimeter. Where a completely
enclosed (“six-wall”) border cannot be established, the Responsible Entity shall deploy and
document alternative measures to control physical access to the Critical Cyber Assets.
Question
If a completely enclosed border cannot be created, what does the phrase, “to control physical access"
require? Must the alternative measure be physical in nature? If so, must the physical barrier literally
prevent physical access e.g. using concrete encased fiber, or can the alternative measure effectively
mitigate the risks associated with physical access through cameras, motions sensors, or encryption?
Does this requirement preclude the application of logical controls as an alternative measure in
mitigating the risks of physical access to Critical Cyber Assets?
Response
For Electronic Security Perimeter wiring external to a Physical Security Perimeter, the drafting team
interprets the Requirement R1.1 as not limited to measures that are “physical in nature.” The
alternative measures may be physical or logical, on the condition that they provide security equivalent
or better to a completely enclosed (“six-wall”) border. Alternative physical control measures may
include, but are not limited to, multiple physical access control layers within a non-public, controlled
space. Alternative logical control measures may include, but are not limited to, data encryption and/or
circuit monitoring to detect unauthorized access or physical tampering.
* Mandatory BC effective date October 16, 2011
* per BCUC Order G-162-11
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Standard CIP–007–3 — Cyber Security — Systems Security Management
A. Introduction
1.
Title:
Cyber Security — Systems Security Management
2.
Number:
CIP-007-3
3.
Purpose:
Standard CIP-007-3 requires Responsible Entities to define methods, processes,
and procedures for securing those systems determined to be Critical Cyber Assets, as well as
the other (non-critical) Cyber Assets within the Electronic Security Perimeter(s). Standard
CIP-007-3 should be read as part of a group of standards numbered Standards CIP-002-3
through CIP-009-3.
4.
Applicability:
4.1. Within the text of Standard CIP-007-3, “Responsible Entity” shall mean:
4.1.1
Reliability Coordinator.
4.1.2
Balancing Authority.
4.1.3
Interchange Authority.
4.1.4
Transmission Service Provider.
4.1.5
Transmission Owner.
4.1.6
Transmission Operator.
4.1.7
Generator Owner.
4.1.8
Generator Operator.
4.1.9
Load Serving Entity.
4.1.10 NERC.
4.1.11 Regional Entity.
4.2. The following are exempt from Standard CIP-007-3:
5.
4.2.1
Facilities regulated by the U.S. Nuclear Regulatory Commission or the Canadian
Nuclear Safety Commission.
4.2.2
Cyber Assets associated with communication networks and data communication
links between discrete Electronic Security Perimeters.
4.2.3
Responsible Entities that, in compliance with Standard CIP-002-3, identify that
they have no Critical Cyber Assets.
*Effective Date: The first day of the third calendar quarter after applicable regulatory
approvals have been received (or the Reliability Standard otherwise becomes effective the first
day of the third calendar quarter after BOT adoption in those jurisdictions where regulatory
approval is not required).
B. Requirements
R1.
Test Procedures — The Responsible Entity shall ensure that new Cyber Assets and significant
changes to existing Cyber Assets within the Electronic Security Perimeter do not adversely
affect existing cyber security controls. For purposes of Standard CIP-007-3, a significant
change shall, at a minimum, include implementation of security patches, cumulative service
packs, vendor releases, and version upgrades of operating systems, applications, database
platforms, or other third-party software or firmware.
Approved by Board of Trustees: December 16, 2009
* per BCUC Order G-162-11
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Standard CIP–007–3 — Cyber Security — Systems Security Management
R2.
R3.
R4.
R5.
R1.1.
The Responsible Entity shall create, implement, and maintain cyber security test
procedures in a manner that minimizes adverse effects on the production system or its
operation.
R1.2.
The Responsible Entity shall document that testing is performed in a manner that
reflects the production environment.
R1.3.
The Responsible Entity shall document test results.
Ports and Services — The Responsible Entity shall establish, document and implement a
process to ensure that only those ports and services required for normal and emergency
operations are enabled.
R2.1.
The Responsible Entity shall enable only those ports and services required for normal
and emergency operations.
R2.2.
The Responsible Entity shall disable other ports and services, including those used for
testing purposes, prior to production use of all Cyber Assets inside the Electronic
Security Perimeter(s).
R2.3.
In the case where unused ports and services cannot be disabled due to technical
limitations, the Responsible Entity shall document compensating measure(s) applied
to mitigate risk exposure.
Security Patch Management — The Responsible Entity, either separately or as a component of
the documented configuration management process specified in CIP-003-3 Requirement R6,
shall establish, document and implement a security patch management program for tracking,
evaluating, testing, and installing applicable cyber security software patches for all Cyber
Assets within the Electronic Security Perimeter(s).
R3.1.
The Responsible Entity shall document the assessment of security patches and
security upgrades for applicability within thirty calendar days of availability of the
patches or upgrades.
R3.2.
The Responsible Entity shall document the implementation of security patches. In
any case where the patch is not installed, the Responsible Entity shall document
compensating measure(s) applied to mitigate risk exposure.
Malicious Software Prevention — The Responsible Entity shall use anti-virus software and
other malicious software (“malware”) prevention tools, where technically feasible, to detect,
prevent, deter, and mitigate the introduction, exposure, and propagation of malware on all
Cyber Assets within the Electronic Security Perimeter(s).
R4.1.
The Responsible Entity shall document and implement anti-virus and malware
prevention tools. In the case where anti-virus software and malware prevention tools
are not installed, the Responsible Entity shall document compensating measure(s)
applied to mitigate risk exposure.
R4.2.
The Responsible Entity shall document and implement a process for the update of
anti-virus and malware prevention “signatures.” The process must address testing and
installing the signatures.
Account Management — The Responsible Entity shall establish, implement, and document
technical and procedural controls that enforce access authentication of, and accountability for,
all user activity, and that minimize the risk of unauthorized system access.
R5.1.
The Responsible Entity shall ensure that individual and shared system accounts and
authorized access permissions are consistent with the concept of “need to know” with
respect to work functions performed.
Approved by Board of Trustees: December 16, 2009
* per BCUC Order G-162-11
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Standard CIP–007–3 — Cyber Security — Systems Security Management
R5.1.1. The Responsible Entity shall ensure that user accounts are implemented as
approved by designated personnel. Refer to Standard CIP-003-3
Requirement R5.
R5.1.2. The Responsible Entity shall establish methods, processes, and procedures
that generate logs of sufficient detail to create historical audit trails of
individual user account access activity for a minimum of ninety days.
R5.1.3. The Responsible Entity shall review, at least annually, user accounts to
verify access privileges are in accordance with Standard CIP-003-3
Requirement R5 and Standard CIP-004-3 Requirement R4.
R5.2.
The Responsible Entity shall implement a policy to minimize and manage the scope
and acceptable use of administrator, shared, and other generic account privileges
including factory default accounts.
R5.2.1. The policy shall include the removal, disabling, or renaming of such
accounts where possible. For such accounts that must remain enabled,
passwords shall be changed prior to putting any system into service.
R5.2.2. The Responsible Entity shall identify those individuals with access to shared
accounts.
R5.2.3. Where such accounts must be shared, the Responsible Entity shall have a
policy for managing the use of such accounts that limits access to only those
with authorization, an audit trail of the account use (automated or manual),
and steps for securing the account in the event of personnel changes (for
example, change in assignment or termination).
R5.3.
At a minimum, the Responsible Entity shall require and use passwords, subject to the
following, as technically feasible:
R5.3.1. Each password shall be a minimum of six characters.
R5.3.2. Each password shall consist of a combination of alpha, numeric, and
“special” characters.
R5.3.3. Each password shall be changed at least annually, or more frequently based
on risk.
R6.
Security Status Monitoring — The Responsible Entity shall ensure that all Cyber Assets within
the Electronic Security Perimeter, as technically feasible, implement automated tools or
organizational process controls to monitor system events that are related to cyber security.
R6.1.
The Responsible Entity shall implement and document the organizational processes
and technical and procedural mechanisms for monitoring for security events on all
Cyber Assets within the Electronic Security Perimeter.
R6.2.
The security monitoring controls shall issue automated or manual alerts for detected
Cyber Security Incidents.
R6.3.
The Responsible Entity shall maintain logs of system events related to cyber security,
where technically feasible, to support incident response as required in Standard CIP008-3.
R6.4.
The Responsible Entity shall retain all logs specified in Requirement R6 for ninety
calendar days.
R6.5.
The Responsible Entity shall review logs of system events related to cyber security
and maintain records documenting review of logs.
Approved by Board of Trustees: December 16, 2009
* per BCUC Order G-162-11
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Standard CIP–007–3 — Cyber Security — Systems Security Management
R7.
R8.
R9.
Disposal or Redeployment — The Responsible Entity shall establish and implement formal
methods, processes, and procedures for disposal or redeployment of Cyber Assets within the
Electronic Security Perimeter(s) as identified and documented in Standard CIP-005-3.
R7.1.
Prior to the disposal of such assets, the Responsible Entity shall destroy or erase the
data storage media to prevent unauthorized retrieval of sensitive cyber security or
reliability data.
R7.2.
Prior to redeployment of such assets, the Responsible Entity shall, at a minimum,
erase the data storage media to prevent unauthorized retrieval of sensitive cyber
security or reliability data.
R7.3.
The Responsible Entity shall maintain records that such assets were disposed of or
redeployed in accordance with documented procedures.
Cyber Vulnerability Assessment — The Responsible Entity shall perform a cyber vulnerability
assessment of all Cyber Assets within the Electronic Security Perimeter at least annually. The
vulnerability assessment shall include, at a minimum, the following:
R8.1.
R8.2.
A document identifying the vulnerability assessment process;
A review to verify that only ports and services required for operation of the Cyber
Assets within the Electronic Security Perimeter are enabled;
R8.3.
R8.4.
A review of controls for default accounts; and,
Documentation of the results of the assessment, the action plan to remediate or
mitigate vulnerabilities identified in the assessment, and the execution status of that
action plan.
Documentation Review and Maintenance — The Responsible Entity shall review and update
the documentation specified in Standard CIP-007-3 at least annually. Changes resulting from
modifications to the systems or controls shall be documented within thirty calendar days of the
change being completed.
C. Measures
M1. The Responsible Entity shall make available documentation of its security test procedures as
specified in Requirement R1.
M2. The Responsible Entity shall make available documentation as specified in Requirement R2.
M3. The Responsible Entity shall make available documentation and records of its security patch
management program, as specified in Requirement R3.
M4. The Responsible Entity shall make available documentation and records of its malicious
software prevention program as specified in Requirement R4.
M5. The Responsible Entity shall make available documentation and records of its account
management program as specified in Requirement R5.
M6. The Responsible Entity shall make available documentation and records of its security status
monitoring program as specified in Requirement R6.
M7. The Responsible Entity shall make available documentation and records of its program for the
disposal or redeployment of Cyber Assets as specified in Requirement R7.
M8. The Responsible Entity shall make available documentation and records of its annual
vulnerability assessment of all Cyber Assets within the Electronic Security Perimeters(s) as
specified in Requirement R8.
M9. The Responsible Entity shall make available documentation and records demonstrating the
review and update as specified in Requirement R9.
Approved by Board of Trustees: December 16, 2009
* per BCUC Order G-162-11
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Standard CIP–007–3 — Cyber Security — Systems Security Management
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Enforcement Authority
The British Columbia Utilities Commission
1.2. Compliance Monitoring Period and Reset Time Frame
Not applicable.
1.3. Compliance Monitoring and Enforcement Processes
Compliance Audits
Self-Certifications
Spot Checking
Compliance Violation Investigations
Self-Reporting
Complaints
1.4. Data Retention
1.4.1
The Responsible Entity shall keep all documentation and records from the
previous full calendar year unless directed by its Compliance Enforcement
Authority to retain specific evidence for a longer period of time as part of an
investigation.
1.4.2
The Responsible Entity shall retain security–related system event logs for ninety
calendar days, unless longer retention is required pursuant to Standard CIP-008-3
Requirement R2.
1.4.3
The Compliance Enforcement Authority in conjunction with the Registered
Entity shall keep the last audit records and all requested and submitted
subsequent audit records.
1.5. Additional Compliance Information.
2.
Violation Severity Levels (To be developed later.)
E. Regional Variances
None identified.
Version History
Version
2
Date
Action
Change Tracking
Modifications to clarify the requirements and to
bring the compliance elements into conformance
with the latest guidelines for developing compliance
elements of standards.
Removal of reasonable business judgment and
acceptance of risk.
Revised the Purpose of this standard to clarify that
Standard CIP-007-2 requires Responsible Entities to
define methods, processes, and procedures for
securing Cyber Assets and other (non-Critical)
Approved by Board of Trustees: December 16, 2009
* per BCUC Order G-162-11
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Standard CIP–007–3 — Cyber Security — Systems Security Management
Assets within an Electronic Security Perimeter.
Replaced the RRO with the RE as a responsible
entity.
Rewording of Effective Date.
R9 changed ninety (90) days to thirty (30) days
Changed compliance monitor to Compliance
Enforcement Authority.
3
3
Updated version numbers from -2 to -3
12/16/09
Approved by the NERC Board of Trustees
Approved by Board of Trustees: December 16, 2009
* per BCUC Order G-162-11
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Standard CIP–008–3 — Cyber Security — Incident Reporting and Response Planning
A. Introduction
1.
Title:
Cyber Security — Incident Reporting and Response Planning
2.
Number:
CIP-008-3
3.
Purpose:
Standard CIP-008-3 ensures the identification, classification, response, and
reporting of Cyber Security Incidents related to Critical Cyber Assets. Standard CIP-008-23
should be read as part of a group of standards numbered Standards CIP-002-3 through CIP009-3.
4.
Applicability
4.1. Within the text of Standard CIP-008-3, “Responsible Entity” shall mean:
4.1.1
Reliability Coordinator.
4.1.2
Balancing Authority.
4.1.3
Interchange Authority.
4.1.4
Transmission Service Provider.
4.1.5
Transmission Owner.
4.1.6
Transmission Operator.
4.1.7
Generator Owner.
4.1.8
Generator Operator.
4.1.9
Load Serving Entity.
4.1.10 NERC.
4.1.11 Regional Entity.
4.2. The following are exempt from Standard CIP-008-3:
5.
4.2.1
Facilities regulated by the U.S. Nuclear Regulatory Commission or the Canadian
Nuclear Safety Commission.
4.2.2
Cyber Assets associated with communication networks and data communication
links between discrete Electronic Security Perimeters.
4.2.3
Responsible Entities that, in compliance with Standard CIP-002-3, identify that
they have no Critical Cyber Assets.
*Effective Date: The first day of the third calendar quarter after applicable regulatory
approvals have been received (or the Reliability Standard otherwise becomes effective the first
day of the third calendar quarter after BOT adoption in those jurisdictions where regulatory
approval is not required).
B. Requirements
R1.
Cyber Security Incident Response Plan — The Responsible Entity shall develop and maintain a
Cyber Security Incident response plan and implement the plan in response to Cyber Security
Incidents. The Cyber Security Incident response plan shall address, at a minimum, the
following:
R1.1.
Procedures to characterize and classify events as reportable Cyber Security Incidents.
R1.2.
Response actions, including roles and responsibilities of Cyber Security Incident
response teams, Cyber Security Incident handling procedures, and communication
plans.
Approved by Board of Trustees: December 16, 2009
* per BCUC Order G-162-11
1
ATTACHMENT C
to Order G-162-11
Page 33 of 143
Standard CIP–008–3 — Cyber Security — Incident Reporting and Response Planning
R2.
R1.3.
Process for reporting Cyber Security Incidents to the Electricity Sector Information
Sharing and Analysis Center (ES-ISAC). The Responsible Entity must ensure that all
reportable Cyber Security Incidents are reported to the ES-ISAC either directly or
through an intermediary.
R1.4.
Process for updating the Cyber Security Incident response plan within thirty calendar
days of any changes.
R1.5.
Process for ensuring that the Cyber Security Incident response plan is reviewed at
least annually.
R1.6.
Process for ensuring the Cyber Security Incident response plan is tested at least
annually. A test of the Cyber Security Incident response plan can range from a paper
drill, to a full operational exercise, to the response to an actual incident.
Cyber Security Incident Documentation — The Responsible Entity shall keep relevant
documentation related to Cyber Security Incidents reportable per Requirement R1.1 for three
calendar years.
C. Measures
M1. The Responsible Entity shall make available its Cyber Security Incident response plan as
indicated in Requirement R1 and documentation of the review, updating, and testing of the
plan.
M2. The Responsible Entity shall make available all documentation as specified in Requirement
R2.
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Enforcement Authority
The British Columbia Utilities Commission
1.2. Compliance Monitoring Period and Reset Time Frame
Not applicable.
1.3. Compliance Monitoring and Enforcement Processes
Compliance Audits
Self-Certifications
Spot Checking
Compliance Violation Investigations
Self-Reporting
Complaints
1.4. Data Retention
1.4.1
The Responsible Entity shall keep documentation other than that required for
reportable Cyber Security Incidents as specified in Standard CIP-008-3 for the
previous full calendar year unless directed by its Compliance Enforcement
Authority to retain specific evidence for a longer period of time as part of an
investigation.
Approved by Board of Trustees: December 16, 2009
* per BCUC Order G-162-11
2
ATTACHMENT C
to Order G-162-11
Page 34 of 143
Standard CIP–008–3 — Cyber Security — Incident Reporting and Response Planning
1.4.2
The Compliance Enforcement Authority in conjunction with the Registered
Entity shall keep the last audit records and all requested and submitted
subsequent audit records.
1.5. Additional Compliance Information
2.
1.5.1
The Responsible Entity may not take exception in its cyber security policies to
the creation of a Cyber Security Incident response plan.
1.5.2
The Responsible Entity may not take exception in its cyber security policies to
reporting Cyber Security Incidents to the ES ISAC.
Violation Severity Levels (To be developed later.)
E. Regional Variances
None identified.
Version History
Version
Date
Action
2
Modifications to clarify the requirements
and to bring the compliance elements into
conformance with the latest guidelines for
developing compliance elements of
standards.
Removal of reasonable business judgment.
Replaced the RRO with the RE as a
responsible entity.
Rewording of Effective Date.
Changed compliance monitor to
Compliance Enforcement Authority.
3
Updated Version number from -2 to -3
In Requirement 1.6, deleted the sentence
pertaining to removing component or
system from service in order to perform
testing, in response to FERC order issued
September 30, 2009.
3
12/16/09
Approved by NERC Board of Trustees
Approved by Board of Trustees: December 16, 2009
* per BCUC Order G-162-11
Change Tracking
Update
3
ATTACHMENT C
to Order G-162-11
Page 35 of 143
Standard CIP–009–3 — Cyber Security — Recovery Plans for Critical Cyber Assets
A. Introduction
1.
Title:
Cyber Security — Recovery Plans for Critical Cyber Assets
2.
Number:
CIP-009-3
3.
Purpose:
Standard CIP-009-3 ensures that recovery plan(s) are put in place for Critical
Cyber Assets and that these plans follow established business continuity and disaster recovery
techniques and practices. Standard CIP-009-3 should be read as part of a group of standards
numbered Standards CIP-002-3 through CIP-009-3.
4.
Applicability:
4.1. Within the text of Standard CIP-009-3, “Responsible Entity” shall mean:
4.1.1
Reliability Coordinator
4.1.2
Balancing Authority
4.1.3
Interchange Authority
4.1.4
Transmission Service Provider
4.1.5
Transmission Owner
4.1.6
Transmission Operator
4.1.7
Generator Owner
4.1.8
Generator Operator
4.1.9
Load Serving Entity
4.1.10 NERC
4.1.11 Regional Entity
4.2. The following are exempt from Standard CIP-009-3:
5.
4.2.1
Facilities regulated by the U.S. Nuclear Regulatory Commission or the Canadian
Nuclear Safety Commission.
4.2.2
Cyber Assets associated with communication networks and data communication
links between discrete Electronic Security Perimeters.
4.2.3
Responsible Entities that, in compliance with Standard CIP-002-3, identify that
they have no Critical Cyber Assets.
*Effective Date: The first day of the third calendar quarter after applicable regulatory
approvals have been received (or the Reliability Standard otherwise becomes effective the first
day of the third calendar quarter after BOT adoption in those jurisdictions where regulatory
approval is not required).
B. Requirements
R1. Recovery Plans — The Responsible Entity shall create and annually review recovery plan(s)
for Critical Cyber Assets. The recovery plan(s) shall address at a minimum the following:
R1.1.
Specify the required actions in response to events or conditions of varying duration
and severity that would activate the recovery plan(s).
R1.2.
Define the roles and responsibilities of responders.
R2. Exercises — The recovery plan(s) shall be exercised at least annually. An exercise of the
recovery plan(s) can range from a paper drill, to a full operational exercise, to recovery from an
actual incident.
Approved by Board of Trustees: December 16, 2009
* per BCUC Order G-162-11
1
ATTACHMENT C
to Order G-162-11
Page 36 of 143
Standard CIP–009–3 — Cyber Security — Recovery Plans for Critical Cyber Assets
R3. Change Control — Recovery plan(s) shall be updated to reflect any changes or lessons learned
as a result of an exercise or the recovery from an actual incident. Updates shall be
communicated to personnel responsible for the activation and implementation of the recovery
plan(s) within thirty calendar days of the change being completed.
R4. Backup and Restore — The recovery plan(s) shall include processes and procedures for the
backup and storage of information required to successfully restore Critical Cyber Assets. For
example, backups may include spare electronic components or equipment, written
documentation of configuration settings, tape backup, etc.
R5. Testing Backup Media — Information essential to recovery that is stored on backup media shall
be tested at least annually to ensure that the information is available. Testing can be completed
off site.
C. Measures
M1. The Responsible Entity shall make available its recovery plan(s) as specified in Requirement
R1.
M2. The Responsible Entity shall make available its records documenting required exercises as
specified in Requirement R2.
M3. The Responsible Entity shall make available its documentation of changes to the recovery
plan(s), and documentation of all communications, as specified in Requirement R3.
M4. The Responsible Entity shall make available its documentation regarding backup and storage
of information as specified in Requirement R4.
M5. The Responsible Entity shall make available its documentation of testing of backup media as
specified in Requirement R5.
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Enforcement Authority
The British Columbia Utilities Commission
1.2. Compliance Monitoring Period and Reset Time Frame
Not applicable.
1.3. Compliance Monitoring and Enforcement Processes
Compliance Audits
Self-Certifications
Spot Checking
Compliance Violation Investigations
Self-Reporting
Complaints
1.4. Data Retention
1.4.1
The Responsible Entity shall keep documentation required by Standard CIP-0093 from the previous full calendar year unless directed by its Compliance
Enforcement Authority to retain specific evidence for a longer period of time as
part of an investigation.
Approved by Board of Trustees: December 16, 2009
* per BCUC Order G-162-11
2
ATTACHMENT C
to Order G-162-11
Page 37 of 143
Standard CIP–009–3 — Cyber Security — Recovery Plans for Critical Cyber Assets
1.4.2
The Compliance Enforcement Authority in conjunction with the Registered
Entity shall keep the last audit records and all requested and submitted
subsequent audit records.
1.5. Additional Compliance Information
2.
Violation Severity Levels (To be developed later.)
E. Regional Variances
None identified.
Version History
Version
Date
Action
2
Modifications to clarify the requirements
and to bring the compliance elements into
conformance with the latest guidelines for
developing compliance elements of
standards.
Removal of reasonable business judgment.
Replaced the RRO with the RE as a
responsible entity.
Rewording of Effective Date.
Communication of revisions to the recovery
plan changed from 90 days to 30 days.
Changed compliance monitor to
Compliance Enforcement Authority.
3
Updated version numbers from -2 to -3
3
12/16/09
Approved by the NERC Board of Trustees
Approved by Board of Trustees: December 16, 2009
* per BCUC Order G-162-11
Change Tracking
Update
3
ATTACHMENT C
to Order G-162-11
Page 38 of 143
Standard FAC-010-2.1 — System Operating Limits Methodology for the Planning Horizon
A. Introduction
1.
Title:
System Operating Limits Methodology for the Planning Horizon
2.
Number:
FAC-010-2.1
3.
Purpose:
To ensure that System Operating Limits (SOLs) used in the reliable planning of
the Bulk Electric System (BES) are determined based on an established methodology or
methodologies.
4.
Applicability
4.1. Planning Authority
5.
*Effective Date:
April 19, 2010
B. Requirements
R1.
R2.
The Planning Authority shall have a documented SOL Methodology for use in developing
SOLs within its Planning Authority Area. This SOL Methodology shall:
R1.1.
Be applicable for developing SOLs used in the planning horizon.
R1.2.
State that SOLs shall not exceed associated Facility Ratings.
R1.3.
Include a description of how to identify the subset of SOLs that qualify as IROLs.
The Planning Authority’s SOL Methodology shall include a requirement that SOLs provide
BES performance consistent with the following:
R2.1.
In the pre-contingency state and with all Facilities in service, the BES shall
demonstrate transient, dynamic and voltage stability; all Facilities shall be within their
Facility Ratings and within their thermal, voltage and stability limits. In the
determination of SOLs, the BES condition used shall reflect expected system
conditions and shall reflect changes to system topology such as Facility outages.
R2.2.
Following the single Contingencies 1 identified in Requirement 2.2.1 through
Requirement 2.2.3, the system shall demonstrate transient, dynamic and voltage
stability; all Facilities shall be operating within their Facility Ratings and within their
thermal, voltage and stability limits; and Cascading or uncontrolled separation shall
not occur.
R2.2.1. Single line to ground or three-phase Fault (whichever is more severe), with
Normal Clearing, on any Faulted generator, line, transformer, or shunt
device.
R2.2.2. Loss of any generator, line, transformer, or shunt device without a Fault.
R2.2.3. Single pole block, with Normal Clearing, in a monopolar or bipolar high
voltage direct current system.
R2.3.
Starting with all Facilities in service, the system’s response to a single Contingency,
may include any of the following:
R2.3.1. Planned or controlled interruption of electric supply to radial customers or
some local network customers connected to or supplied by the Faulted
Facility or by the affected area.
1
The Contingencies identified in R2.2.1 through R2.2.3 are the minimum contingencies that must be studied but are
not necessarily the only Contingencies that should be studied.
Adopted by Board of Trustees: November 5, 2009
Effective Date: April 19, 2010
* per BCUC Order G-162-11
Page 1 of 9
ATTACHMENT C
to Order G-162-11
Page 39 of 143
Standard FAC-010-2 — System Operating Limits Methodology for the Planning Horizon
R2.3.2. System reconfiguration through manual or automatic control or protection
actions.
R2.4.
To prepare for the next Contingency, system adjustments may be made, including
changes to generation, uses of the transmission system, and the transmission system
topology.
R2.5.
Starting with all Facilities in service and following any of the multiple Contingencies
identified in Reliability Standard TPL-003 the system shall demonstrate transient,
dynamic and voltage stability; all Facilities shall be operating within their Facility
Ratings and within their thermal, voltage and stability limits; and Cascading or
uncontrolled separation shall not occur.
R2.6.
In determining the system’s response to any of the multiple Contingencies, identified
in Reliability Standard TPL-003, in addition to the actions identified in R2.3.1 and
R2.3.2, the following shall be acceptable:
R2.6.1. Planned or controlled interruption of electric supply to customers (load
shedding), the planned removal from service of certain generators, and/or
the curtailment of contracted Firm (non-recallable reserved) electric power
Transfers.
R3.
R4.
R5.
The Planning Authority’s methodology for determining SOLs, shall include, as a minimum, a
description of the following, along with any reliability margins applied for each:
R3.1.
Study model (must include at least the entire Planning Authority Area as well as the
critical modeling details from other Planning Authority Areas that would impact the
Facility or Facilities under study).
R3.2.
Selection of applicable Contingencies.
R3.3.
Level of detail of system models used to determine SOLs.
R3.4.
Allowed uses of Special Protection Systems or Remedial Action Plans.
R3.5.
Anticipated transmission system configuration, generation dispatch and Load level.
R3.6.
Criteria for determining when violating a SOL qualifies as an Interconnection
Reliability Operating Limit (IROL) and criteria for developing any associated IROL
Tv .
The Planning Authority shall issue its SOL Methodology, and any change to that methodology,
to all of the following prior to the effectiveness of the change:
R4.1.
Each adjacent Planning Authority and each Planning Authority that indicated it has a
reliability-related need for the methodology.
R4.2.
Each Reliability Coordinator and Transmission Operator that operates any portion of
the Planning Authority’s Planning Authority Area.
R4.3.
Each Transmission Planner that works in the Planning Authority’s Planning Authority
Area.
If a recipient of the SOL Methodology provides documented technical comments on the
methodology, the Planning Authority shall provide a documented response to that recipient
within 45 calendar days of receipt of those comments. The response shall indicate whether a
change will be made to the SOL Methodology and, if no change will be made to that SOL
Methodology, the reason why.
Adopted by Board of Trustees: November 5, 2009
Effective Date: April 19, 2010
* per BCUC Order G-162-11
Page 2 of 9
ATTACHMENT C
to Order G-162-11
Page 40 of 143
Standard FAC-010-2 — System Operating Limits Methodology for the Planning Horizon
C. Measures
M1. The Planning Authority’s SOL Methodology shall address all of the items listed in
Requirement 1 through Requirement 3.
M2. The Planning Authority shall have evidence it issued its SOL Methodology and any changes to
that methodology, including the date they were issued, in accordance with Requirement 4.
M3. If the recipient of the SOL Methodology provides documented comments on its technical
review of that SOL methodology, the Planning Authority that distributed that SOL
Methodology shall have evidence that it provided a written response to that commenter within
45 calendar days of receipt of those comments in accordance with Requirement 5.
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
Compliance Monitor: British Columbia Utilities Commission
Compliance Monitor’s Administrator: Western Electricity Coordinating Council
1.2. Compliance Monitoring Period and Reset Time Frame
Each Planning Authority shall self-certify its compliance to the Compliance Monitor at
least once every three years. New Planning Authorities shall demonstrate compliance
through an on-site audit conducted by the Compliance Monitor within the first year that it
commences operation. The Compliance Monitor shall also conduct an on-site audit once
every nine years and an investigation upon complaint to assess performance.
The Performance-Reset Period shall be twelve months from the last non-compliance.
1.3. Data Retention
The Planning Authority shall keep all superseded portions to its SOL Methodology for 12
months beyond the date of the change in that methodology and shall keep all documented
comments on its SOL Methodology and associated responses for three years. In addition,
entities found non-compliant shall keep information related to the non-compliance until
found compliant.
The Compliance Monitor shall keep the last audit and all subsequent compliance records.
1.4. Additional Compliance Information
The Planning Authority shall make the following available for inspection during an onsite audit by the Compliance Monitor or within 15 business days of a request as part of an
investigation upon complaint:
1.4.1
SOL Methodology.
1.4.2
Documented comments provided by a recipient of the SOL Methodology on its
technical review of a SOL Methodology, and the associated responses.
1.4.3
Superseded portions of its SOL Methodology that had been made within the past
12 months.
1.4.4
Evidence that the SOL Methodology and any changes to the methodology that
occurred within the past 12 months were issued to all required entities.
Adopted by Board of Trustees: November 5, 2009
Effective Date: April 19, 2010
* per BCUC Order G-162-11
Page 3 of 9
ATTACHMENT C
to Order G-162-11
Page 41 of 143
Standard FAC-010-2 — System Operating Limits Methodology for the Planning Horizon
2.
Levels of Non-Compliance for Western Interconnection: (To be replaced with VSLs once
developed and approved by WECC)
2.1. Level 1:
There shall be a level one non-compliance if either of the following
conditions exists:
2.1.1
The SOL Methodology did not include a statement indicating that Facility
Ratings shall not be exceeded.
2.1.2
No evidence of responses to a recipient’s comments on the SOL Methodology.
2.2. Level 2:
The SOL Methodology did not include a requirement to address all of the
elements in R2.1 through R2.3 and E1.
2.3. Level 3:
There shall be a level three non-compliance if any of the following
conditions exists:
2.3.1
The SOL Methodology did not include a statement indicating that Facility
Ratings shall not be exceeded and the methodology did not include evaluation of
system response to one of the three types of single Contingencies identified in
R2.2.
2.3.2
The SOL Methodology did not include a statement indicating that Facility
Ratings shall not be exceeded and the methodology did not include evaluation of
system response to two of the seven types of multiple Contingencies identified in
E1.1.
2.3.3
The System Operating Limits Methodology did not include a statement
indicating that Facility Ratings shall not be exceeded and the methodology did
not address two of the six required topics in R3.
2.4. Level 4:
with R4
The SOL Methodology was not issued to all required entities in accordance
Adopted by Board of Trustees: November 5, 2009
Effective Date: April 19, 2010
* per BCUC Order G-162-11
Page 4 of 9
ATTACHMENT C
to Order G-162-11
Page 42 of 143
Standard FAC-010-2 — System Operating Limits Methodology for the Planning Horizon
3.
Violation Severity Levels:
Requirement
Lower
Moderate
High
Severe
R1
Not applicable.
The Planning Authority has a
documented SOL Methodology
for use in developing SOLs
within its Planning Authority
Area, but it does not address
R1.2
The Planning Authority has a
documented SOL Methodology
for use in developing SOLs
within its Planning Authority
Area, but it does not address
R1.3.
The Planning Authority has a
documented SOL Methodology
for use in developing SOLs
within its Planning Authority
Area, but it does not address
R1.1.
OR
The Planning Authority has no
documented SOL Methodology
for use in developing SOLs
within its Planning Authority
Area.
R2
The Planning Authority’s SOL
Methodology requires that SOLs
are set to meet BES
performance following single and
multiple contingencies, but does
not address the pre-contingency
state (R2.1)
The Planning Authority’s SOL
Methodology requires that SOLs
are set to meet BES
performance in the precontingency state and following
single contingencies, but does
not address multiple
contingencies. (R2.5-R2.6)
The Planning Authority’s SOL
Methodology requires that SOLs
are set to meet BES
performance in the precontingency state and following
multiple contingencies, but does
not meet the performance for
response to single
contingencies. (R2.2 –R2.4)
The Planning Authority’s SOL
Methodology requires that SOLs
are set to meet BES
performance in the precontingency state but does not
require that SOLs be set to meet
the BES performance specified
for response to single
contingencies (R2.2-R2.4) and
does not require that SOLs be
set to meet the BES
performance specified for
response to multiple
contingencies. (R2.5-R2.6)
R3
The Planning Authority has a
methodology for determining
SOLs that includes a description
for all but one of the following:
R3.1 through R3.6.
The Planning Authority has a
methodology for determining
SOLs that includes a description
for all but two of the following:
R3.1 through R3.6.
The Planning Authority has a
methodology for determining
SOLs that includes a description
for all but three of the following:
R3.1 through R3.6.
The Planning Authority has a
methodology for determining
SOLs that is missing a
description of four or more of the
following: R3.1 through R3.6.
R4
One or both of the following:
The Planning Authority issued its
SOL Methodology and changes
One of the following:
The Planning Authority issued its
SOL Methodology and changes
One of the following:
The Planning Authority issued its
SOL Methodology and changes
One of the following:
The Planning Authority failed to
issue its SOL Methodology and
Adopted by Board of Trustees: November 5, 2009
Effective Date: April 19, 2010
* per BCUC Order G-162-11
Page 5 of 9
ATTACHMENT C
to Order G-162-11
Page 43 of 143
Standard FAC-010-2 — System Operating Limits Methodology for the Planning Horizon
Requirement
Lower
to that methodology to all but
one of the required entities.
For a change in methodology,
the changed methodology was
provided up to 30 calendar days
after the effectiveness of the
change.
Adopted by Board of Trustees: November 5, 2009
Effective Date: April 19, 2010
* per BCUC Order G-162-11
Moderate
to that methodology to all but
one of the required entities AND
for a change in methodology, the
changed methodology was
provided 30 calendar days or
more, but less than 60 calendar
days after the effectiveness of
the change.
OR
The Planning Authority issued its
SOL Methodology and changes
to that methodology to all but
two of the required entities AND
for a change in methodology, the
changed methodology was
provided up to 30 calendar days
after the effectiveness of the
change.
High
to that methodology to all but
one of the required entities AND
for a change in methodology, the
changed methodology was
provided 60 calendar days or
more, but less than 90 calendar
days after the effectiveness of
the change.
OR
The Planning Authority issued its
SOL Methodology and changes
to that methodology to all but
two of the required entities AND
for a change in methodology, the
changed methodology was
provided 30 calendar days or
more, but less than 60 calendar
days after the effectiveness of
the change.
OR
The Planning Authority issued its
SOL Methodology and changes
to that methodology to all but
three of the required entities
AND for a change in
methodology, the changed
methodology was provided up to
30 calendar days after the
effectiveness of the change.
Page 6 of 9
Severe
changes to that methodology to
more than three of the required
entities.
The Planning Authority issued its
SOL Methodology and changes
to that methodology to all but
one of the required entities AND
for a change in methodology, the
changed methodology was
provided 90 calendar days or
more after the effectiveness of
the change.
OR
The Planning Authority issued its
SOL Methodology and changes
to that methodology to all but
two of the required entities AND
for a change in methodology, the
changed methodology was
provided 60 calendar days or
more, but less than 90 calendar
days after the effectiveness of
the change.
OR
The Planning Authority issued its
SOL Methodology and changes
to that methodology to all but
three of the required entities
AND for a change in
methodology, the changed
methodology was provided 30
calendar days or more, but less
than 60 calendar days after the
effectiveness of the change.
The Planning Authority issued its
SOL Methodology and changes
to that methodology to all but
ATTACHMENT C
to Order G-162-11
Page 44 of 143
Standard FAC-010-2 — System Operating Limits Methodology for the Planning Horizon
Requirement
R5
Lower
Moderate
High
Severe
four of the required entities AND
for a change in methodology, the
changed methodology was
provided up to 30 calendar days
after the effectiveness of the
change.
The Planning Authority received
documented technical comments
on its SOL Methodology and
provided a complete response in
a time period that was longer
than 45 calendar days but less
than 60 calendar days.
The Planning Authority received
documented technical comments
on its SOL Methodology and
provided a complete response in
a time period that was 60
calendar days or longer but less
than 75 calendar days.
The Planning Authority received
documented technical comments
on its SOL Methodology and
provided a complete response in
a time period that was 75
calendar days or longer but less
than 90 calendar days.
OR
The Planning Authority’s
response to documented
technical comments on its SOL
Methodology indicated that a
change will not be made, but did
not include an explanation of
why the change will not be
made.
The Planning Authority received
documented technical comments
on its SOL Methodology and
provided a complete response in
a time period that was 90
calendar days or longer.
OR
The Planning Authority’s
response to documented
technical comments on its SOL
Methodology did not indicate
whether a change will be made
to the SOL Methodology.
Adopted by Board of Trustees: November 5, 2009
Effective Date: April 19, 2010
* per BCUC Order G-162-11
Page 7 of 9
ATTACHMENT C
to Order G-162-11
Page 45 of 143
Standard FAC-010-2 — System Operating Limits Methodology for the Planning Horizon
E. Regional Differences
1.
The following Interconnection-wide Regional Difference shall be applicable in the Western
Interconnection:
1.1. As governed by the requirements of R2.5 and R2.6, starting with all Facilities in service,
shall require the evaluation of the following multiple Facility Contingencies when
establishing SOLs:
1.1.1
Simultaneous permanent phase to ground Faults on different phases of each of
two adjacent transmission circuits on a multiple circuit tower, with Normal
Clearing. If multiple circuit towers are used only for station entrance and exit
purposes, and if they do not exceed five towers at each station, then this
condition is an acceptable risk and therefore can be excluded.
1.1.2
A permanent phase to ground Fault on any generator, transmission circuit,
transformer, or bus section with Delayed Fault Clearing except for bus
sectionalizing breakers or bus-tie breakers addressed in E1.1.7
1.1.3
Simultaneous permanent loss of both poles of a direct current bipolar Facility
without an alternating current Fault.
1.1.4
The failure of a circuit breaker associated with a Special Protection System to
operate when required following: the loss of any element without a Fault; or a
permanent phase to ground Fault, with Normal Clearing, on any transmission
circuit, transformer or bus section.
1.1.5
A non-three phase Fault with Normal Clearing on common mode Contingency of
two adjacent circuits on separate towers unless the event frequency is determined
to be less than one in thirty years.
1.1.6
A common mode outage of two generating units connected to the same
switchyard, not otherwise addressed by FAC-010.
1.1.7
The loss of multiple bus sections as a result of failure or delayed clearing of a bus
tie or bus sectionalizing breaker to clear a permanent Phase to Ground Fault.
1.2. SOLs shall be established such that for multiple Facility Contingencies in E1.1.1 through
E1.1.5 operation within the SOL shall provide system performance consistent with the
following:
1.2.1
All Facilities are operating within their applicable Post-Contingency thermal,
frequency and voltage limits.
1.2.2
Cascading does not occur.
1.2.3
Uncontrolled separation of the system does not occur.
1.2.4
The system demonstrates transient, dynamic and voltage stability.
1.2.5
Depending on system design and expected system impacts, the controlled
interruption of electric supply to customers (load shedding), the planned removal
from service of certain generators, and/or the curtailment of contracted firm (nonrecallable reserved) electric power transfers may be necessary to maintain the
overall security of the interconnected transmission systems.
1.2.6
Interruption of firm transfer, Load or system reconfiguration is permitted through
manual or automatic control or protection actions.
Adopted by Board of Trustees: November 5, 2009
Effective Date: April 19, 2010
* per BCUC Order G-162-11
Page 8 of 9
ATTACHMENT C
to Order G-162-11
Page 46 of 143
Standard FAC-010-2 — System Operating Limits Methodology for the Planning Horizon
1.2.7
To prepare for the next Contingency, system adjustments are permitted, including
changes to generation, Load and the transmission system topology when
determining limits.
1.3. SOLs shall be established such that for multiple Facility Contingencies in E1.1.6 through
E1.1.7 operation within the SOL shall provide system performance consistent with the
following with respect to impacts on other systems:
1.3.1
Cascading does not occur.
1.4. The Western Interconnection may make changes (performance category adjustments) to
the Contingencies required to be studied and/or the required responses to Contingencies
for specific facilities based on actual system performance and robust design. Such
changes will apply in determining SOLs.
Version History
Version
Date
Action
Change Tracking
1
November 1,
2006
Adopted by Board of Trustees
New
1
November 1,
2006
Fixed typo. Removed the word “each” from
the 1st sentence of section D.1.3, Data
Retention.
01/11/07
2
June 24, 2008
Adopted by Board of Trustees; FERC Order
705
Revised
Changed the effective date to July 1, 2008
Changed “Cascading Outage” to
“Cascading”
Replaced Levels of Non-compliance with
Violation Severity Levels
Revised
January 22,
2010
Updated effective date and footer to April
29, 2009 based on the March 20, 2009
FERC Order
Update
2.1
November 5,
2009
Adopted by the Board of Trustees — errata
change Section E1.1 modified to reflect the
renumbering of requirements R2.4 and R2.5
from FAC-010-1 to R2.5 and R2.6 in FAC010-2.
Errata
2.1
April 19, 2010
FERC Approved — errata change Section
E1.1 modified to reflect the renumbering of
requirements R2.4 and R2.5 from FAC-0101 to R2.5 and R2.6 in FAC-010-2.
Errata
2
2
Adopted by Board of Trustees: November 5, 2009
Effective Date: April 19, 2010
* per BCUC Order G-162-11
Page 9 of 9
ATTACHMENT C
to Order G-162-11
Page 47 of 143
Standard INT-005-3 — Interchange Authority Distributes Arranged Interchange
A. Introduction
1.
Title:
Interchange Authority Distributes Arranged Interchange
2.
Number:
INT-005-3
3.
Purpose: To ensure that the implementation of Interchange between Source and
Sink Balancing Authorities is distributed by an Interchange Authority such that
Interchange information is available for reliability assessments.
4.
Applicability:
4.1. Interchange Authority.
5.
*Effective Date:
July 1, 2010
B. Requirements
R1.
Prior to the expiration of the time period defined in the timing requirements tables in this
standard, Column A, the Interchange Authority shall distribute the Arranged Interchange
information for reliability assessment to all reliability entities involved in the Interchange.
R1.1.
When a Balancing Authority or Reliability Coordinator initiates a Curtailment to
Confirmed or Implemented Interchange for reliability, the Interchange Authority shall
distribute the Arranged Interchange information for reliability assessment only to the
Source Balancing Authority and the Sink Balancing Authority.
C. Measures
M1. For each Arranged Interchange, the Interchange Authority shall be able to provide evidence
that it has distributed the Arranged Interchange information to all reliability entities involved in
the Interchange within the applicable time frame.
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
Compliance Monitor: British Columbia Utilities Commission
Compliance Monitor’s Administrator: Western Electricity Coordinating Council
1.2. Compliance Monitoring Period and Reset Time Frame
The Performance-Reset Period shall be twelve months from the last noncompliance to Requirement 1.
1.3. Data Retention
The Interchange Authority shall keep 90 days of historical data. The Compliance
Monitor shall keep audit records for a minimum of three calendar years.
1.4. Additional Compliance Information
Each Interchange Authority shall demonstrate compliance to the Compliance
Monitor within the first year that this standard becomes effective or the first year
the entity commences operation by self-certification to the Compliance Monitor.
Subsequent to the initial compliance review, compliance may be:
1.4.1
Verified by audit at least once every three years.
Adopted by NERC Board of Trustees: October 29, 2008
Effective Date: July 1, 2010
* per BCUC Order G-162-11
Page 1 of 6
ATTACHMENT C
to Order G-162-11
Page 48 of 143
Standard INT-005-3 — Interchange Authority Distributes Arranged Interchange
1.4.2
Verified by spot checks in years between audits.
1.4.3
Verified by annual audits of noncompliant Interchange Authorities, until
compliance is demonstrated.
1.4.4
Verified at any time as the result of a specific complaint of failure to
perform R1. Complaints must be lodged within 60 days of the incident.
The Compliance Monitor will evaluate complaints.
Each Interchange Authority shall make the following available for inspection by
the Compliance Monitor upon request:
1.4.5
For compliance audits and spot checks, relevant data and system log
records for the audit period which indicate the Interchange Authority’s
distribution of all Arranged Interchange information to all reliability
entities involved in an Interchange. The Compliance Monitor may request
up to a three month period of historical data ending with the date the
request is received by the Interchange Authority.
1.4.6
For specific complaints, only those data and system log records associated
with the specific Interchange event contained in the complaint which
indicate that the Interchange Authority distributed the Arranged
Interchange information to all reliability entities involved in that specific
Interchange.
Levels of Non-Compliance
2.
One occurrence 1 of not distributing information to all involved
reliability entities as described in R1.
2.1. Level 1:
Two occurrences1 of not distributing information to all involved
reliability entities as described in R1.
2.2. Level 2:
Three occurrences1 of not distributing information to all involved
reliability entities as described in R1.
2.3. Level 3:
Four or more occurrences1 of not distributing information to all
involved reliability entities as described in R1 or no evidence provided.
2.4. Level 4:
E. Regional Differences
None
Version History
Version
Date
Action
Change Tracking
1
May 2, 2006
Approved by BOT
New
2
May 2, 2007
Approved by BOT
Revised
3
April 8, 2010
Approved by FERC, Effective July 1,
2010
1
This does not include instances of not distributing information due to extenuating circumstances approved by the
Compliance Monitor.
Adopted by NERC Board of Trustees: October 29, 2008
Effective Date: July 1, 2010
* per BCUC Order G-162-11
Page 2 of 6
ATTACHMENT C
to Order G-162-11
Page 49 of 143
Standard INT-005-3 — Interchange Authority Distributes Arranged Interchange
Timing Requirements for all Interconnections except WECC
Request for
Interchange
Submitted
Ramp
Start
Interchange Timeline with Minimum
Reliability-Related Response Times
A
B
C
D
If Arranged
Interchange (RFI) 2
is Submitted
IA Assigned
Time
Classification
IA Makes Initial
Distribution of
Arranged Interchange
BA and TSP Conduct
Reliability Assessments
IA Compiles and
Distributes Status
>1 hour after the RFI
start time
ATF
< 1 minute from RFI
submission
Entities have up to 2 hours
to respond.
< 1 minute from receipt of
all Reliability Assessments
NA
<15 minutes prior to
ramp start and <1
hour after the RFI
start time
Late
< 1 minute from RFI
submission
Entities have up to 10
minutes to respond.
< 1 minute from receipt of
all Reliability Assessments
< 3 minutes after receipt
of confirmed RFI
<1 hour and > 15
minutes prior to
ramp start
On-time
< 1 minute from RFI
submission
< 10 minutes from
Arranged Interchange
receipt from IA
< 1 minute from receipt of
all Reliability Assessments
> 3 minutes prior to
ramp start
>1 hour to < 4
hours prior to ramp
start
On-time
< 1 minute from RFI
submission
< 20 minutes from
Arranged Interchange
receipt from IA
< 1 minute from receipt of
all Reliability Assessments
> 39 minutes prior to
ramp start
> 4 hours prior to
ramp start
On-time
< 1 minute from RFI
submission
< 2 hours from Arranged
Interchange receipt from
IA
< 1 minute from receipt of
all Reliability Assessments
> 1 hour 58 minutes
prior to ramp start
2
BA Prepares
Confirmed Interchange
for Implementation
Time Classifications and deadlines apply to both initial Arranged Interchange submittal and any subsequent modifications to the Arranged Interchange.
Adopted by NERC Board of Trustees: October 29, 2008
* per BCUC Order G-162-11
Page 3 of 6
ATTACHMENT C
to Order G-162-11
Page 50 of 143
Standard INT-005-3 — Interchange Authority Distributes Arranged Interchange
Example of Timing Requirements for all Interconnections except WECC
Adopted by NERC Board of Trustees: October 29, 2008
* per BCUC Order G-162-11
Page 4 of 6
ATTACHMENT C
to Order G-162-11
Page 51 of 143
Standard INT-005-3 — Interchange Authority Distributes Arranged Interchange
Timing Requirements for WECC
A
B
IA Makes Initial
Distribution of
Arranged
Interchange
BA and TSP Conduct
Reliability Assessments
Entities have up to 2 hours to
respond.
If Arranged Interchange
(RFI) 3 is Submitted
IA Assigned
Time
Classification
>1 hour after the start time
ATF
< 1minute from RFI
submission
<10 minutes prior to ramp
start and <1 hour after the
start time
Late
< 1minute from RFI
submission
10 minutes prior to ramp
start
On-time
< 1minute from RFI
submission
11 minutes prior to ramp
start
On-time
12 minutes prior to ramp
start
C
D
IA Compiles and
Distributes Status
BA Prepares Confirmed
Interchange for
Implementation
< 1minute from receipt of
all Reliability Assessments
NA
< 1minute from receipt of
all Reliability Assessments
< 3 minutes after receipt
of confirmed RFI
< 5 minutes from Arranged
Interchange receipt from IA
< 1minute from receipt of
all Reliability Assessments
> 3 minutes prior to ramp
start
< 1minute from RFI
submission
< 6 minutes from Arranged
Interchange receipt from IA
< 1minute from receipt of
all Reliability Assessments
> 3 minutes prior to ramp
start
On-time
< 1minute from RFI
submission
< 7 minutes from Arranged
Interchange receipt from IA
< 1minute from receipt of
all Reliability Assessments
> 3 minutes prior to ramp
start
13 minutes prior to ramp
start
On-time
< 1minute from RFI
submission
< 8 minutes from Arranged
Interchange receipt from IA
< 1minute from receipt of
all Reliability Assessments
> 3 minutes prior to ramp
start
14 minutes prior to ramp
start
On-time
< 1minute from RFI
submission
< 9 minutes from Arranged
Interchange receipt from IA
< 1minute from receipt of
all Reliability Assessments
> 3 minutes prior to ramp
start
<1 hour and > 15 minutes
prior to ramp start
On-time
< 1minute from RFI
submission
< 10 minutes from Arranged
Interchange receipt from IA
< 1minute from receipt of
all Reliability Assessments
> 3 minutes prior to ramp
start
> 1hour and < 4 hours prior
to ramp start
On-time
< 1minute from RFI
submission
< 20 minutes from Arranged
interchange receipt from IA
< 1minute from receipt of
all Reliability Assessments
> 39 minutes prior to ramp
start
> 4 hours prior to ramp
start
On-time
< 1minute from RFI
submission
< 2 hours from Arranged
Interchange receipt from IA
< 1minute from receipt of
all Reliability Assessments
> 1 hour 58 minutes prior
to ramp start
Submitted before 10:00 PPT
with start time > 00:00 PPT
of following day
On-time
< 1minute from RFI
submission
By 12:00 PPT of day the
Arranged Interchange was
received by the IA
< 1minute from receipt of
all Reliability Assessments
> 1 hour 58 minutes prior
to ramp start
3
Entities have up to 10 minutes
to respond.
Time Classifications and deadlines apply to both initial Arranged Interchange submittal and any subsequent modifications to the Arranged Interchange.
Adopted by NERC Board of Trustees: October 29, 2008
* per BCUC Order G-162-11
Page 5 of 6
ATTACHMENT C
to Order G-162-11
Page 52 of 143
Standard INT-005-3 — Interchange Authority Distributes Arranged Interchange
Example of Timing Requirements for WECC
Adopted by NERC Board of Trustees: October 29, 2008
* per BCUC Order G-162-11
Page 6 of 6
ATTACHMENT C
to Order G-162-11
Page 53 of 143
Standard INT-006-3 — Response to Interchange Authority
A. Introduction
1.
Title:
Response to Interchange Authority
2.
Number:
INT-006-3
3.
Purpose:
To ensure that each Arranged Interchange is checked for reliability before it is
implemented.
4.
Applicability:
4.1. Balancing Authority.
4.2. Transmission Service Provider.
5.
*Effective Date:
July 1, 2010
B. Requirements
R1.
Prior to the expiration of the reliability assessment period defined in the timing requirements
tables in this standard, Column B, the Balancing Authority and Transmission Service Provider
shall respond to each On-time Request for Interchange (RFI), and to each Emergency RFI and
Reliability Adjustment RFI from an Interchange Authority to transition an Arranged
Interchange to a Confirmed Interchange. 1
R1.1.
Each involved Balancing Authority shall evaluate the Arranged Interchange with
respect to:
R1.1.1. Energy profile (ability to support the magnitude of the Interchange).
R1.1.2. Ramp (ability of generation maneuverability to accommodate).
R1.1.3. Scheduling path (proper connectivity of Adjacent Balancing Authorities).
R1.2.
Each involved Transmission Service Provider shall confirm that the transmission
service arrangements associated with the Arranged Interchange have adjacent
Transmission Service Provider connectivity, are valid and prevailing transmission
system limits will not be violated.
C. Measures
M1. The Balancing Authority and Transmission Service Provider shall each provide evidence that it
responded, relative to transitioning an Arranged Interchange to a Confirmed Interchange, to
each On–time Request for Interchange (RFI), and to each Emergency RFI or Reliability
Adjustment RFI from an Interchange Authority within the reliability assessment period defined
in the Timing Table, Column B. The Balancing Authority and Transmission Service Provider
need not provide evidence that it responded to any other requests.
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
Compliance Monitor: the British Columbia Utilities Commission
Compliance Monitor’s Administrator: the Western Electricity Coordinating Council
1
The Balancing Authority and Transmission Service Provider need not provide responses to any other requests.
Adopted by NERC Board of Trustee: October 29, 2008
Effective Date: July 1, 2010
* per BCUC Order G-162-11
Page 1 of 7
ATTACHMENT C
to Order G-162-11
Page 54 of 143
Standard INT-006-3 — Response to Interchange Authority
1.2. Compliance Monitoring Period and Reset Time Frame
The Performance-Reset Period shall be twelve months from the last non-compliance to
Requirement 1.
1.3. Data Retention
The Balancing Authority and Transmission Service Provider shall each keep 90 days of
historical data. The Compliance Monitor shall keep audit records for a minimum of three
calendar years.
1.4. Additional Compliance Information
The Balancing Authority and Transmission Service Provider shall demonstrate
compliance to the Compliance Monitor within the first year that this standard becomes
effective or the first year the entity commences operation by self-certification to the
Compliance Monitor.
Subsequent to the initial compliance review, compliance may be:
1.4.1
Verified by audit at least once every three years.
1.4.2
Verified by spot checks in years between audits.
1.4.3
Verified by annual audits of non-compliant Interchange Authorities, until
compliance is demonstrated.
1.4.4
Verified at any time as the result of a complaint. Complaints must be lodged
within 60 days of the incident. The Compliance Monitor will evaluate
complaints.
The Balancing Authority, and Transmission Service Provider shall make the
following available for inspection by the Compliance Monitor upon request:
2.
1.4.5
For compliance audits and spot checks, relevant data and system log records and
agreements for the audit period which indicate a reliability entity identified in R1
responded to all instances of the Interchange Authority’s communication under
Reliability Standard INT-005 Requirement 1 concerning the pending transition of
an Arranged Interchange to Confirmed Interchange. The Compliance Monitor
may request up to a three month period of historical data ending with the date the
request is received by the Balancing Authority, or Transmission Service
Provider.
1.4.6
For specific complaints, agreements and those data and system log records
associated with the specific Interchange event contained in the complaint which
indicates a reliability entity identified in R1 has responded to the Interchange
Authority’s communication under INT-005 R1 concerning the pending transition
of Arranged Interchange to Confirmed Interchange for that specific Interchange.
Levels of Non-Compliance
2.1. Level 1:
One occurrence 2 of not responding to the Interchange Authority as
described in R1.
2.2. Level 2:
Two occurrences1 of not responding to the Interchange Authority as
described in R1.
2
This does not include instances of not responding due to extenuating circumstances approved by the Compliance
Monitor.
Adopted by NERC Board of Trustee: October 29, 2008
Effective Date: July 1, 2010
* per BCUC Order G-162-11
Page 2 of 7
ATTACHMENT C
to Order G-162-11
Page 55 of 143
Standard INT-006-3 — Response to Interchange Authority
2.3. Level 3:
Three occurrences1 of not responding to the Interchange Authority as
described in R1.
2.4. Level 4:
Four or more occurrences1 of not responding to the Interchange Authority as
described in R1 or no evidence provided.
E. Regional Differences
None.
Version History
Version
Date
Action
Change Tracking
1
May 2, 2006
Approved by BOT
New
2
May 2, 2007
Approved by BOT
Revised
3
April 8, 2010
Approved by FERC, Effective July 1,
2010
Adopted by NERC Board of Trustee: October 29, 2008
Effective Date: July 1, 2010
* per BCUC Order G-162-11
Page 3 of 7
ATTACHMENT C
to Order G-162-11
Page 56 of 143
Standard INT-006-3 — Response to Interchange Authority
Timing Requirements for all Interconnections except WECC
Request for
Interchange
Submitted
Ramp
Start
Interchange Timeline with Minimum
Reliability-Related Response Times
A
B
C
D
If Arranged
Interchange (RFI) 3
is Submitted
IA Assigned
Time
Classification
IA Makes Initial
Distribution of
Arranged Interchange
BA and TSP Conduct
Reliability Assessments
IA Compiles and
Distributes Status
>1 hour after the RFI
start time
ATF
< 1 minute from RFI
submission
Entities have up to 2 hours
to respond.
< 1 minute from receipt of
all Reliability Assessments
NA
<15 minutes prior to
ramp start and <1
hour after the RFI
start time
Late
< 1 minute from RFI
submission
Entities have up to 10
minutes to respond.
< 1 minute from receipt of
all Reliability Assessments
< 3 minutes after receipt
of confirmed RFI
<1 hour and > 15
minutes prior to
ramp start
On-time
< 1 minute from RFI
submission
< 10 minutes from
Arranged Interchange
receipt from IA
< 1 minute from receipt of
all Reliability Assessments
> 3 minutes prior to
ramp start
>1 hour to < 4
hours prior to ramp
start
On-time
< 1 minute from RFI
submission
< 20 minutes from
Arranged Interchange
receipt from IA
< 1 minute from receipt of
all Reliability Assessments
> 39 minutes prior to
ramp start
> 4 hours prior to
ramp start
On-time
< 1 minute from RFI
submission
< 2 hours from Arranged
Interchange receipt from
IA
< 1 minute from receipt of
all Reliability Assessments
> 1 hour 58 minutes
prior to ramp start
3
BA Prepares
Confirmed Interchange
for Implementation
Time Classifications and deadlines apply to both initial Arranged Interchange submittal and any subsequent modifications to the Arranged Interchange.
Adopted by NERC Board of Trustee: October 29, 2008
Effective Date: July 1, 2010
* per BCUC Order G-162-11
Page 4 of 7
ATTACHMENT C
to Order G-162-11
Page 57 of 143
Standard INT-006-3 — Response to Interchange Authority
Example of Timing Requirements for all Interconnections except WECC
Adopted by NERC Board of Trustee: October 29, 2008
Effective Date: July 1, 2010
* per BCUC Order G-162-11
Page 5 of 7
ATTACHMENT C
to Order G-162-11
Page 58 of 143
Standard INT-006-3 — Response to Interchange Authority
Timing Requirements for WECC
A
B
IA Makes Initial
Distribution of
Arranged
Interchange
BA and TSP Conduct
Reliability Assessments
Entities have up to 2 hours to
respond.
If Arranged Interchange
(RFI) 4 is Submitted
IA Assigned
Time
Classification
>1 hour after the start time
ATF
< 1minute from RFI
submission
<10 minutes prior to ramp
start and <1 hour after the
start time
Late
< 1minute from RFI
submission
10 minutes prior to ramp
start
On-time
< 1minute from RFI
submission
11 minutes prior to ramp
start
On-time
12 minutes prior to ramp
start
C
D
IA Compiles and
Distributes Status
BA Prepares Confirmed
Interchange for
Implementation
< 1minute from receipt of
all Reliability Assessments
NA
< 1minute from receipt of
all Reliability Assessments
< 3 minutes after receipt
of confirmed RFI
< 5 minutes from Arranged
Interchange receipt from IA
< 1minute from receipt of
all Reliability Assessments
> 3 minutes prior to ramp
start
< 1minute from RFI
submission
< 6 minutes from Arranged
Interchange receipt from IA
< 1minute from receipt of
all Reliability Assessments
> 3 minutes prior to ramp
start
On-time
< 1minute from RFI
submission
< 7 minutes from Arranged
Interchange receipt from IA
< 1minute from receipt of
all Reliability Assessments
> 3 minutes prior to ramp
start
13 minutes prior to ramp
start
On-time
< 1minute from RFI
submission
< 8 minutes from Arranged
Interchange receipt from IA
< 1minute from receipt of
all Reliability Assessments
> 3 minutes prior to ramp
start
14 minutes prior to ramp
start
On-time
< 1minute from RFI
submission
< 9 minutes from Arranged
Interchange receipt from IA
< 1minute from receipt of
all Reliability Assessments
> 3 minutes prior to ramp
start
<1 hour and > 15 minutes
prior to ramp start
On-time
< 1minute from RFI
submission
< 10 minutes from Arranged
Interchange receipt from IA
< 1minute from receipt of
all Reliability Assessments
> 3 minutes prior to ramp
start
> 1hour and < 4 hours prior
to ramp start
On-time
< 1minute from RFI
submission
< 20 minutes from Arranged
interchange receipt from IA
< 1minute from receipt of
all Reliability Assessments
> 39 minutes prior to ramp
start
> 4 hours prior to ramp
start
On-time
< 1minute from RFI
submission
< 2 hours from Arranged
Interchange receipt from IA
< 1minute from receipt of
all Reliability Assessments
> 1 hour 58 minutes prior
to ramp start
Submitted before 10:00 PPT
with start time > 00:00 PPT
of following day
On-time
< 1minute from RFI
submission
By 12:00 PPT of day the
Arranged Interchange was
received by the IA
< 1minute from receipt of
all Reliability Assessments
> 1 hour 58 minutes prior
to ramp start
4
Entities have up to 10 minutes
to respond.
Time Classifications and deadlines apply to both initial Arranged Interchange submittal and any subsequent modifications to the Arranged Interchange.
Adopted by NERC Board of Trustee: October 29, 2008
Effective Date: July 1, 2010
* per BCUC Order G-162-11
Page 6 of 7
ATTACHMENT C
to Order G-162-11
Page 59 of 143
Standard INT-006-3 — Response to Interchange Authority
Example of Timing Requirements for WECC
Adopted by NERC Board of Trustee: October 29, 2008
Effective Date: July 1, 2010
* per BCUC Order G-162-11
Page 7 of 7
ATTACHMENT C
to Order G-162-11
Page 60 of 143
Standard INT-008-3 — Interchange Authority Distributes Status
A. Introduction
1.
Title:
Interchange Authority Distributes Status
2.
Number:
INT-008-3
3.
Purpose:
To ensure that the implementation of Interchange between Source and
Sink Balancing Authorities is coordinated by an Interchange Authority.
4.
Applicability:
4.1. Interchange Authority.
5.
*Effective Date:
July 1, 2010
B. Requirements
R1.
Prior to the expiration of the time period defined in the Timing Table, Column C, the
Interchange Authority shall distribute to all Balancing Authorities (including Balancing
Authorities on both sides of a direct current tie), Transmission Service Providers and
Purchasing-Selling Entities involved in the Arranged Interchange whether or not the
Arranged Interchange has transitioned to a Confirmed Interchange.
For Confirmed Interchange, the Interchange Authority shall also communicate:
R1.1.
R1.1.1. Start and stop times, ramps, and megawatt profile to Balancing
Authorities.
R1.1.2. Necessary Interchange information to NERC-identified reliability
analysis services.
C. Measures
M1. For each Arranged Interchange, the Interchange Authority shall provide evidence that it
has distributed the final status and Confirmed Interchange information specified in
Requirement 1 to all Balancing Authorities, Transmission Service Providers and
Purchasing-Selling Entities involved in the Arranged Interchange within the time
period defined in the Timing Table, Column C. If denied, the Interchange Authority
shall tell all involved parties that approval has been denied.
For each Arranged Interchange that includes a direct current tie, the
Interchange Authority shall provide evidence that it has communicated the
final status to the Balancing Authorities on both sides of the direct current tie,
even if the Balancing Authorities are neither the Source nor Sink for the
Interchange.
M1.1
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
Compliance Monitor: the British Columbia Utilities Commission
Compliance Monitor’s Administrator: the Western Electricity Coordinating Council
1.2. Compliance Monitoring Period and Reset Time Frame
Adopted by NERC Board of Trustees: October 29, 2008
Effective Date: July 1, 2010
* per BCUC Order G-162-11
Page 1 of 7
ATTACHMENT C
to Order G-162-11
Page 61 of 143
Standard INT-008-3 — Interchange Authority Distributes Status
The Performance-Reset Period shall be twelve months from the last noncompliance to R1.
1.3. Data Retention
The Interchange Authority shall keep 90 days of historical data. The Compliance
Monitor shall keep audit records for a minimum of three calendar years.
1.4. Additional Compliance Information
Each Interchange Authority shall demonstrate compliance to the Compliance
Monitor within the first year that this standard becomes effective or the first year
the entity commences operation by self-certification to the Compliance Monitor.
Subsequent to the initial compliance review, compliance will be:
1.4.1
Verified by audit at least once every three years.
1.4.2
Verified by spot checks in years between audits.
1.4.3
Verified by annual audits of noncompliant Interchange Authorities, until
compliance is demonstrated.
1.4.4
Verified at any time as the result of a complaint. Complaints must be
lodged within 60 days of the incident. Complaints will be evaluated by
the Compliance Monitor.
Each Interchange Authority shall make the following available for inspection by
the Compliance Monitor upon request:
2.
1.4.5
For compliance audits and spot checks, relevant data and system log
records for the audit period which indicate the Interchange Authority’s
distribution of all Arranged Interchange final status and Confirmed
Interchange information to all entities involved in an Interchange per R1.
The Compliance Monitor may request up to a three-month period of
historical data ending with the date the request is received by the
Interchange Authority
1.4.6
For specific complaints, only those data and system log records associated
with the specific Interchange event contained in the complaint which
indicate that the Interchange Authority distributed the Arranged
Interchange final status and Confirmed Interchange information to all
entities involved in that specific Interchange.
Levels of Non-Compliance
One occurrence 1 of not distributing final status and information as
described in R1.
2.1. Level 1:
1
This does not include instances of not distributing information due to extenuating circumstances approved by the
Compliance Monitor.
Adopted by NERC Board of Trustees: October 29, 2008
Effective Date: July 1, 2010
* per BCUC Order G-162-11
Page 2 of 7
ATTACHMENT C
to Order G-162-11
Page 62 of 143
Standard INT-008-3 — Interchange Authority Distributes Status
Two occurrences1 of not distributing final status and information as
described in R1.
2.2. Level 2:
Three occurrences1 of not distributing final status and information as
described in R1.
2.3. Level 3:
Four or more occurrences1 of not distributing final status and
information as described in R1 or no evidence provided.
2.4. Level 4:
E. Regional Differences
None.
Version History
Version
Date
Action
Change Tracking
1
May 2, 2006
Approved by BOT
New
2
May 2, 2007
Approved by BOT
Revised
3
April 8, 2010
Approved by FERC, Effective July 1,
2010
Adopted by NERC Board of Trustees: October 29, 2008
Effective Date: July 1, 2010
* per BCUC Order G-162-11
Page 3 of 7
ATTACHMENT C
to Order G-162-11
Page 63 of 143
Standard INT-008-3 — Interchange Authority Distributes Status
Timing Requirements for all Interconnections except WECC
Request for
Interchange
Submitted
Ramp
Start
Interchange Timeline with Minimum
Reliability-Related Response Times
A
B
C
D
If Arranged
Interchange (RFI) 2
is Submitted
IA Assigned
Time
Classification
IA Makes Initial
Distribution of
Arranged Interchange
BA and TSP Conduct
Reliability Assessments
IA Compiles and
Distributes Status
>1 hour after the RFI
start time
ATF
< 1 minute from RFI
submission
Entities have up to 2 hours
to respond.
< 1 minute from receipt of
all Reliability Assessments
NA
<15 minutes prior to
ramp start and <1
hour after the RFI
start time
Late
< 1 minute from RFI
submission
Entities have up to 10
minutes to respond.
< 1 minute from receipt of
all Reliability Assessments
< 3 minutes after receipt
of confirmed RFI
<1 hour and > 15
minutes prior to
ramp start
On-time
< 1 minute from RFI
submission
< 10 minutes from
Arranged Interchange
receipt from IA
< 1 minute from receipt of
all Reliability Assessments
> 3 minutes prior to
ramp start
>1 hour to < 4
hours prior to ramp
start
On-time
< 1 minute from RFI
submission
< 20 minutes from
Arranged Interchange
receipt from IA
< 1 minute from receipt of
all Reliability Assessments
> 39 minutes prior to
ramp start
> 4 hours prior to
ramp start
On-time
< 1 minute from RFI
submission
< 2 hours from Arranged
Interchange receipt from
IA
< 1 minute from receipt of
all Reliability Assessments
> 1 hour 58 minutes
prior to ramp start
2
BA Prepares
Confirmed Interchange
for Implementation
Time Classifications and deadlines apply to both initial Arranged Interchange submittal and any subsequent modifications to the Arranged Interchange.
Adopted by NERC Board of Trustees: October 29, 2008
Effective Date: July 1, 2010
* per BCUC Order G-162-11
Page 4 of 7
ATTACHMENT C
to Order G-162-11
Page 64 of 143
Standard INT-008-3 — Interchange Authority Distributes Status
Example of Timing Requirements for all Interconnections except WECC
Adopted by NERC Board of Trustees: October 29, 2008
Effective Date: July 1, 2010
* per BCUC Order G-162-11
Page 5 of 7
ATTACHMENT C
to Order G-162-11
Page 65 of 143
Standard INT-008-3 — Interchange Authority Distributes Status
Timing Requirements for WECC
A
B
IA Makes Initial
Distribution of
Arranged
Interchange
BA and TSP Conduct
Reliability Assessments
Entities have up to 2 hours to
respond.
If Arranged Interchange
(RFI) 3 is Submitted
IA Assigned
Time
Classification
>1 hour after the start time
ATF
< 1minute from RFI
submission
<10 minutes prior to ramp
start and <1 hour after the
start time
Late
< 1minute from RFI
submission
10 minutes prior to ramp
start
On-time
< 1minute from RFI
submission
11 minutes prior to ramp
start
On-time
12 minutes prior to ramp
start
C
D
IA Compiles and
Distributes Status
BA Prepares Confirmed
Interchange for
Implementation
< 1minute from receipt of
all Reliability Assessments
NA
< 1minute from receipt of
all Reliability Assessments
< 3 minutes after receipt
of confirmed RFI
< 5 minutes from Arranged
Interchange receipt from IA
< 1minute from receipt of
all Reliability Assessments
> 3 minutes prior to ramp
start
< 1minute from RFI
submission
< 6 minutes from Arranged
Interchange receipt from IA
< 1minute from receipt of
all Reliability Assessments
> 3 minutes prior to ramp
start
On-time
< 1minute from RFI
submission
< 7 minutes from Arranged
Interchange receipt from IA
< 1minute from receipt of
all Reliability Assessments
> 3 minutes prior to ramp
start
13 minutes prior to ramp
start
On-time
< 1minute from RFI
submission
< 8 minutes from Arranged
Interchange receipt from IA
< 1minute from receipt of
all Reliability Assessments
> 3 minutes prior to ramp
start
14 minutes prior to ramp
start
On-time
< 1minute from RFI
submission
< 9 minutes from Arranged
Interchange receipt from IA
< 1minute from receipt of
all Reliability Assessments
> 3 minutes prior to ramp
start
<1 hour and > 15 minutes
prior to ramp start
On-time
< 1minute from RFI
submission
< 10 minutes from Arranged
Interchange receipt from IA
< 1minute from receipt of
all Reliability Assessments
> 3 minutes prior to ramp
start
> 1hour and < 4 hours prior
to ramp start
On-time
< 1minute from RFI
submission
< 20 minutes from Arranged
interchange receipt from IA
< 1minute from receipt of
all Reliability Assessments
> 39 minutes prior to ramp
start
> 4 hours prior to ramp
start
On-time
< 1minute from RFI
submission
< 2 hours from Arranged
Interchange receipt from IA
< 1minute from receipt of
all Reliability Assessments
> 1 hour 58 minutes prior
to ramp start
Submitted before 10:00 PPT
with start time > 00:00 PPT
of following day
On-time
< 1minute from RFI
submission
By 12:00 PPT of day the
Arranged Interchange was
received by the IA
< 1minute from receipt of
all Reliability Assessments
> 1 hour 58 minutes prior
to ramp start
3
Entities have up to 10 minutes
to respond.
Time Classifications and deadlines apply to both initial Arranged Interchange submittal and any subsequent modifications to the Arranged Interchange.
Adopted by NERC Board of Trustees: October 29, 2008
Effective Date: July 1, 2010
* per BCUC Order G-162-11
Page 6 of 7
ATTACHMENT C
to Order G-162-11
Page 66 of 143
Standard INT-008-3 — Interchange Authority Distributes Status
Example of Timing Requirements for WECC
Adopted by NERC Board of Trustees: October 29, 2008
Effective Date: July 1, 2010
* per BCUC Order G-162-11
Page 7 of 7
ATTACHMENT C
to Order G-162-11
Page 67 of 143
Standard IRO-006-4.1 — Reliability Coordination — Transmission Loading Relief
A. Introduction
1.
Title:
Reliability Coordination — Transmission Loading Relief (TLR)
2.
Number:
IRO-006-4.1
3.
Purpose:
The purpose of this standard is to provide Interconnection-wide transmission
loading relief procedures that can be used to prevent or manage potential or actual SOL and
IROL violations to maintain reliability of the Bulk Electric System.
4.
Applicability:
4.1. Reliability Coordinators.
4.2. Transmission Operators.
4.3. Balancing Authorities.
5.
*Effective Date:
December 10, 2009
B. Requirements
R1.
A Reliability Coordinator experiencing a potential or
This requirement simply states; the
actual SOL or IROL violation within its Reliability
RC has the authority to act, the RC
Coordinator Area shall, with its authority and at its
should know at what limits he/she
discretion, select one or more procedures to provide
needs to act, the RC has pretransmission loading relief. These procedures can be a
identified regional, interregional and
“local” (regional, interregional, or sub-regional)
sub-regional TLR procedures.
transmission loading relief procedure or one of the
following Interconnection-wide procedures: [Violation Risk Factor: Medium] [Time Horizon:
Real-time Operations]
R1.1.
The Interconnection-wide Transmission Loading
Comment: see FERC Order 693
Relief (TLR) procedure for use in the Eastern
paragraph 964 regarding
Interconnection provided in Attachment 1-IROrecommendation for using tools
006-4. The TLR procedure alone is an
other than TLR to mitigate an
inappropriate and ineffective tool to mitigate an
actual IROL.
IROL violation due to the time required to
implement the procedure. Other acceptable and more effective procedures to mitigate
actual IROL violations include: reconfiguration, redispatch, or load shedding.
R1.2.
The Interconnection-wide transmission loading relief procedure for use in the Western
Interconnection is the WECC Unscheduled Flow Reduction Procedure provided at:
http://www.wecc.biz/documents/library/UFAS/UFAS_mitigation_plan_rev_2001clean_8-8-03.pdf.
R1.3.
The Interconnection-wide transmission loading relief
procedure for use in ERCOT is provided as Section 7 of the
ERCOT Protocols, posted at:
http://www.ercot.com/mktrules/protocols/current.html
Note: the URL has
changed.
R2.
The Reliability Coordinator shall only use local transmission loading relief or congestion
management procedures to which the Transmission Operator experiencing the potential or
actual SOL or IROL violation is a party. [Violation Risk Factor: Low] [Time Horizon:
Operations Planning]
R3.
Each Reliability Coordinator with a relief obligation from an Interconnection-wide procedure
shall follow the curtailments as directed by the Interconnection-wide procedure. A Reliability
Coordinator desiring to use a local procedure as a substitute for curtailments as directed by the
Approved by Board of Trustees: April 15, 2009
Effective Date: December 10, 2009
* per BCUC Order G-162-11
Page 1 of 35
ATTACHMENT C
to Order G-162-11
Page 68 of 143
Standard IRO-006-4.1 — Reliability Coordination — Transmission Loading Relief
Interconnection-wide procedure shall obtain prior approval of the local procedure from the
ERO. [Violation Risk Factor: Low] [Time Horizon: Operations Planning]
R4.
When Interconnection-wide procedures are implemented to curtail Interchange Transactions
that cross an Interconnection boundary, each Reliability Coordinator shall comply with the
provisions of the Interconnection-wide procedure. [Violation Risk Factor: Medium] [Time
Horizon: Real-time Operations]
R5.
During the implementation of relief procedures, and
up to the point that emergency action is necessary,
Reliability Coordinators and Balancing Authorities
shall comply with applicable Interchange
scheduling standards. [Violation Risk Factor:
Medium] [Time Horizon: Real-time Operations]
Comment: R5 will be reviewed during
Phase 3 of the TLR drafting team work.
See white paper for explanation of the
three phases of changes to this standard.
C. Measures
M1. Each Reliability Coordinator shall be capable of providing evidence (such as logs) that
demonstrate when Eastern Interconnection, WECC, or ERCOT Interconnection-wide
transmission loading relief procedures are implemented, the implementation follows the
respective established procedure as specified in this standard (R1, R1.1, R1.2 and R1.3).
M2. Each Reliability Coordinator shall be capable of providing evidence (such as written
documentation) that the Transmission Operator experiencing the potential or existing SOL or
IROL violations is a party to the local transmission loading relief or congestion management
procedures when these procedures have been implemented (R2).
M3. Each Reliability Coordinator shall be capable of providing evidence (such as NERC meeting
minutes) that the local procedure has received prior approval by the ERO when such procedure
is used as a substitute for curtailment as directed by the Interconnection-wide procedure (R3).
M4. Each Reliability Coordinator shall be capable of providing evidence (such as logs) that the
responding Reliability Coordinator complied with the provisions of the Interconnection-wide
procedure as requested by the initiating Reliability Coordinator when requested to curtail an
Interchange Transaction that crosses an Interconnection boundary (R4).
M5. Each Reliability Coordinator and Balancing Authority shall be capable of providing evidence
(such as Interchange Transaction Tags, operator logs, voice recordings or transcripts of voice
recordings, electronic communications, computer printouts) that they have complied with
applicable Interchange scheduling standards INT-001, INT-003, and INT-004 during the
implementation of relief procedures, up to the point emergency action is necessary (R5).
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
Compliance Monitor: the British Columbia Utilities Commission
Compliance Monitor’s Administrator: the Western Electricity Coordinating Council
1.2. Compliance Monitoring Period and Reset Time Frame
Compliance Monitoring Period: One calendar year.
Reset Period: One month without a violation.
1.3. Data Retention
Approved by Board of Trustees: April 15, 2009
Effective Date: December 10, 2009
* per BCUC Order G-162-11
Page 2 of 35
ATTACHMENT C
to Order G-162-11
Page 69 of 143
Standard IRO-006-4.1 — Reliability Coordination — Transmission Loading Relief
The Reliability Coordinator shall maintain evidence for eighteen months for M1, M4, and
M5.
The Reliability Coordinator shall maintain evidence for the duration the Transmission
Operator is party to the procedure in effect plus one calendar year thereafter for M2.
The Reliability Coordinator shall maintain evidence for the approved duration of the
procedure in effect plus one calendar year thereafter for M3.
1.4. Additional Compliance Information
Each Reliability Coordinator and Balancing Authority shall demonstrate compliance
through self-certification submitted to its Compliance Monitor annually and reporting by
exception. The Compliance Monitor may also use scheduled on-site reviews every three
years, and investigations upon complaint, to assess performance.
Each Reliability Coordinator and Balancing Authority shall have the following available
for its Compliance Monitor to inspect during a scheduled, on-site review or within 5 days
of a request as part of an investigation upon complaint:
2.
1.4.1
Operations logs, voice recordings or transcripts of voice recordings or other
documentation providing the evidence of its compliance to all the requirements
for all Interconnection-wide TLR procedures that it has implemented during the
review period.
1.4.2
TLR reports.
Violation Severity Levels
2.1. Lower. There shall be a lower violation severity level if any of the following
conditions exist:
2.1.1
For each TLR in the Eastern Interconnection, the Reliability Coordinator violates
one (1) requirement of the applicable Interconnection-wide procedure (R1)
2.1.2
The Reliability Coordinators or Balancing Authorities did not comply with
applicable Interchange scheduling standards during the implementation of the
relief procedures, up to the point emergency action is necessary (R5).
2.1.3
When requested to curtail an Interchange Transaction that crosses an
Interconnection boundary utilizing an Interconnection-wide procedure, the
responding Reliability Coordinator did not comply with the provisions of the
Interconnection-wide procedure as requested by the initiating Reliability
Coordinator (R4).
2.2. Moderate. There shall be a moderate violation severity level if any of the following
conditions exist:
2.2.1
For each TLR in the Eastern Interconnection, the Reliability Coordinator violated
two (2) to three (3) requirements of the applicable Interconnection-wide
procedure (R1).
2.3. High. There shall be a high violation severity level if any of the following conditions
exist:
2.3.1
For each TLR in the Eastern Interconnection, the applicable Reliability
Coordinator violated four (4) to five (5) requirements of the applicable
Interconnection-wide procedure (R1).
Approved by Board of Trustees: April 15, 2009
Effective Date: December 10, 2009
* per BCUC Order G-162-11
Page 3 of 35
ATTACHMENT C
to Order G-162-11
Page 70 of 143
Standard IRO-006-4.1 — Reliability Coordination — Transmission Loading Relief
2.4. Severe. There shall be a severe violation severity level if any of the following
conditions exist:
2.4.1
For each TLR in the Eastern Interconnection, the Reliability Coordinator violated
six (6) or more of the requirements of the applicable Interconnection-wide
procedure (R1).
2.4.2
A Reliability Coordinator implemented local transmission loading relief or
congestion management procedures to relieve congestion but the Transmission
Operator experiencing the congestion was not a party to those procedures (R2).
2.4.3
A Reliability Coordinator implemented local transmission loading relief or
congestion management procedures as a substitute for curtailment as directed by
the Interconnection-wide procedure but the local procedure had not received
prior approval from the ERO (R3).
2.4.4
While attempting to mitigate an existing IROL violation in the Eastern
Interconnection, the Reliability Coordinator applied TLR as the sole remedy for
an existing IROL violation.
2.4.5
While attempting to mitigate an existing constraint in the Western
Interconnection using the “WSCC Unscheduled Flow Mitigation Plan”, the
Reliability Coordinator did not follow the procedure correctly.
2.4.6
While attempting to mitigate an existing constraint in ERCOT using Section 7 of
the ERCOT Protocols, the Reliability Coordinator did not follow the procedure
correctly.
E. Regional Differences
1.
PJM/MISO Enhanced Congestion Management
(Curtailment/Reload/Reallocation) Waiver approved
March 25, 2004. To be retired upon completion of the
field test, and in the interim the Regional Difference will
be contained in both the NERC and NAESB standards.
2.
Southwest Power Pool (SPP) Regional Difference –
Enhanced Congestion Management (Curtailment/Reload/Reallocation). The SPP regional
difference, which is equivalent to the PJM/MISO waiver, shall apply within the SPP region as
follows:
This section on Regional
Differences is highlighted for
transfer to NAESB following
completion of the MISO/PJM/SPP
field test as described in the white
paper.
This regional difference impacts actions on behalf of those SPP Balancing Authorities that are
participating in the SPP market. This regional difference does not impact those Balancing
Authorities for which SPP will continue to act as the Reliability Coordinator but that are not
participating in the SPP market.
SPP shall calculate the impacts of SPP market flow on all facilities included in SPP’s
Coordinated Flowgate List. SPP shall conduct sensitivity studies to determine which external
flowgates (outside SPP’s footprint) are significantly impacted by the market flows of SPP’s
control zones (currently the balancing areas that exist today in the IDC). SPP shall perform
studies to determine which external flowgates SPP will monitor and help control. An external
flowgate selected by one of the studies will be considered a Coordinated Flowgate (CF).
In its calculation, SPP shall consider market flow impacts as the impacts of energy dispatched
by the SPP market and self-dispatched energy serving load in the market footprint, but not
tagged. SPP shall use a method equivalent to the PJM/MISO Market Flow Calculation
methodology identified in the PJM/MISO waiver. Impacts of tagged transactions representing
Approved by Board of Trustees: April 15, 2009
Effective Date: December 10, 2009
* per BCUC Order G-162-11
Page 4 of 35
ATTACHMENT C
to Order G-162-11
Page 71 of 143
Standard IRO-006-4.1 — Reliability Coordination — Transmission Loading Relief
delivery of energy not dispatched by the SPP market and energy dispatched by the market but
delivered outside the footprint will not be included in market flow.
SPP shall separate the market flow impacts for current hour and next hour into their
appropriate priorities and shall provide those market flow impacts to the IDC. The market
flows will be represented in the IDC and made available for curtailment under the appropriate
TLR Levels. The market flow impacts will not be represented by conventional interchange
transaction tags.
The SPP method will impact the following sections of the TLR Procedure:
Network and Native Load (NNL) Calculations ⎯ The SPP regional difference modifies
Attachment 1-IRO-006-1 Section 5 “Parallel Flow Calculation Procedure for Reallocating or
Curtailing Firm Transmission Service” within the SPP region.
Section 5 of Attachment 1-IRO-006-1 requires that the “Per Generator Method without
Counter Flow” methodology be utilized to calculate the portion of parallel flows on any
Constrained Facility due to Network Integration (NI) transmission service and service to
Native Load (NL) of each balancing authority.
SPP shall use a “Market Flow Calculation” methodology to calculate the portion of parallel
flows on all facilities included in the RTO’s “Coordinated Flowgate List” due to NI service or
service to NL of each balancing authority.
The Market Flow Calculation differs from the Per Generator Method in the following ways:
−
The contribution from all market area generators will be taken into account.
−
In the Per Generator Method, only generators having a GLDF greater than 5% are
included in the calculation. Additionally, generators are included only when the sum
of the maximum generating capacity at a bus is greater than 20 MW. The market
flow calculations will use all positively impacting flows down to 0% with no
threshold. Counter flows will not be included in the market flow calculation.
−
The contribution of all market area generators is based on the present output level of
each individual unit.
−
The contribution of the market area load is based on the present demand at each
individual bus.
By expanding on the Per Generator Method, the market flow calculation evolves into a
methodology very similar to the “Per Generator Method” method, while providing increased
Interchange Distribution Calculator (IDC) granularity. Counter flows are also calculated and
tracked in order to account for and recognize that the either the positive market flows may be
reduced or counter flows may be increased to provide appropriate relief on a flowgate.
These NNL values will be provided to the IDC to be included and represented with the
calculated NNL values of other Balancing Authorities for the purposes of identifying and
obtaining required NNL relief across a flowgate in congestion under a TLR Level 5A/5B.
Pro Rata Curtailment of Non-Firm Market Flow Impacts ⎯ The SPP regional difference
modifies Attachment 1-IRO-006-1 Appendix B “Transaction Curtailment Formula” within the
SPP region.
Appendix B “Transaction Curtailment Formula” details the formula used to apply a weighted
impact to each non-firm tagged Interchange Transaction (Priorities 1 thru 6) for the purposes of
Curtailment by the IDC. For the purpose of Curtailment, the non-firm market flow impacts
(Priorities 2 and 6) submitted to the IDC by SPP should be curtailed pro-rata as is done for
Approved by Board of Trustees: April 15, 2009
Effective Date: December 10, 2009
* per BCUC Order G-162-11
Page 5 of 35
ATTACHMENT C
to Order G-162-11
Page 72 of 143
Standard IRO-006-4.1 — Reliability Coordination — Transmission Loading Relief
Interchange Transaction using firm transmission service. This is because several of the values
needed to assign a weighted impact using the process listed in Appendix B will not be
available:
−
Distribution Factor (no tag to calculate this value from)
−
Impact on Interface value (cannot be calculated without Distribution Factor)
−
Impact Weighting Factor (cannot be calculated without Distribution Factor)
−
Weighted Maximum Interface Reduction (cannot be calculated without Distribution
Factor)
−
Interface Reduction (cannot be calculated without Distribution Factor)
−
Transaction Reduction (cannot be calculated without Distribution Factor)
While the non-firm market flow impacts submitted to the IDC are to be curtailed pro rata, the
impacting non-firm tagged Interchange Transactions could still use the existing processes to
assign the weighted impact value.
Assignment of Sub-Priorities ⎯ The SPP regional difference modifies Attachment 1-IRO006-1 Appendix E “How the IDC Handles Reallocation”, Section E2 “Timing Requirements”,
within the SPP region.
Under the header “IDC Calculations and Reporting” in Section E2 of Appendix E to
Attachment 1-IRO-006-1, the following requirement exists: “In a TLR Level 3a the
Interchange Transactions using Non-firm Transmission Service in a given priority will be
further divided into four sub-priorities, based on current schedule, current active schedule
(identified by the submittal of a tag ADJUST message), next-hour schedule, and tag status.
Solely for the purpose of identifying which Interchange Transactions to be loaded under a TLR
3a, various MW levels of an Interchange Transaction may be in different sub-priorities. The
sub-priorities are shown in the following table:
Priority
Purpose
Explanation and Conditions
S1
To allow a flowing Interchange
Transaction to maintain or reduce its
current MW amount in accordance with
its energy profile.
The MW amount is the lowest between
currently flowing MW amount and the
next-hour schedule. The currently
flowing MW amount is determined by
the e-tag ENERGY PROFILE and
ADJUST tables. If the calculated
amount is negative, zero is used instead.
S2
To allow a flowing Interchange
The Interchange Transaction MW
amount used is determined through the
e-tag ENERGY PROFILE and ADJUST
tables. If the calculated amount is
negative, zero is used instead.
Transaction that has been curtailed or
halted by TLR to reload to the lesser of
its current-hour MW amount or nexthour schedule in accordance with its
energy profile.
S3
To allow a flowing Transaction to
increase from its current-hour schedule
to its next-hour schedule in accordance
with its energy profile.
Approved by Board of Trustees: April 15, 2009
Effective Date: December 10, 2009
* per BCUC Order G-162-11
The MW amounts used in this subpriority is determined by the e-tag
ENERGY PROFILE table. If the
calculated amount is negative, zero is
used instead.
Page 6 of 35
ATTACHMENT C
to Order G-162-11
Page 73 of 143
Standard IRO-006-4.1 — Reliability Coordination — Transmission Loading Relief
S4
To allow a Transaction that had never
started and was submitted to the Tag
Authority after the TLR (level 2 or
higher) has been declared to begin
flowing (i.e., the Interchange
Transaction never had an active MW
and was submitted to the IDC after the
first TLR Action of the TLR Event had
been declared.)
The Transaction would not be allowed
to start until all other Interchange
Transactions submitted prior to the TLR
with the same priority have been
(re)loaded. The MW amount used is the
sub-priority is the next-hour schedule
determined by the e-tag ENERGY
PROFILE table.
SPP shall use a “Market Flow Calculation” methodology to calculate the amount of energy
flowing across all facilities included in the RTO’s “Coordinated Flowgate List” that is
associated with the operation of the SPP market. This energy is identified as “market flow.”
These market flow impacts for current hour and next hour will be separated into their
appropriate priorities and provided to the IDC by SPP. The market flows will then be
represented and made available for curtailment under the appropriate TLR Levels.
Even though these market flow impacts (separated into appropriate priorities) will not be
represented by conventional “tags,” the impacts and their desired levels will still be provided to
the IDC for current hour and next hour. Therefore, for the purposes of reallocation, a subpriority (S1 thru S4) should be assigned to these market flow impacts by the NERC IDC as
follows, using comparable logic as would be used if the impacts were in fact tagged
transactions.
Priority
Purpose
Explanation and Conditions
S1
To allow existing market flow to
maintain or reduce its current
MW amount.
The currently flowing MW amount is the
amount of market flow existing after the RTO
has recognized the constraint for which TLR
has been called. If the calculated amount is
negative, zero is used instead.
S2
To allow market flow that has
been curtailed or halted by TLR
to reload to its desired amount for
the current-hour.
This is the difference between the current hour
unconstrained market flow and the current
market flow. If the current-hour unconstrained
market flow is not available, the IDC will use
the most recent market flow since the TLR was
first issued or, if not available, the market flow
at the time the TLR was fist issued.
S3
To allow a market flow to
increase to its next-hour desired
amount.
This is the difference between the next hour
and current hour unconstrained market flow.
To be retired upon completion of the field test, and in the interim the Regional Difference will
be contained in both the NERC and NAESB standards.
F. Associated Documents
Version History
Approved by Board of Trustees: April 15, 2009
Effective Date: December 10, 2009
* per BCUC Order G-162-11
Page 7 of 35
ATTACHMENT C
to Order G-162-11
Page 74 of 143
Standard IRO-006-4.1 — Reliability Coordination — Transmission Loading Relief
Version
Date
Action
Change Tracking
0
April 1, 2005
Effective Date
New
0
August 8, 2005
Removed “Proposed” from Effective Date
Errata
1
August 8, 2005
Revised Attachment 1
Revision
3
February 26, 2007
Revised Purpose and Attachment 1 related
to NERC NAESB split of the TLR
procedure
Revision
4
October 23, 2007
Approved by Board of Trustees
Revision
4.1
April 15, 2009
The URL in R1.2. was corrected.
Errata
4.1
December 10, 2009
Approved by FERC — Added approved
effective date
Update
Approved by Board of Trustees: April 15, 2009
Effective Date: December 10, 2009
* per BCUC Order G-162-11
Page 8 of 35
ATTACHMENT C
to Order G-162-11
Page 75 of 143
Standard IRO-006-4.1 — Reliability Coordination — Transmission Loading Relief
PLEASE NOTE: items designated for inclusion in the NAESB TLR business practice following
completion of the standard revision were deleted. Please see the mapped document to see which
items were move to NAESB and what future changes are expected.
Attachment 1 — IRO-006
Transmission Loading Relief Procedure — Eastern Interconnection
Purpose
This standard defines procedures for curtailment and reloading of Interchange Transactions to relieve
overloads on transmission facilities modeled in the Interchange Distribution Calculator.
Applicability
This standard only applies to the Eastern Interconnection.
1.
Transmission Loading Relief (TLR) Procedure
1.1.
Initiation only by Reliability Coordinator. A Reliability
Coordinator shall be the only entity authorized to initiate the
TLR Procedure.
1.1.1.
The flexibility for ISOs
and RTOs to use
redispatch is contained
explicitly in the
NAESB business
practice Section 1.3.
Requesting relief on transmission facilities. Any
Transmission Operator may request from its Reliability Coordinator relief on the
transmission facilities it operates. A Reliability Coordinator shall review these
requests for relief and determine the appropriate relief actions.
1.2.
Mitigating SOL and IROL violations. A Reliability Coordinator may utilize the TLR
Procedure to mitigate potential or existing System Operating Limit (SOL) violations or to
prevent or mitigate Interconnection Reliability Operating Limit (IROL) violations on any
transmission facility modeled in the IDC. However, the TLR procedure is an
inappropriate and ineffective tool as a sole means to mitigate existing IROL violations
due to the time required to implement the procedure. Reconfiguration, redispatch, and
load shedding are more timely and effective in mitigating existing IROL violations
1.3.
Sequencing of TLR Levels and taking emergency action. The Reliability Coordinator
shall not be required to follow the TLR Levels in their numerical sequence (Section 2,
“TLR Levels”). Furthermore, if a Reliability Coordinator deems that a transmission
loading condition could jeopardize Bulk Electric System reliability, the Reliability
Coordinator shall have the authority to enter TLR Level 6 directly, and immediately
direct the Balancing Authorities or Transmission Operators to take such actions as
redispatching generation, or reconfiguring transmission, or reducing load to mitigate the
critical condition until Interchange Transactions can be reduced utilizing the TLR
Procedure or other methods to return the system to a secure state.
1.4.
Notification of TLR Procedure
This notification is automated in the
implementation. The Reliability
Interchange
Distribution Calculator
Coordinator initiating the use of the TLR
(IDC)
and
populates
a message on
Procedure shall notify other Reliability
the NERC RCIS.
Coordinators and Balancing Authorities and
Transmission Operators, and must post the
initiation and progress of the TLR event on the appropriate NERC web page(s).
1.4.1.
Notifying other Reliability Coordinators. The Reliability Coordinator initiating
the TLR Procedure shall inform all other Reliability Coordinators via the
Reliability Coordinator Information System (RCIS) that the TLR Procedure has
been implemented.
Approved by Board of Trustees: April 15, 2009
Effective Date: December 10, 2009
* per BCUC Order G-162-11
Page 9 of 35
ATTACHMENT C
to Order G-162-11
Page 76 of 143
Standard IRO-006-4.1 — Reliability Coordination — Transmission Loading Relief
Actions expected. The Reliability Coordinator initiating the TLR Procedure shall indicate the actions
expected to be taken by other Reliability Coordinators.
1.4.2.
Notifying Transmission Operators and Balancing Authorities. The Reliability
Coordinator shall notify Transmission Operators and
This notification is
Balancing Authorities in its Reliability Area when entering
automated in the
and leaving any TLR level.
1.4.3.
Notifying Sink Balancing Authorities. The Reliability
Coordinator for the sink Balancing Authority shall be
responsible for directing the Sink Balancing Authority to
curtail the Interchange Transactions as specified by the
Reliability Coordinator implementing the TLR Procedure.
Interchange
Distribution
Calculator (IDC)
and populates a
message on the
NERC RCIS.
Notification order. Within a Transmission Service
Priority level, the Sink Balancing Authorities whose Interchange
Transactions have the largest impact on the Constrained Facilities
shall be notified first if practicable.
1.4.4.
Updates. At least once each hour, or when conditions change, the Reliability
Coordinator implementing the TLR Procedure shall update all other Reliability
Coordinators (via the RCIS). Transmission Operators and Balancing Authorities
who have had Interchange Transactions impacted by the TLR will be updated by
their Reliability Coordinator.
1.5.
Obligations. All Reliability Coordinators shall comply with the request of the Reliability
Coordinator who initiated the TLR Procedure, unless the initiating Reliability
Coordinator agrees otherwise.
1.6.
Consideration of Interchange Transactions. The administration of the TLR Procedure
shall be guided by information obtained from the IDC.
1.6.1.
Interchange Transactions not in the IDC. Reliability Coordinators shall also
treat known Interchange Transactions that may not appear in the IDC in
accordance with the procedures in this document.
1.6.2.
Transmission elements not in IDC. When a Reliability Coordinator is faced
with an overload on a transmission element that is not modeled in the IDC, the
Reliability Coordinator shall use the best information available to curtail
Interchange Transactions in order to operate the system in a reliable manner. The
Reliability Coordinator shall use its best efforts to ensure that Interchange
Transactions with a Transfer Distribution Factor of less than the Curtailment
Threshold on the transmission element not modeled in the IDC are not curtailed.
1.6.3.
Questionable IDC results. Any Reliability Coordinator who believes the
curtailment list from the IDC for a particular TLR event is incorrect shall use its
best efforts to communicate those adjustments necessary to bring the curtailment
list into conformance with the principles of this Procedure to the initiating
Reliability Coordinator. Causes of questionable IDC results may include:
•
Missing Interchange Transactions that are known to contribute to the
Constraint.
•
Significant change in transmission system topology.
•
TDF matrix error.
Impacts
cts of questionable IDC results may include:
Approved by Board of Trustees: April 15, 2009
Effective Date: December 10, 2009
* per BCUC Order G-162-11
Page 10 of 35
ATTACHMENT C
to Order G-162-11
Page 77 of 143
Standard IRO-006-4.1 — Reliability Coordination — Transmission Loading Relief
•
Curtailment that would have no effect on, or aggravate the constraint.
•
Curtailment that would initiate a constraint elsewhere.
If other Reliability Coordinators are involved in the TLR event, all impacted
Reliability Coordinators shall be in agreement before any adjustments to the
Curtailment list are made.
1.6.4.
Curtailment that would cause a constraint elsewhere. A Reliability
Coordinator shall be allowed to exempt an Interchange Transaction from
Curtailment if that Reliability Coordinator is aware that the Interchange
Transaction Curtailment directed by the IDC would cause a constraint to occur
elsewhere. This exemption shall only be allowed after the Reliability
Coordinator has consulted with the Reliability Coordinator who initiated the
Curtailment.
1.7
Logging. The Reliability Coordinator shall complete the
NERC Transmission Loading Relief Procedure Log
whenever it invokes TLR Level 2 or above, and send a
copy of the log via email to NERC within two business
days of the TLR event for posting on the NERC website.
1.8
TLR Event Review. The Reliability Coordinator shall
report the TLR event to the Operating Reliability Subcommittee in accordance with TLR
review processes established by NERC as required.
Creation and
distribution of the
TLR Procedure Log
is now automated in
the IDC.
1.8.1
Providing information. Transmission Operators and Balancing Authorities
within the Reliability Coordinator’s Area, and all other Reliability Coordinators,
including Transmission Operators and Balancing Authorities within their
respective Reliability Areas, shall provide information, as requested by the
initiating Reliability Coordinator, in accordance with TLR review processes
established by NERC.
1.8.2
Market Committee reviews. The Market
The Market Committee no longer
Committee may conduct reviews of certain
exists and this requirement will be
TLR events based on the size and number of
Interchange Transactions that are affected, the
removed in Phase 3.
frequency that the TLR Procedure is called for
a particular Constrained Facility, or other factors.
1.8.3
Operating Reliability Subcommittee reviews. The Operating Reliability
Subcommittee shall conduct reviews to ensure proper implementation and for
“lessons learned.”
Approved by Board of Trustees: April 15, 2009
Effective Date: December 10, 2009
* per BCUC Order G-162-11
Page 11 of 35
ATTACHMENT C
to Order G-162-11
Page 78 of 143
Standard IRO-006-4.1 — Reliability Coordination — Transmission Loading Relief
2.
Transmission Loading Relief (TLR) Levels
Introduction
This section describes the various levels of the TLR Procedure. The description of each level begins with
the circumstances that define the TLR Level, followed by the procedures to be followed.
The decision that a Reliability Coordinator makes in selecting a particular TLR Level often depends on
the transmission loading condition and whether the Interchange Transaction is using Non-firm Point-toPoint Transmission Service or Firm Point-to-Point Transmission Service. There are further
considerations that depend on whether the Constrained Facility is on or off the Contract Path. It is
important to note that an Interchange Transaction using Firm Point-to-Point Transmission Service on all
Contract Path links is considered a “firm” Interchange Transaction even if the Constrained Facility is off
the Contract Path.
2.1.
TLR Level 1 — Notify Reliability Coordinators of potential SOL or IROL
Violations
2.1.1.
2.1.2.
2.2.
•
The transmission system is secure.
•
The Reliability Coordinator foresees a transmission or generation
contingency or other operating problem within its Reliability Area that could
cause one or more transmission facilities to approach or exceed their SOL or
IROL.
Notification procedures. The Reliability Coordinator shall notify all Reliability
Coordinators via the Reliability Coordinator Information System (RCIS) as soon
as the condition is foreseen. All affected Reliability Coordinators shall check to
ensure that Interchange Transactions are posted in the IDC.
TLR Level 2 — Hold transfers at present level to prevent SOL or IROL Violations
2.2.1.
2.3
The Reliability Coordinator shall use the following circumstances to establish the
need for TLR Level 1:
The Reliability Coordinator shall use the following circumstances to establish the
need for entering TLR Level 2:
•
The transmission system is secure.
•
One or more transmission facilities are expected to approach, or are
approaching, or are at their SOL or IROL.
TLR Level 3a — Reallocation of Transmission Service by curtailing Interchange
Transactions using Non-firm Point-to-Point Transmission Service to allow
Interchange Transactions using higher priority Transmission Service
2.3.1.
The Reliability Coordinator shall use the following circumstances to establish the
need for entering TLR Level 3a:
•
The transmission system is secure.
•
One or more transmission facilities are expected to approach, or are
approaching, or are at their SOL or IROL.
•
Transactions using Non-firm Point-to-Point Transmission Service are
flowing that are at or above the Curtailment Threshold on those facilities.
Approved by Board of Trustees: April 15, 2009
Effective Date: December 10, 2009
* per BCUC Order G-162-11
Page 12 of 35
ATTACHMENT C
to Order G-162-11
Page 79 of 143
Standard IRO-006-4.1 — Reliability Coordination — Transmission Loading Relief
•
2.4.
TLR Level 3b — Curtail Interchange Transactions using Non-Firm Transmission
Service Arrangements to mitigate a SOL or IROL Violation
2.4.1.
2.5
The Reliability Coordinator shall use the following circumstances to establish the
need for entering TLR Level 3b:
•
One or more transmission facilities are operating above their SOL or IROL,
or
•
Such operation is imminent and it is expected that facilities will exceed their
reliability limit unless corrective action is taken, or
•
One or more Transmission Facilities will exceed their SOL or IROL upon the
removal from service of a generating unit or another transmission facility.
•
Transactions using Non-firm Point-to-Point Transmission Service are
flowing that are at or above the Curtailment Threshold on those facilities.
TLR Level 4 — Reconfigure Transmission
2.5.1.
2.5.2.
2.6.
The Transmission Provider has previously approved a higher priority Pointto-Point Transmission Service reservation over which a Transmission
Customer wishes to begin an Interchange Transaction.
The Reliability Coordinator shall use the following circumstances to establish the
need for entering TLR Level 4:
•
One or more Transmission Facilities are above their SOL or IROL, or
•
Such operation is imminent and it is expected that facilities will exceed their
reliability limit unless corrective action is taken.
Reconfiguration procedures. The issuance of a TLR Level 4 shall result in the
curtailment, in the current hour and the next hour, of all Interchange Transactions
using Non-firm Point-to-Point Transmission Service that are at or above the
Curtailment Threshold that impact the Constrained Facilities. If a SOL or IROL
violation is imminent or occurring, the Reliability Coordinator(s) shall request
that the affected Transmission Operators reconfigure transmission on their
system, or arrange for reconfiguration on other transmission systems, to mitigate
the constraint.
TLR Level 5a — Reallocation of Transmission Service by curtailing Interchange
Transactions using Firm Point-to-Point Transmission Service on a pro rata basis to
allow additional Interchange Transactions using Firm Point-to-Point Transmission
Service
2.6.1.
The Reliability Coordinator shall use the following circumstances to establish the
need for entering TLR Level 5a:
•
The transmission system is secure.
•
One or more transmission facilities are at their SOL or IROL.
•
All Interchange Transactions using Non-firm Point-to-Point Transmission
Service that are at or above the Curtailment Threshold have been curtailed.
•
The Transmission Provider has been requested to begin an Interchange
Transaction using previously arranged Firm Transmission Service that would
result in a SOL or IROL violation.
Approved by Board of Trustees: April 15, 2009
Effective Date: December 10, 2009
* per BCUC Order G-162-11
Page 13 of 35
ATTACHMENT C
to Order G-162-11
Page 80 of 143
Standard IRO-006-4.1 — Reliability Coordination — Transmission Loading Relief
•
2.7.
TLR Level 5b — Curtail Interchange Transactions using Firm Point-to-Point
Transmission Service to mitigate an SOL or IROL violation
2.7.1.
2.8.
No further transmission reconfiguration is possible or effective.
The Reliability Coordinator shall use following circumstances to establish the
need for entering TLR Level 5b:
•
One or more Transmission Facilities are operating above their SOL or IROL,
or
•
Such operation is imminent, or
•
One or more Transmission Facilities will exceed their SOL or IROL upon the
removal from service of a generating unit or another transmission facility.
•
All Interchange Transactions using Non-firm Point-to-Point Transmission
Service that are at or above the Curtailment Threshold have been curtailed.
•
No further transmission reconfiguration is possible
or effective.
Curtailment of Interchange Transactions Using Firm
Transmission Service
2.8.1.
formerly NERC
section 3.3
The Reliability Coordinator shall direct the curtailment of Interchange
Transactions using Firm Transmission Service that are at or above the
Curtailment Threshold for the following TLR Levels:
2.8.1.1. TLR Level 5a. Enable additional Interchange Transactions using Firm
Point-to-Point Transmission Service to be implemented after all
Interchange Transactions using Non-firm Point-to-Point Service have
been curtailed, or
2.8.1.2. TLR Level 5b. Mitigate a SOL or IROL violation that remains after all
Interchange Transactions using Non-firm Transmission Service has been
curtailed under TLR Level 3b, and following attempts to reconfigure
transmission under TLR Level 4.
2.9.
TLR Level 6 — Emergency Procedures
2.9.1
2.9.2
2.10
The Reliability Coordinator shall use following circumstances to establish the
need for entering TLR Level 6:
•
One or more Transmission Facilities are above their SOL or IROL.
•
One or more Transmission Facilities will exceed their SOL or IROL upon the
removal from service of a generating unit or another transmission facility.
Implementing emergency procedures. If the Reliability Coordinator deems that
transmission loading is critical to Bulk Electric System reliability, the Reliability
Coordinator shall immediately direct the Balancing Authorities and Transmission
Operators in its Reliability Area to redispatch generation, or reconfigure
transmission, or reduce load to mitigate the critical condition until Interchange
Transactions can be reduced utilizing the TLR Procedures or other procedures to
return the system to a secure state. All Balancing Authorities and Transmission
Operators shall comply with all requests from their Reliability Coordinator.
TLR Level 0 — TLR concluded
Approved by Board of Trustees: April 15, 2009
Effective Date: December 10, 2009
* per BCUC Order G-162-11
Page 14 of 35
ATTACHMENT C
to Order G-162-11
Page 81 of 143
Standard IRO-006-4.1 — Reliability Coordination — Transmission Loading Relief
2.10.1 Interchange Transaction restoration and notification procedures. The
Reliability Coordinator initiating the TLR Procedure shall notify all Reliability
Coordinators within the Interconnection via the RCIS when the SOL or IROL
violations are mitigated and the system is in a reliable state, allowing Interchange
Transactions to be reestablished at its discretion. Those with the highest
transmission priorities shall be reestablished first if possible.
3.
Requirements
3.1
The Reliability Coordinator shall be allowed to call a TLR 3b at any time to help mitigate
a SOL or IROL violation.
3.2
The Reliability Coordinator shall Reallocate Interchange Transactions using Non-firm
Point-to-Point Transmission for the next hour to maintain the desired flow using
Reallocation in accordance with the following timing specification:
3.2.1
If issued prior to XX: 25, Non-firm Interchange Transactions will be curtailed to
meet the desired current hour relief
4.2.1.1 At XX: 25 a Reallocation will be performed to maintain the desired flow
at the top of the following hour
3.3
3.2.2
If issued after XX: 25, Non firm Interchange Transactions will be curtailed to
meet the desired current hour relief and a Reallocation will be performed to
maintain the target flow identified for the current hour.
3.2.3
Transactions must be in the IDC by the Approved-tag Submission Deadline for
Reallocation.
The IDC shall issue ADJUST Lists to the Generation and Load Balancing Authority
Areas and the Purchasing-Selling Entity who submitted the tag. The ADJUST List will
include: (recommended to be moved to Attachment 2)
3.3.1
Interchange Transactions using Non-firm Point-to-Point Transmission Service
that are to be curtailed or held during current and next hours. (recommended to
be moved to Attachment 2)
3.3.2
Interchange Transactions using Firm Point-to-Point Transmission Service that
were entered after XX:25 or issuance of TLR 3b (see Case 3 in Appendix F).
(recommended to be moved to Attachment 2)
3.4
The Sink Balancing Authority shall send the ADJUST Lists back to the IDC as soon as
possible to ensure the most accurate calculations for actions subsequent to the TLR 3b
being called. (recommend to be moved to Attachment 2)
3.5
The Reliability Coordinator will no longer be required to call a TLR Level 3a as soon as
the SOL or IROL violation that caused the TLR 3b to be called has been mitigated due to
the inherent next hour Reallocation that takes place for the top of the next hour in the
TLR Level 3b. (recommend to be moved to Attachment 2)
Approved by Board of Trustees: April 15, 2009
Effective Date: December 10, 2009
* per BCUC Order G-162-11
Page 15 of 35
ATTACHMENT C
to Order G-162-11
Page 82 of 143
Standard IRO-006-4.1 — Reliability Coordination — Transmission Loading Relief
Appendices for Transmission Loading Relief Standard
PLEASE NOTE: items designated for inclusion in the NAESB TLR business practice following
completion of the standard revision were deleted from this version of the NERC standard. Please
see the mapped document to see which requirements were moved to NAESB and what future
changes are expected. Appendices B, D, G, and the sub-priority portions of E-2 have been moved to
NAESB, The appendices below (A, C, E, F) will be renumbered in the final standard.
Appendix A. Transaction Management and Curtailment Process.
Appendix C. Sample NERC Transmission Loading Relief Procedure Log.
Appendix E. How the IDC Handles Reallocation.
Section E1: Summary of IDC Features that Support Transaction Reloading/Reallocation.
Section E2: Timing Requirements.
Appendix F. Considerations for Interchange Transactions using Firm Point-to-Point Transmission
Service.
Approved by Board of Trustees: April 15, 2009
Effective Date: December 10, 2009
* per BCUC Order G-162-11
Page 16 of 35
ATTACHMENT C
to Order G-162-11
Page 83 of 143
Standard IRO-006-4.1 — Reliability Coordination — Transmission Loading Relief
Appendix A. Transaction Management and Curtailment Process
This flowchart depicts an overview of the Transaction Management and Curtailment process. Detailed
decisions are not shown.
Monitor
System
System
Secure
Security Limit
Violation?
Yes
TLR 3b
OSL Violation
No
Yes
Potential
SLV?
Curtailment
Method:
No
TLR 1
NERC TLR
Local
No
No
Request
for Transmission
Service?
Still
Constrained?
Yes
IDC
Yes
Yes
Curtail Non-Firm
Priorities 1-6
Accommodate?
No
No
TLR 2
Hold
Still
Constrained?
TLR 4
Reconfigure
Yes
Request for Higher Priority
Service
Yes
Can
Reconfigure?
No
Yes
TLR 3a
Curtail Non-firm
Accommodate?
No
No
Still
Constrained?
TLR 5b
Calc TCF
Curtail Firm
Yes
Take
Emergency
Action
TLR 4
Reconfigure
Yes
Accommodate?
No
TLR 5a
TCF
Curtail Firm
Approved by Board of Trustees: April 15, 2009
Effective Date: December 10, 2009
* per BCUC Order G-162-11
Page 17 of 35
ATTACHMENT C
to Order G-162-11
Page 84 of 143
Standard IRO-006-4.1 — Reliability Coordination — Transmission Loading Relief
Appendix C. Sample NERC Transmission Loading Relief Procedure Log
SAVE FILE DIRECTORY:
NERC TRANSMISSION LOADING RELIEF (TLR) PROCEDURE LOG
FILE SAVED AS:
INCIDENT :
DATE:
INITIAL
.XLS
IMPACTED RELIABILITY COORDINATOR :
ID NO:
CONDITIONS
Limiting Flowgate (LIMIT)
Rating Contingent Flowgate (CONT.)
TLR Levels
Priorities
NX
Next Hour Market Service
NS
Service over secondary receipt and delivery points
NH
Hourly Service
ND
Daily Service
NW
Weekly Service
NM
Monthly Service
NN
Non-firm imports for native load and network customers from
non-designated network resources
F
Firm Service
0: TLR Incident Canceled
1. Notify Reliability Coordinators of potential problems.
2: Halt additional transactions that contribute to the overload
3a and 3b: Curtail transactions using Non-firm Transmission Service
4. Reconfigure to continue firm transactions if needed.
5a and 5b: Curtail Transactions using Firm Transmission Service.
6: Implement emergency procedures.
ODF
T L R
A C T I O N S
TLR 3,5TLR 3,5
MW Flow
Limiting Element Cont. Elem't
COMMENTS ABOUT ACTIONS
LEVEL TIME Priority No. TX MW
Curtail Curtail Present Post Cont. Present
Approved by Board of Trustees: April 15, 2009
Effective Date: December 10, 2009
* per BCUC Order G-162-11
Page 18 of 35
ATTACHMENT C
to Order G-162-11
Page 85 of 143
Standard IRO-006-4.1 — Reliability Coordination — Transmission Loading Relief
Appendix E. How the IDC Handles Reallocation
The IDC algorithms reflect the Reallocation and reloading principles in this Appendix, as well as the
reporting requirements, and status display. The IDC will obtain the Tag Submittal Time from the Tag
Authority and post the Reloading/Reallocation information to the NERC TLR website.
A summary of IDC features that support the Reallocation process is provided in Attachment E1. Details
on the interface and display features are provided in Attachment E2. Refer to Version 1.7.095 NERC
Transaction Information Systems Working Group (TISWG) Electronic Tagging Functional Specification
for details about the E-Tag system.
E1. Summary of IDC Features that Support Transaction Reloading/Reallocation
The following is a summary of IDC features and E-Tag interface that support Reloading/Reallocation:
Information posted from IDC to NERC TLR website.
1. Restricted directions (all source/sink combinations that impact a Constrained Facility(ies) with TLR 2
or higher) will be posted to the NERC TLR website and updated as necessary.
2. TLR Constrained Facility status and Transfer Distribution Factors will continue to be posted to
NERC TLR website.
3. Lowest priority of Interchange Transactions (marginal “bucket”) to be Reloaded/Reallocated nexthour on each TLR Constrained Facility will be posted on NERC TLR website. This will provide an
indication to the market of priority of Interchange Transactions that may be Reloaded/Reallocated the
following hours.
IDC Logic, IDC Report, and Timing
1. The Reliability Coordinator will run the IDC the Reloading/Reallocation report at approximately
00:26. The IDC will prompt the Reliability Coordinator to enter a maximum loading value. The IDC
will alarm if the Reliability Coordinator does not enter this value and issue a report by 00:30 or
change from TLR 3a Level. The Report will be distributed to Balancing Authorities and
Transmission Operators at 00:30. This process repeats every hour as long as the approved tag
submission deadline for Reallocation is in effect (or until the TLR level is reduced to 1 or 0).
2. For Interchange Transactions in the restricted directions, tags must be submitted to the IDC by the
approved tag submission deadline for Reallocation to be considered for Reallocation next-hour. The
time stamp by the Tag Authority is regarded the official tag submission time.
3. Tags submitted to IDC after the approved tag submission deadline for Reallocation will not be
allowed to start or increase but will be considered for Reallocation the next hour.
4. Interchange Transactions in restricted directions that are not indicated as “PROCEED” on the
Reload/Reallocation Report will not be permitted to start or increase next hour.
Reloading/Reallocation Transaction Status
Reloading/Reallocation status will be determined by the IDC for all Interchange Transactions. The
Reloading/Reallocation status of each Interchange Transaction will be listed on IDC reports and NERC
TLR website as appropriate. An Interchange Transaction is considered to be in a restricted direction if it
is at or above the Curtailment Threshold. Interchange Transactions below the Curtailment Threshold are
unrestricted and free to flow subject to all applicable Reliability Standards and tariff rules.
1. HOLD. Permission has not been given for Interchange Transaction to start or increase and is waiting
for the next Reloading/Reallocation evaluation for which it is a candidate. Interchange Transactions
with E-tags submitted to the Tag Authority prior to TLR 2 or higher being declared (pre-tagged) will
change to CURTAILED Status upon evaluation that does not permit them to start or increase.
Approved by Board of Trustees: April 15, 2009
Effective Date: December 10, 2009
* per BCUC Order G-162-11
Page 19 of 35
ATTACHMENT C
to Order G-162-11
Page 86 of 143
Standard IRO-006-4.1 — Reliability Coordination — Transmission Loading Relief
Transactions with E-tags submitted to Tag Authority after TLR 2 or higher was declared (posttagged) will retain HOLD Status until given permission to proceed or E-Tag expires.
2. CURTAILED. Transactions for which E-Tags were submitted to Tag Authority prior to TLR 2 or
higher being declared (pre-tagged) and ordered to be curtailed totally, curtailed partially, not
permitted to start, or not permitted to increase. Interchange Transactions (pre-tagged or post-tagged)
that were flowing and ordered to be reduced or totally curtailed. The Balancing Authority will
indicate to the IDC through the E-Tag adjustment table the Interchange Transaction’s curtailed
values.
3. PROCEED: Interchange Transaction is flowing or has been permitted to flow as a result of
Reloading/Reallocation evaluation. The Balancing Authority will indicate through the E-Tag
adjustment table to IDC if Interchange Transaction will reload, start, or increase next-hour per
Purchasing-Selling Entity’s energy schedule as appropriate.
Reallocation/Reloading Priorities
1. Interchange Transaction candidates are ranked for loading and curtailment by priority as per Section
4, “Principles for Mitigating Constraints On and Off the Contract Path.” This is called the
“Constrained Path Method,” or CPM. (secondary, hourly, daily, … firm etc). Interchange
Transactions are curtailed and loaded pro-rata within priority level per TLR algorithm.
2. Reloading/Reallocation of Interchange Transactions are prioritized first by priority per CPM. E-Tags
must be submitted to the IDC by the approved tag submission deadline for Reallocation of the hour
during which the Interchange Transaction is scheduled to start or increase to be considered for
Reallocation.
3. During Reloading/Reallocation, Interchange Transactions using lower priority Transmission Service
will be curtailed pro-rata to allow higher priority transactions to reload, increase, or start. Equal
priority Interchange Transactions will not reload, start, or increase by pro-rata Curtailment of other
equal priority Interchange Transactions.
4. Reloading of Interchange Transactions using Non-firm Transmission Service with CURTAILED
Status will take precedence over starting or increasing of Interchange Transactions using Non-firm
Transmission Service of the same priority with PENDING Statuses.
5. Interchange Transactions using Firm Point-to-Point Transmission Service will be allowed to start as
scheduled under TLR 3a as long as their E-Tag was received by the IDC by the approved tag
submission deadline for Reallocation of the hour during which the Interchange Transaction is due to
start or increase, regardless of whether the E-tag was submitted to the Tag Authority prior to TLR 2
or higher being declared or not. If this is the initial issuance of the TLR 3a, Interchange Transactions
using Firm Point-to-Point Transmission Service will be allowed to start as scheduled as long as their
E-Tag was received by the IDC by the time the TLR is declared.
Total Flow Value on a Constrained Facility for Next Hour
1. The Reliability Coordinator will calculate the change in net flow on a Constrained Facility due to
Reallocation for the next hour based on:
•
Present constrained facility loading, present level of Interchange Transactions, and Balancing
Authorities NNative Load responsibility (TLR Level 5a) impacting the Constrained Facility,
•
SOLs or IROLs, known interchange impacts and Balancing Authority NNative Load responsibility
(TLR Level 5a) on the Constrained Facility the next hour, and
•
Interchange Transactions scheduled to begin the next hour.
Approved by Board of Trustees: April 15, 2009
Effective Date: December 10, 2009
* per BCUC Order G-162-11
Page 20 of 35
ATTACHMENT C
to Order G-162-11
Page 87 of 143
Standard IRO-006-4.1 — Reliability Coordination — Transmission Loading Relief
2. The Reliability Coordinator will enter a maximum loading value for the constrained facility into the
IDC as part of issuing the Reloading/Reallocation report.
3. The Reliability Coordinator is allowed to call for TLR 3a or 5a when approaching a SOL or IROL to
allow maximum transactional flow next hour, and to manage flows without violating transmission
limits.
4. The simultaneous curtailment and Reallocation for a Constrained Facility is allowed. This reduces
the flow over the Constrained Facility while allowing Interchange Transactions using higher priority
Transmission Service to start or increase the next hour. This may be used to accommodate change in
flow next-hour due to changes other than Point-to-Point Interchange Transactions while respecting
the priorities of Interchange Transactions flowing and scheduled to flow the next hour. The intent is
to reduce the need for using TLR 3b, which prevents new Interchange Transactions from starting or
increasing the next hour.
5. The Reliability Coordinator must allow Interchange Transactions to be reloaded as soon as possible.
Reloading must be in an orderly fashion to prevent a SOL or IROL violation from (re)occurring and
requiring holding or curtailments in the restricted direction.
Approved by Board of Trustees: April 15, 2009
Effective Date: December 10, 2009
* per BCUC Order G-162-11
Page 21 of 35
ATTACHMENT C
to Order G-162-11
Page 88 of 143
Standard IRO-006-4.1 — Reliability Coordination — Transmission Loading Relief
E2. Timing Requirements
TLR Levels 3a and 5a Issuing/Processing Time Requirement
1. In order for the IDC to be reasonably certain that a TLR Level 3a or 5a re-allocation/reloading report
in which all tags submitted by the approved tag submission deadline for Reallocation are included,
the report must be generated no earlier than 00:25 to allow the 10-minute approval time for
Transactions that start next hour.
2. In order to allow a Reliability Coordinator to declare a TLR Level 3a or 5a at any time during the
hour, the TLR declaration and Reallocation/Reloading report distribution will be treated as
independent processes by the IDC. That is, a Reliability
IDC results prior
to 00:25 and
Coordinator may declare a TLR Level 3a or 5a at any time
01:25 are
during the course of an hour. However, if a TLR Level 3a
not distributed
or 5a is declared for the next hour prior to 00:25 (see Figure
5 at right), the Reallocation/Reloading report that is
generated will be made available to the issuing Reliability
Coordinator only for previewing purposes, and cannot be
:25
:25
distributed to the other Reliability Coordinators or the
00:00
01:00
02:00
market. Instead, the issuing Reliability Coordinator will be
Figure 5 - IDC report may be run prior to
reminded by an IDC alarm at 00:25 to generate a new
00:25, but results are not distributed.
Reallocation/Reloading report that will include all tags
submitted prior to the approved tag submission deadline for Reallocation.
3. A TLR Level 3a or 5a Reallocation/Reloading report must be confirmed by the issuing Reliability
Coordinator prior to 00:30 in order to provide a minimum of 30 minutes for the Reliability
Coordinators with tags sinking in its Reliability Area to coordinate the Reallocation and Reloading
with the Sink Balancing Authorities. This provides only 5 minutes (from 00:25 to 00:30) for the
issuing Reliability Coordinator to generate a Reallocation/Reloading report, review it, and approve it.
4. The TLR declaration time will be recorded in the IDC for evaluating transaction sub-priorities for
Reallocation/Reloading purposes (see Subpriority Table, in the IDC Calculations and Reporting
section below).
Re-Issuing of a TLR Level 2 or Higher
Each hour, the IDC will automatically remind the issuing Reliability Coordinator (via an IDC alarm) of a
TLR level 2 or higher declared in the previous hour or earlier about re-issuing the TLR. The purpose of
the reminder is to enable the Reliability Coordinator to Reallocate or reload currently halted or curtailed
Interchange Transactions next hour. The reminder will be in the form of an alarm to the issuing
Reliability Coordinator, and will take place at 00:25 so that, if the Reliability Coordinator re-issues the
TLR as a TLR level 3a or 5a, all tags submitted prior to the approved tag submission deadline for
Reallocation are available in the IDC.
IDC Assistance with Next Hour Point-to-Point Transactions
In order to assist a Reliability Coordinator in determining the MW relief required on a Constrained
Facility for the next hour for a TLR level 3a or 5a, the IDC will calculate and present the total MW
impact of all currently flowing and scheduled Point-to-Point Transactions for the next hour. In order to
assist a Reliability Coordinator in determining the MW relief required on a Constrained Facility for the
next hour during a TLR level 5a, the IDC will calculate and present the total MW impact of all currently
flowing and scheduled Point-to-Point Transactions for the next hour as well as Balancing Authority with
flows due to service to Network Customers and Native Load. The Reliability Coordinator will then be
requested to provide the total incremental or decremental MW amount of flow through the Constrained
Facility that can be allowed for the next hour. The value entered by the Reliability Coordinator and the
IDC-calculated amounts will be used by the IDC to identify the relief/reloading amounts (delta
Approved by Board of Trustees: April 15, 2009
Effective Date: December 10, 2009
* per BCUC Order G-162-11
Page 22 of 35
ATTACHMENT C
to Order G-162-11
Page 89 of 143
Standard IRO-006-4.1 — Reliability Coordination — Transmission Loading Relief
incremental flow value) on the constrained facility. The IDC will determine the Transactions to be
reloaded, reallocated, or curtailed to make room for the Transactions using higher priority Transmission
Service. The following examples show the calculation performed by IDC to identify the “delta
incremental flow:”
Example 1
Flow to maintain on Facility
800 MW
Expected flow next hour from Transactions using Point-toPoint Transmission Service
950 MW
Contribution from flow next hour from service to Network
customers and Native Load
-100 MW
Expected Net flow next hour on Facility
850 MW
Amount of Transactions using Point-to-Point Transmission
Service to hold for Reallocation
850 MW – 800 MW = 50 MW
Amount to enter into IDC for Transactions using Point-to-Point
Transmission Service
950 MW – 50 MW = 900 MW
Example 2
Flow to maintain on Facility
800 MW
Expected flow next hour from Transactions using Point-toPoint Transmission Service
950 MW
Contribution from flow next hour from service to Network
customers and Native Load
50 MW
Expected Net flow next hour on Facility
1000 MW
Amount of Transactions using Point-to-Point Transmission
Service to hold for Reallocation
1000 MW – 800 MW = 200 MW
Amount to enter into IDC for Transactions using Point-to-Point
Transmission Service
950 MW – 200 MW = 750 MW
Example 3
Flow to maintain on Facility
800 MW
Expected flow next hour from Transactions using Point-toPoint Transmission Service
950 MW
Contribution from flow next hour from service to Network
customers and Native Load
-200 MW
Expected Net flow next hour on Facility
750 MW
Amount of Transactions using Point-to-Point Transmission
Service to hold for Reallocation
750 MW – 800 MW = -50 MW
None are held
Approved by Board of Trustees: April 15, 2009
Effective Date: December 10, 2009
* per BCUC Order G-162-11
Page 23 of 35
ATTACHMENT C
to Order G-162-11
Page 90 of 143
Standard IRO-006-4.1 — Reliability Coordination — Transmission Loading Relief
For a TLR levels 3b or 5b the IDC will request the Reliability Coordinator to provide the MW requested
relief amount on the Constrained Facility, and will not present the current and next hour MW impact of
Point-to-Point transactions. The Reliability Coordinator-entered requested relief amount will be used by
the IDC to determine the Interchange Transaction Curtailments and flows due to service to Network
Customers and Native Load (TLR Level 5b) in order to reduce the SOL or IROL violation on the
Constrained Facility by the requested amount.
IDC Calculations and Reporting
At the time the TLR report is processed, the IDC will use all candidate Interchange Transactions for
Reallocation that met the approved tag submission deadline for Reallocation plus those Interchange
Transactions that were curtailed or halted on the previous TLR action of the same TLR event. The IDC
will calculate and present an Interchange Transactions Halt/Curtailment list that will include reload and
Reallocation of Interchange Transactions. The Interchange Transactions are prioritized as follows:
1. All Interchange Transactions will be arranged by Transmission Service Priority according to the
Constrained Path Method. These priorities range from 1 to 6 for the various non-firm Transmission
Service products (TLR levels 3a and 3b). Interchange Transactions using Firm Transmission Service
(priority 7) are used only in TLR levels 5a and 5b. Next-Hour Market Service is included at priority 0
(Recommended to be placed in Attachment 2).
Examples of Interchange Transactions using Non-firm Transmission Service sub-priority settings
begin in the Transaction Sub-priority Examples following sections
2. All Interchange Transactions using Firm Transmission Service will be put in the same priority group,
and will be Curtailed/Reallocated pro-rata, independent of their current status (curtailed or halted) or
time of submittal with respect to TLR issuance (TLR level 5a). Under a TLR 5a, all Interchange
Transactions using Non-firm Transmission Service that is at or above the Curtailment Threshold will
have been curtailed and hence sub-prioritizing is not required.
All Interchange Transactions processed in a TLR are assigned one of the following statuses:
PROCEED:
The Interchange Transaction has started or is allowed to start to the next hour
MW schedule amount.
CURTAILED:
The Interchange Transaction has started and is curtailed due to the TLR, or it had
not started but it was submitted prior to the TLR being declared (level 2 or
higher).
HOLD:
The Interchange Transaction had never started and it was submitted after the
TLR being declared – the Interchange Transaction is held from starting next hour
or the transaction had never started and it was submitted to the IDC after the
Approved-Tag Submission Deadline – the Interchange Transaction is to be held
from starting next hour and is not included in the Reallocation calculations until
following hour.
Upon acceptance of the TLR Transaction Reallocation/reloading report by the issuing Reliability
Coordinator, the IDC will generate a report to be sent to NERC that will include the PSE name and Tag
ID of each Interchange Transaction in the IDC TLR report. The Interchange Transaction will be ranked
according to its assigned status of HOLD, CURTAILED or PROCEED. The reloading/Reallocation
report will be made available at NERC’s public TLR website, and it is NERC’s responsibility to format
and publish the report.
Tag Reloading for TLR Levels 1 and 0
When a TLR Level 1 or 0 is issued, the Constrained Facility is no longer under SOL or IROL violation
and all Interchange Transactions are allowed to flow. In order to provide the Reliability Coordinators with
Approved by Board of Trustees: April 15, 2009
Effective Date: December 10, 2009
* per BCUC Order G-162-11
Page 24 of 35
ATTACHMENT C
to Order G-162-11
Page 91 of 143
Standard IRO-006-4.1 — Reliability Coordination — Transmission Loading Relief
a view of the Interchange Transactions that were halted or curtailed on previous TLR actions (level 2 or
higher) and are now available for reloading, the IDC provides such information in the TLR report.
New Tag Alarming
Those Interchange Transactions that are at or above the Curtailment Threshold and are not candidates for
Reallocation because the tags for those Transactions were not submitted by the approved tag submission
deadline for Reallocation will be flagged as HOLD and must not be permitted to start or increase during
the next hour. To alert Reliability Coordinators of those Transactions required to be held, the IDC will
generate a report (for viewing within the IDC only) at various times. The report will include a list of all
HOLD Transactions. In order not to overwhelm the Reliability Coordinator with alarms, only those who
issued the TLR and those whose Transactions sink within their Reliability Area will be alarmed. An
alarm will be issued for a given tag only once and will be issued for all TLR levels for which halting new
Transactions is required: TLR Level 2, 3a, 3b, 5a and 5b.
Tag Adjustment
The Interchange Transactions with statuses of HOLD, CURTAILED or PROCEED must be adjusted by a
Tag Authority or Tag Approval entity. Without the tag adjustments, the IDC will assume that Interchange
Transactions were not curtailed/held and are flowing at their specified schedule amounts.
1. Interchange Transactions marked as CURTAILED should be adjusted to a cap equal to, or at the
request of the originating PSE, less than the reallocated amount (shown as the MW CAP on the IDC
report). This amount may be zero if the Transaction is fully curtailed.
2. Interchange Transaction marked as PROCEED should be adjusted to reload (NULL or to its MW
level in accordance with its Energy Profile in the adjusted MW in the E-Tag) if the Interchange
Transaction has been previously adjusted; otherwise, if the Interchange Transaction is flowing in full,
the Tag Authority need not issue an adjust.
3. Interchange Transactions marked as HOLD should be adjusted to 0 MW.
Special Tag Status
There are cases in which a tag may be marked with a composite state of ATTN_REQD to indicate that tag
Authority/Approval failed to communicate or there is an inconsistency between the validation software of
different tag Authority/Approval entities. In this situation, the tag is no longer subject to passive approval
and its status change to IMPLEMENT may take longer than 10 minutes. Under these circumstances, the
IDC may have a tag that is issued prior to the Tag Submittal Deadline that will not be a candidate for
Reallocation. Such tags, when approved by the Tag Authority, will be marked as HOLD and must be
halted.
Transaction Sub-Priority Examples
The following describes examples of Interchange Transactions using Non-firm Transmission Service subpriority setting for an Interchange Transaction under different circumstances of current-hour and nexthour schedules and active MW flowing as modified by tag adjust table in E-Tag.
Approved by Board of Trustees: April 15, 2009
Effective Date: December 10, 2009
* per BCUC Order G-162-11
Page 25 of 35
ATTACHMENT C
to Order G-162-11
Page 92 of 143
Standard IRO-006-4.1 — Reliability Coordination — Transmission Loading Relief
Example 1 – Transaction curtailed, next-hour Energy Profile is higher
20 MW
Actual flow following curtailment: Current hour
10 MW
Energy Profile: Next hour
40 MW
MW
Energy Profile: Current hour
40
S3
20
S2
10
S1
Time
TLR
Sub-priorities for Transaction MW:
Sub-Priority
MW Value
Explanation
S1
10 MW
Maintain current curtailed flow
S2
+10 MW
Reload to current hour Energy Profile
S3
+20 MW
Load to next hour Energy Profile
S4
Approved by Board of Trustees: April 15, 2009
Effective Date: December 10, 2009
* per BCUC Order G-162-11
Page 26 of 35
ATTACHMENT C
to Order G-162-11
Page 93 of 143
Standard IRO-006-4.1 — Reliability Coordination — Transmission Loading Relief
Example 2 – Transaction curtailed, next-hour Energy Profile is lower
40 MW
Actual flow following curtailment: Current hour
10 MW
Energy Profile: Next hour
20 MW
MW
Energy Profile: Current hour
40
20
S2
10
S1
Time
TLR
Sub-priorities for Transaction MW:
Sub-Priority
MW Value
Explanation
S1
10 MW
Maintain current curtailed flow
S2
+10 MW
Reload to lesser of current and next-hour Energy Profile
S3
+0 MW
Next-hour Energy Profile is 20MW, so no change in MW value
S4
Approved by Board of Trustees: April 15, 2009
Effective Date: December 10, 2009
* per BCUC Order G-162-11
Page 27 of 35
ATTACHMENT C
to Order G-162-11
Page 94 of 143
Standard IRO-006-4.1 — Reliability Coordination — Transmission Loading Relief
Example 3 – Transaction not curtailed, next-hour Energy Profile is higher
20 MW
Actual flow following curtailment: Current
hour
20 MW (no curtailment)
Energy Profile: Next hour
40 MW
MW
Energy Profile: Current hour
40
S3
20
S1
10
Time
TLR
Sub-Priority
MW Value
Explanation
S1
20 MW
Maintain current flow (not curtailed)
S2
+0 MW
Reload to lesser of current and next-hour Energy Profile
S3
+20 MW
Next-hour Energy Profile is 40MW
S4
Approved by Board of Trustees: April 15, 2009
Effective Date: December 10, 2009
* per BCUC Order G-162-11
Page 28 of 35
ATTACHMENT C
to Order G-162-11
Page 95 of 143
Standard IRO-006-4.1 — Reliability Coordination — Transmission Loading Relief
Example 4 – Transaction not curtailed, next-hour Energy Profile is lower
40 MW
Actual flow following curtailment: Current hour
40 MW (no curtailment)
Energy Profile: Next hour
20 MW
MW
Energy Profile: Current hour
40
20
S1
10
Time
TLR
Sub-priorities for Transaction MW:
Sub-Priority
MW Value
Explanation
S1
20 MW
Reduce flow to next-hour Energy
Profile (20MW)
S2
+0 MW
Reload to lesser of current and
next-hour Energy Profile
S3
+0 MW
Next-hour Energy Profile is
20MW
S4
Approved by Board of Trustees: April 15, 2009
Effective Date: December 10, 2009
* per BCUC Order G-162-11
Page 29 of 35
ATTACHMENT C
to Order G-162-11
Page 96 of 143
Standard IRO-006-4.1 — Reliability Coordination — Transmission Loading Relief
Example 5 — TLR Issued before Transaction was scheduled to start
0 MW
Actual flow following curtailment: Current hour
0 MW (Transaction
scheduled to start after
TLR initiated)
Energy Profile: Next hour
20 MW
MW
Energy Profile: Current hour
40
20
S3
10
Time
Tag
TLR
Sub-Priority
MW Value
Explanation
S1
0 MW
Transaction was not allowed to start
S2
+0 MW
Transaction was not allowed to start
S3
+20 MW
Next-hour Energy Profile is 20MW
S4
+0
Tag submitted prior to TLR
Approved by Board of Trustees: April 15, 2009
Effective Date: December 10, 2009
* per BCUC Order G-162-11
Page 30 of 35
ATTACHMENT C
to Order G-162-11
Page 97 of 143
Standard IRO-006-4.1 — Reliability Coordination — Transmission Loading Relief
Appendix F. Considerations for Interchange Transactions
Using Firm Point-to-Point Transmission Service
The following cases explain the circumstances under which an Interchange Transaction using Firm Pointto-Point Transmission Service will be allowed to start as scheduled during a TLR 3b:
Case 1: TLR 3b is called between 00:00 and 00:25 and the Interchange Transaction using Firm
Point-to-Point Transmission Service is submitted to IDC by 00:25.
The IDC will examine the current hour (00) and next hour (01) for all Interchange Transactions.
Firm Transactions
that were held are
allowed to start at
02:00
Firm
Transactions in
IDC by 00:25
allowed to start
as scheduled.
Firm Transactions
must be submitted
to IDC by 00:25 to
start as scheduled
TLR 3b
TLR 3a
00:25
00:00
00:10
00:20
00:30
Beginning of
Current Hour
IDC issues Congestion
Management Report
based on time of calling
TLR 3b. ADJUST List
follows.
00:40
IDC checks for
additional approved
Firm Transactions.
Congestion
Management Report
and second ADJUST
List issued if needed.
00:50
01:00
Beginning of
Next Hour
The IDC will issue an ADJUST List based upon the time the TLR 3b is called. The ADJUST List will include
curtailments of Interchange Transactions using Non-firm Point-to-Point Transmission Service as necessary to
allow room for those Interchange Transactions using Firm Point-to-Point Transmission Service to start as
scheduled.
At 00:25, the IDC will check for additional Interchange Transactions using Firm Point-to-Point Transmission
Service that were submitted to the IDC by that time and issue a second ADJUST List if those additional
Interchange Transactions are found.
All existing or new Interchange Transactions using Non-firm Point-to-Point Transmission Service that are
increasing or expected to start during the current hour or next hour will be placed on HALT or HOLD. There is
no Reallocation of lower-priority Interchange Transactions using Non-firm Point-to-Point Transmission Service.
Interchange Transactions using Firm Point-to-Point Transmission Service that were submitted to the IDC by
00:25 will be allowed to start as scheduled.
Interchange Transactions using Firm Point-to-Point Transmission Service that were submitted to the IDC after
00:25 will be held.
Once the SOL or IROL violation is mitigated, the Reliability Coordinator shall call a TLR Level 3a (or
lower). If a TLR Level 3a is called:
Interchange Transactions using Firm Point-to-Point Transmission Service that were submitted to the IDC
by 00:25 will be allowed to start as scheduled at 02:00.
Interchange Transactions using Non-firm Point-to-Point Transmission Service that were held may then be
reallocated to start at 02:00.
Approved by Board of Trustees: April 15, 2009
Effective Date: December 10, 2009
* per BCUC Order G-162-11
Page 31 of 35
ATTACHMENT C
to Order G-162-11
Page 98 of 143
Standard IRO-006-4.1 — Reliability Coordination — Transmission Loading Relief
Case 2: TLR 3b is called after 00:25 and the Interchange Transaction using Firm Point-to-Point
Transmission Service is submitted to the IDC no later than the time at which the TLR 3b is called.
Firm Transactions
that are in the IDC
by start of TLR 3b
are started as
scheduled
Firm Transactions
must be submitted
to IDC by start of
TLR 3b to start
TLR 3b
00:25
00:00
00:10
00:20
Beginning of
Current Hour
00:30
IDC issues
Congestion
Management
Report based on
time of calling
TLR 3b. ADJUST
List follows.
00:40
00:50
01:00
Beginning of
Next Hour
The IDC will examine the current hour (00) and next hour (01) for all Interchange Transactions.
The IDC will issue an ADJUST List at the time the TLR 3b is called. The ADJUST List will include
additional curtailments of Interchange Transactions using Non-firm Point-to-Point Transmission Service
as necessary to allow room for those Interchange Transactions using Firm Point-to-Point Transmission
Service to start at as scheduled.
All existing or new Interchange Transactions using Non-firm Point-to-Point Transmission Service that are
increasing or expected to start during the current hour or next hour will be placed on HALT or HOLD.
There is no Reallocation of lower-priority Interchange Transactions using Non-firm Point-to-Point
Transmission Service.
Interchange Transactions using Firm Point-to-Point Transmission Service that were submitted to the IDC
by the time the TLR 3b was called will be allowed to start at as scheduled.
Interchange Transaction using Firm Point-to-Point Transmission Service that were submitted to the IDC
after the TLR 3b was called will be held until the next issuance for TLR (either TLR 3b, 3a, or lower
level).
Approved by Board of Trustees: April 15, 2009
Effective Date: December 10, 2009
* per BCUC Order G-162-11
Page 32 of 35
ATTACHMENT C
to Order G-162-11
Page 99 of 143
Standard IRO-006-4.1 — Reliability Coordination — Transmission Loading Relief
Case 3. TLR 2 or higher is in effect, a TLR 3b is called after 00:25, and the Interchange
Transaction using Firm Point-to-Point Transmission Service is submitted to the IDC by 00:25.
Firm Transactions
must be submitted
to IDC by 00:25 to
start as scheduled
Firm Transactions
that are in IDC by
00:25 may start as
scheduled
TLR 2 or higher
TLR 3b
00:25
00:00
00:10
00:20
Beginning of
Current Hour
00:30
IDC issues
Congestion
Management
Report based on
time of calling
TLR 3b. ADJUST
List follows.
00:40
00:50
01:00
Beginning of
Next Hour
If a TLR 2 or higher has been issued and 3B is subsequently issued, then only those Interchange
Transactions using Firm Point-to-Point Transmission Service that had been submitted to the IDC by
00:25 will be allowed to start as scheduled. All other Interchange Transactions are held.
Approved by Board of Trustees: April 15, 2009
Effective Date: December 10, 2009
* per BCUC Order G-162-11
Page 33 of 35
ATTACHMENT C
to Order G-162-11
Page 100 of 143
Standard IRO-006-4.1 — Reliability Coordination — Transmission Loading Relief
Case 4. TLR 3b is called before 00:25 and the Interchange Transaction is submitted to the IDC by
00:25. TLR 3a is called at 00:40.
Non-firm
Transactions are
Reallocated at
01:00.
Firm Transactions
must be submitted
to IDC by 00:25 to
start as scheduled
Firm
Transactions are
started as
scheduled
TLR 3b
TLR 3a
00:25
00:00
00:10
00:20
Beginning of
Current Hour
IDC issues
Congestion
Management
Report based on
time of calling TLR
3b. ADJUST List
follows.
00:30
00:40
00:50
IDC checks for
additional approved
Firm Transactions.
Congestion
Management Report
and second ADJUST
List issued if needed.
01:00
Beginning of
Next Hour
Same as Case 1, but TLR Level 3b ends at 00:40 and becomes TLR Level 3a.
All Interchange Transactions using Firm Point-to-Point Transmission Service will start as scheduled if in
by the time the 3A is declared.
All Interchange Transactions using Non-firm Point-to-Point Transmission Service are reallocated at
01:00.
Approved by Board of Trustees: April 15, 2009
Effective Date: December 10, 2009
* per BCUC Order G-162-11
Page 34 of 35
ATTACHMENT C
to Order G-162-11
Page 101 of 143
Standard IRO-006-4.1 — Reliability Coordination — Transmission Loading Relief
Case 5. TLR 3b is called before 00:25 and the Interchange Transaction is submitted to the IDC by
00:25. TLR 1 is called at 00:40.
Firm
Transactions are
started as
scheduled. Nonfirm
Transactions
may be loaded.
Firm Transactions
must be submitted
to IDC by 00:25 to
start as scheduled
TLR 3b
TLR 1
00:25
00:00
00:10
00:20
00:30
Beginning of
Current Hour
IDC issues
Congestion
Management
Report based on
time of calling
TLR 3b. ADJUST
List follows.
00:40
IDC checks for
additional approved
Firm Transactions.
Congestion
Management Report
and second ADJUST
List issued if needed.
00:50
01:00
Beginning of
Next Hour
Same as Case 1, but TLR Level 3b ends at 00:40 and becomes TLR Level 1.
All Interchange Transactions using Firm Point-to-Point Transmission Service will start as scheduled.
All Interchange Transactions using Non-firm Point-to-Point Transmission Service may be loaded
immediately.
Approved by Board of Trustees: April 15, 2009
Effective Date: December 10, 2009
* per BCUC Order G-162-11
Page 35 of 35
ATTACHMENT C
to Order G-162-11
Page 102 of 143
Standard MOD-021-0.1 — Accounting Methodology for Effects of Controllable DSM in Forecasts
A. Introduction
1.
Title:
Documentation of the Accounting Methodology for the Effects of
Controllable Demand-Side Management in Demand and Energy Forecasts.
2.
Number:
3.
Purpose:
To ensure that assessments and validation of past events and databases can be
performed, reporting of actual Demand data is needed. Forecast demand data is needed to
perform future system assessments to identify the need for system reinforcement for continued
reliability. In addition, to assist in proper real-time operating, load information related to
controllable Demand-Side Management (DSM) programs is needed.
4.
Applicability:
MOD-021-0.1
4.1. Load-Serving Entity
4.2. Transmission Planner
4.3. Resource Planner
5.
*Effective Date:
December 10, 2009
B. Requirements
R1.
The Load-Serving Entity, Transmission Planner and Resource Planner’s forecasts shall each
clearly document how the Demand and energy effects of DSM programs (such as conservation,
time-of-use rates, interruptible Demands, and Direct Control Load Management) are addressed.
R2.
The Load-Serving Entity, Transmission Planner and Resource Planner shall each include
information detailing how Demand-Side Management measures are addressed in the forecasts
of its Peak Demand and annual Net Energy for Load in the data reporting procedures of
Standard MOD-016-0_R1.
R3.
The Load-Serving Entity, Transmission Planner and Resource Planner shall each make
documentation on the treatment of its DSM programs available to NERC on request (within 30
calendar days).
C. Measures
M1. The Load-Serving Entity, Transmission Planner and Resource Planner forecasts clearly
document how the demand and energy effects of DSM programs (such as conservation, timeof-use rates, interruptible demands, and Direct Control Load Management) are addressed.
M2. The Load-Serving Entity, Transmission Planner and Resource Planner information detailing
how Demand-Side Management measures are addressed in the forecasts of Peak Demand and
annual Net Energy for Load are included in the data reporting procedures of Reliability
Standard MOD-016-0_R1.
M3. The Load-Serving Entity, Planning Authority and Resource Planner shall each provide
evidence to its Compliance Monitor that it provided documentation on the treatment of DSM
programs to NERC as requested (within 30 calendar days).
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
Compliance Monitor: the British Columbia Utilities Commission
Compliance Monitor’s Administrator: the Western Electricity Coordinating Council
Adopted by NERC Board of Trustees: April 15, 2009
Effective Date: December 10, 2009
* per BCUC Order G-162-11
1 of 2
ATTACHMENT C
to Order G-162-11
Page 103 of 143
Standard MOD-021-0.1 — Accounting Methodology for Effects of Controllable DSM in Forecasts
1.2. Compliance Monitoring Period and Reset Timeframe
On request (within 30 calendar days).
1.3. Data Retention
None specified.
1.4. Additional Compliance Information
None.
2.
Levels of Non-Compliance
2.1. Level 1:
Documentation on the treatment of DSM programs in the demand and
energy forecasts was provided, but was incomplete.
2.2. Level 2:
Not applicable.
2.3. Level 3:
Not applicable.
2.4. Level 4:
Documentation on the treatment of DSM programs in the demand and
energy forecasts was not provided.
E. Regional Differences
1.
None identified.
Version History
Version
Date
Action
Change Tracking
0
April 1, 2005
Effective Date
New
0.1
April 15, 2009
R1. – comma inserted after Load-Serving
Entity
0.1
December 10, 2009
Approved by FERC — Added effective date
Adopted by NERC Board of Trustees: April 15, 2009
Effective Date: December 10, 2009
* per BCUC Order G-162-11
Update
2 of 2
ATTACHMENT C
to Order G-162-11
Page 104 of 143
Standard PER-001-0.1 — Operating Personnel Responsibility and Authority
A. Introduction
1.
Title:
Operating Personnel Responsibility and Authority
2.
Number:
PER-001-0.1
3.
Purpose:
Transmission Operator and Balancing Authority operating personnel must have
the responsibility and authority to implement real-time actions to ensure the stable and reliable
operation of the Bulk Electric System.
4.
Applicability
4.1. Transmission Operators.
4.2. Balancing Authorities.
5.
*Effective Date:
December 10, 2009
B. Requirements
R1.
Each Transmission Operator and Balancing Authority shall provide operating personnel with
the responsibility and authority to implement real-time actions to ensure the stable and reliable
operation of the Bulk Electric System.
C. Measures
M1. The Transmission Operator and Balancing Authority provide documentation that operating
personnel have the responsibility and authority to implement real-time actions to ensure the
stable and reliable operation of the Bulk Electric System. These responsibilities and authorities
are understood by the operating personnel. Documentation shall include:
M1.1
A written current job description that states in clear and unambiguous language the
responsibilities and authorities of each operating position of a Transmission Operator
and Balancing Authority. The job description identifies personnel subject to the
authority of the Transmission Operator and Balancing Authority.
M1.2
The current job description is readily accessible in the control room environment to all
operating personnel.
M1.3
A written current job description that states operating personnel are responsible for
complying with the NERC reliability standards.
M1.4
Written operating procedures that state that, during normal and emergency conditions,
operating personnel have the authority to take or direct timely and appropriate realtime actions. Such actions shall include shedding of firm load to prevent or alleviate
System Operating Limit Interconnection or Reliability Operating Limit violations.
These actions are performed without obtaining approval from higher-level personnel
within the Transmission Operator or Balancing Authority.
D. Compliance
1.
Compliance Monitoring Process
Periodic Review: An on-site review including interviews with Transmission Operator and
Balancing Authority operating personnel and document verification will be conducted every
three years. The job description identifying operating personnel authorities and responsibilities
will be reviewed, as will the written operating procedures or other documents delineating the
authority of the operating personnel to take actions necessary to maintain the reliability of the
Bulk Electric System during normal and emergency conditions.
Adopted by NERC Board of Trustees: April 15, 2009
Effective Date: December 10, 2009
* per BCUC Order G-162-11
1 of 2
ATTACHMENT C
to Order G-162-11
Page 105 of 143
Standard PER-001-0.1 — Operating Personnel Responsibility and Authority
1.1. Compliance Monitoring Responsibility
Self-certification: The Transmission Operator and Balancing Authority shall annually
complete a self-certification form developed by the Regional Reliability Organization
based on measures M1.1 to M1.4.
1.2. Compliance Monitoring Period and Reset Timeframe
One calendar year.
1.3. Data Retention
Permanent.
1.4. Additional Compliance Information
2.
Levels of Non-Compliance
2.1. Level 1:
The Transmission Operator or Balancing Authority has written
documentation that includes three of the four items in M1.
2.2. Level 2:
The Transmission Operator or Balancing Authority has written
documentation that includes two of the four items in M1.
2.3. Level 3:
The Transmission Operator or Balancing Authority has written
documentation that includes one of the four items in M1.
2.4. Level 4:
The Transmission Operator or Balancing Authority has written
documentation that includes none of the items in M1, or the personnel interviews indicate
Transmission Operator or Balancing Authority do not have the required authority.
E. Regional Differences
None identified.
Version History
Version
Date
Action
Change Tracking
0
April 1, 2005
Effective Date
New
0
August 8, 2005
Removed “Proposed” from Effective Date
Errata
0.1
April 15, 2009
Replaced “position” with “job” on M1.1
Errata
0.1
December 10,
2009
Approved by FERC — added effective date
Update
Adopted by NERC Board of Trustees: April 15, 2009
Effective Date: December 10, 2009
* per BCUC Order G-162-11
2 of 2
ATTACHMENT C
to Order G-162-11
Page 106 of 143
Standard PRC-023-1 — Transmission Relay Loadability
A. Introduction
1. Title: Transmission Relay Loadability
2. Number:
PRC-023-1
3. Purpose: Protective relay settings shall not limit transmission loadability; not interfere with
system operators’ ability to take remedial action to protect system reliability and; be set to
reliably detect all fault conditions and protect the electrical network from these faults.
4. Applicability:
4.1. Transmission Owners with load-responsive phase protection systems as described in
Attachment A, applied to facilities defined below:
4.1.1 Transmission lines operated at 200 kV and above.
4.1.2 Transmission lines operated at 100 kV to 200 kV as designated by the Planning
Coordinator as critical to the reliability of the Bulk Electric System.
4.1.3 Transformers with low voltage terminals connected at 200 kV and above.
4.1.4 Transformers with low voltage terminals connected at 100 kV to 200 kV as
designated by the Planning Coordinator as critical to the reliability of the Bulk
Electric System.
4.2. Generator Owners with load-responsive phase protection systems as described in
Attachment A, applied to facilities defined in 4.1.1 through 4.1.4.
4.3. Distribution Providers with load-responsive phase protection systems as described in
Attachment A, applied according to facilities defined in 4.1.1 through 4.1.4., provided that
those facilities have bi-directional flow capabilities.
4.4. Planning Coordinators.
5. * Effective Dates1:
5.1. Requirement 1, Requirement 2:
5.1.1 For circuits described in 4.1.1 and 4.1.3 above (except for switch-on-to-fault
schemes) —the beginning of the first calendar quarter following applicable
regulatory approvals.
5.1.2 For circuits described in 4.1.2 and 4.1.4 above (including switch-on-to-fault
schemes) — at the beginning of the first calendar quarter 39 months following
applicable regulatory approvals.
5.1.3 Each Transmission Owner, Generator Owner, and Distribution Provider shall have
24 months after being notified by its Planning Coordinator pursuant to R3.3 to
comply with R1 (including all sub-requirements) for each facility that is added to
the Planning Coordinator’s critical facilities list determined pursuant to R3.1.
5.2. Requirement 3: 18 months following applicable regulatory approvals.
1 Temporary Exceptions that have already been approved by the NERC Planning Committee via the NERC System
Protection and Control Task Force prior to the approval of this standard shall not result in either findings of noncompliance or sanctions if all of the following apply: (1) the approved requests for Temporary Exceptions include a
mitigation plan (including schedule) to come into full compliance, and (2) the non-conforming relay settings are
mitigated according to the approved mitigation plan.
Approved by Board of Trustees: February 12, 2008
* per BCUC Order G‐162‐11 1 ATTACHMENT C
to Order G-162-11
Page 107 of 143
Standard PRC-023-1 — Transmission Relay Loadability
B. Requirements
R1.
Each Transmission Owner, Generator Owner, and Distribution Provider shall use any one of
the following criteria (R1.1 through R1.13) for any specific circuit terminal to prevent its phase
protective relay settings from limiting transmission system loadability while maintaining
reliable protection of the Bulk Electric System for all fault conditions. Each Transmission
Owner, Generator Owner, and Distribution Provider shall evaluate relay loadability at 0.85 per
unit voltage and a power factor angle of 30 degrees: [Violation Risk Factor: High] [Mitigation
Time Horizon: Long Term Planning].
R1.1.
Set transmission line relays so they do not operate at or below 150% of the highest
seasonal Facility Rating of a circuit, for the available defined loading duration nearest
4 hours (expressed in amperes).
R1.2.
Set transmission line relays so they do not operate at or below 115% of the highest
seasonal 15-minute Facility Rating2 of a circuit (expressed in amperes).
R1.3.
Set transmission line relays so they do not operate at or below 115% of the maximum
theoretical power transfer capability (using a 90-degree angle between the sendingend and receiving-end voltages and either reactance or complex impedance) of the
circuit (expressed in amperes) using one of the following to perform the power
transfer calculation:
R1.3.1. An infinite source (zero source impedance) with a 1.00 per unit bus voltage
at each end of the line.
R1.3.2. An impedance at each end of the line, which reflects the actual system
source impedance with a 1.05 per unit voltage behind each source
impedance.
R1.4.
Set transmission line relays on series compensated transmission lines so they do not
operate at or below the maximum power transfer capability of the line, determined as
the greater of:
-
115% of the highest emergency rating of the series capacitor.
-
115% of the maximum power transfer capability of the circuit (expressed in
amperes), calculated in accordance with R1.3, using the full line inductive
reactance.
R1.5.
Set transmission line relays on weak source systems so they do not operate at or below
170% of the maximum end-of-line three-phase fault magnitude (expressed in
amperes).
R1.6.
Set transmission line relays applied on transmission lines connected to generation
stations remote to load so they do not operate at or below 230% of the aggregated
generation nameplate capability.
R1.7.
Set transmission line relays applied at the load center terminal, remote from
generation stations, so they do not operate at or below 115% of the maximum current
flow from the load to the generation source under any system configuration.
2
When a 15-minute rating has been calculated and published for use in real-time operations, the 15-minute rating
can be used to establish the loadability requirement for the protective relays.
Approved by Board of Trustees: February 12, 2008
* per BCUC Order G‐162‐11 2 ATTACHMENT C
to Order G-162-11
Page 108 of 143
Standard PRC-023-1 — Transmission Relay Loadability
R1.8.
Set transmission line relays applied on the bulk system-end of transmission lines that
serve load remote to the system so they do not operate at or below 115% of the
maximum current flow from the system to the load under any system configuration.
R1.9.
Set transmission line relays applied on the load-end of transmission lines that serve
load remote to the bulk system so they do not operate at or below 115% of the
maximum current flow from the load to the system under any system configuration.
R1.10. Set transformer fault protection relays and transmission line relays on transmission
lines terminated only with a transformer so that they do not operate at or below the
greater of:
-
150% of the applicable maximum transformer nameplate rating (expressed in
amperes), including the forced cooled ratings corresponding to all installed
supplemental cooling equipment.
-
115% of the highest operator established emergency transformer rating.
R1.11. For transformer overload protection relays that do not comply with R1.10 set the
relays according to one of the following:
-
Set the relays to allow the transformer to be operated at an overload level of at
least 150% of the maximum applicable nameplate rating, or 115% of the highest
operator established emergency transformer rating, whichever is greater. The
protection must allow this overload for at least 15 minutes to allow for the
operator to take controlled action to relieve the overload.
-
Install supervision for the relays using either a top oil or simulated winding hot
spot temperature element. The setting should be no less than 100° C for the top
oil or 140° C for the winding hot spot temperature3.
R1.12. When the desired transmission line capability is limited by the requirement to
adequately protect the transmission line, set the transmission line distance relays to a
maximum of 125% of the apparent impedance (at the impedance angle of the
transmission line) subject to the following constraints:
R1.12.1. Set the maximum torque angle (MTA) to 90 degrees or the highest
supported by the manufacturer.
R1.12.2. Evaluate the relay loadability in amperes at the relay trip point at 0.85 per
unit voltage and a power factor angle of 30 degrees.
R1.12.3. Include a relay setting component of 87% of the current calculated in
R1.12.2 in the Facility Rating determination for the circuit.
R1.13. Where other situations present practical limitations on circuit capability, set the phase
protection relays so they do not operate at or below 115% of such limitations.
R2.
The Transmission Owner, Generator Owner, or Distribution Provider that uses a circuit
capability with the practical limitations described in R1.6, R1.7, R1.8, R1.9, R1.12, or R1.13
shall use the calculated circuit capability as the Facility Rating of the circuit and shall obtain
the agreement of the Planning Coordinator, Transmission Operator, and Reliability Coordinator
with the calculated circuit capability. [Violation Risk Factor: Medium] [Time Horizon: Long
Term Planning]
3
IEEE standard C57.115, Table 3, specifies that transformers are to be designed to withstand a winding hot spot
temperature of 180 degrees C, and cautions that bubble formation may occur above 140 degrees C.
Approved by Board of Trustees: February 12, 2008
* per BCUC Order G‐162‐11 3 ATTACHMENT C
to Order G-162-11
Page 109 of 143
Standard PRC-023-1 — Transmission Relay Loadability
R3.
The Planning Coordinator shall determine which of the facilities (transmission lines operated at
100 kV to 200 kV and transformers with low voltage terminals connected at 100 kV to 200 kV)
in its Planning Coordinator Area are critical to the reliability of the Bulk Electric System to
identify the facilities from 100 kV to 200 kV that must meet Requirement 1 to prevent potential
cascade tripping that may occur when protective relay settings limit transmission loadability.
[Violation Risk Factor: Medium] [Time Horizon: Long Term Planning]
R3.1.
The Planning Coordinator shall have a process to determine the facilities that are
critical to the reliability of the Bulk Electric System.
R3.1.1. This process shall consider input from adjoining Planning Coordinators and
affected Reliability Coordinators.
R3.2.
The Planning Coordinator shall maintain a current list of facilities determined
according to the process described in R3.1.
R3.3.
The Planning Coordinator shall provide a list of facilities to its Reliability
Coordinators, Transmission Owners, Generator Owners, and Distribution Providers
within 30 days of the establishment of the initial list and within 30 days of any
changes to the list.
C. Measures
M1. The Transmission Owner, Generator Owner, and Distribution Provider shall each have
evidence to show that each of its transmission relays are set according to one of the criteria in
R1.1 through R1.13. (R1)
M2. The Transmission Owner, Generator Owner, and Distribution Provider with transmission
relays set according to the criteria in R1.6, R1.7, R1.8, R1.9, R1.12, or R.13 shall have
evidence that the resulting Facility Rating was agreed to by its associated Planning
Coordinator, Transmission Operator, and Reliability Coordinator. (R2)
M3. The Planning Coordinator shall have a documented process for the determination of facilities
as described in R3. The Planning Coordinator shall have a current list of such facilities and
shall have evidence that it provided the list to the approriate Reliability Coordinators,
Transmission Operators, Generator Operators, and Distribution Providers. (R3)
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
Compliance Monitor: the British Columbia Utilities Commission
Compliance Monitor’s Administrator: the Western Electricity Coordinating Council
1.2. Compliance Monitoring Period and Reset Time Frame
One calendar year.
1.3. Data Retention
The Transmission Owner, Generator Owner, and Distribution Provider shall each retain
documentation for three years.
The Planning Coordinator shall retain documentation of the most recent review process
required in R3. The Planning Coordinator shall retain the most recent list of facilities that are
critical to the reliability of the electric system determined per R3.
Approved by Board of Trustees: February 12, 2008
* per BCUC Order G‐162‐11 4 ATTACHMENT C
to Order G-162-11
Page 110 of 143
Standard PRC-023-1 — Transmission Relay Loadability
The Compliance Monitor shall retain its compliance documentation for three years.
1.4. Additional Compliance Information
The Transmission Owner, Generator Owner, Planning Coordinator, and Distribution Provider
shall each demonstrate compliance through annual self-certification, or compliance audit
(periodic, as part of targeted monitoring or initiated by complaint or event), as determined by
the Compliance Enforcement Authority.
Approved by Board of Trustees: February 12, 2008
* per BCUC Order G‐162‐11 5 ATTACHMENT C
to Order G-162-11
Page 111 of 143
Standard PRC-023-1 — Transmission Relay Loadability
2.
Violation Severity Levels:
Requirement
Lower
R1
Moderate
High
Evidence that relay settings
comply with criteria in R1.1
though 1.13 exists, but evidence is
incomplete or incorrect for one or
more of the subrequirements.
Severe
Relay settings do not comply with
any of the sub requirements R1.1
through R1.13
OR
Evidence does not exist to support
that relay settings comply with one
of the criteria in subrequirements
R1.1 through R1.13.
R2
Criteria described in R1.6, R1.7.
R1.8. R1.9, R1.12, or R.13 was
used but evidence does not exist
that agreement was obtained in
accordance with R2.
R3
Provided the list of facilities
critical to the reliability of the
Bulk Electric System to the
appropriate Reliability
Coordinators, Transmission
Owners, Generator Owners, and
Distribution Providers between 31
days and 45 days after the list was
established or updated.
Provided the list of facilities
critical to the reliability of the
Bulk Electric System to the
appropriate Reliability
Coordinators, Transmission
Owners, Generator Owners, and
Distribution Providers between 46
days and 60 days after list was
established or updated.
Does not have a process in place to
determine facilities that are critical
to the reliability of the Bulk
Electric System.
OR
Does not maintain a current list of
facilities critical to the reliability
of the Bulk Electric System,
OR
Did not provide the list of facilities
critical to the reliability of the
Bulk Electric System to the
appropriate Reliability
Coordinators, Transmission
Owners, Generator Owners, and
Distribution Providers, or provided
the list more than 60 days after the
list was established or updated.
Approved by Board of Trustees: February 12, 2008
* per BCUC Order G‐162‐11 6 ATTACHMENT C
to Order G-162-11
Page 112 of 143
Standard PRC-023-1 — Transmission Relay Loadability
E. Regional Differences
None
F. Supplemental Technical Reference Document
1. The following document is an explanatory supplement to the standard. It provides the technical
rationale underlying the requirements in this standard. The reference document contains
methodology examples for illustration purposes it does not preclude other technically comparable
methodologies
“Determination and Application of Practical Relaying Loadability Ratings,” Version 1.0, January
9, 2007, prepared by the System Protection and Control Task Force of the NERC Planning
Committee, available at: http://www.nerc.com/~filez/reports.html.
Version History
Version
Date
Action
Change Tracking
1
February 12,
2008
Approved by Board of Trustees
New
1
March 19, 2008
Corrected typo in last sentence of Severe
VSL for Requirement 3 — “then” should be
“than.”
Errata
1
March 18, 2010
Approved by FERC
Approved by Board of Trustees: February 12, 2008
* per BCUC Order G‐162‐11 7 ATTACHMENT C
to Order G-162-11
Page 113 of 143
Standard PRC-023-1 — Transmission Relay Loadability
Attachment A
1.
This standard includes any protective functions which could trip with or without time delay, on
load current, including but not limited to:
1.1. Phase distance.
1.2. Out-of-step tripping.
1.3. Switch-on-to-fault.
1.4. Overcurrent relays.
1.5. Communications aided protection schemes including but not limited to:
1.5.1 Permissive overreach transfer trip (POTT).
1.5.2 Permissive under-reach transfer trip (PUTT).
1.5.3 Directional comparison blocking (DCB).
1.5.4 Directional comparison unblocking (DCUB).
2.
This standard includes out-of-step blocking schemes which shall be evaluated to ensure that they
do not block trip for faults during the loading conditions defined within the requirements.
3.
The following protection systems are excluded from requirements of this standard:
3.1. Relay elements that are only enabled when other relays or associated systems fail. For
example:
•
Overcurrent elements that are only enabled during loss of potential conditions.
•
Elements that are only enabled during a loss of communications.
3.2. Protection systems intended for the detection of ground fault conditions.
3.3. Protection systems intended for protection during stable power swings.
3.4. Generator protection relays that are susceptible to load.
3.5. Relay elements used only for Special Protection Systems applied and approved in
accordance with NERC Reliability Standards PRC-012 through PRC-017.
3.6. Protection systems that are designed only to respond in time periods which allow operators
15 minutes or greater to respond to overload conditions.
3.7. Thermal emulation relays which are used in conjunction with dynamic Facility Ratings.
3.8. Relay elements associated with DC lines.
3.9. Relay elements associated with DC converter transformers.
Approved by Board of Trustees: February 12, 2008
* per BCUC Order G‐162‐11 8 ATTACHMENT C
to Order G-162-11
Page 114 of 143
Standard TOP-002-2a — Normal Operations Planning
A. Introduction
1.
Title:
Normal Operations Planning
2.
Number:
TOP-002-2a
3.
Purpose:
Current operations plans and procedures are essential to being prepared for
reliable operations, including response for unplanned events.
4.
Applicability
4.1. Balancing Authority.
4.2. Transmission Operator.
4.3. Generator Operator.
4.4. Load Serving Entity.
4.5. Transmission Service Provider.
5.
*Effective Date: Immediately after approval of applicable regulatory authorities. FERC
Approved 12/2/09
B. Requirements
R1.
Each Balancing Authority and Transmission Operator shall maintain a set of current plans that
are designed to evaluate options and set procedures for reliable operation through a reasonable
future time period. In addition, each Balancing Authority and Transmission Operator shall be
responsible for using available personnel and system equipment to implement these plans to
ensure that interconnected system reliability will be maintained.
R2.
Each Balancing Authority and Transmission Operator shall ensure its operating personnel
participate in the system planning and design study processes, so that these studies contain the
operating personnel perspective and system operating personnel are aware of the planning
purpose.
R3.
Each Load Serving Entity and Generator Operator shall coordinate (where confidentiality
agreements allow) its current-day, next-day, and seasonal operations with its Host Balancing
Authority and Transmission Service Provider. Each Balancing Authority and Transmission
Service Provider shall coordinate its current-day, next-day, and seasonal operations with its
Transmission Operator.
R4.
Each Balancing Authority and Transmission Operator shall coordinate (where confidentiality
agreements allow) its current-day, next-day, and seasonal planning and operations with
neighboring Balancing Authorities and Transmission Operators and with its Reliability
Coordinator, so that normal Interconnection operation will proceed in an orderly and consistent
manner.
R5.
Each Balancing Authority and Transmission Operator shall plan to meet scheduled system
configuration, generation dispatch, interchange scheduling and demand patterns.
R6.
Each Balancing Authority and Transmission Operator shall plan to meet unscheduled changes
in system configuration and generation dispatch (at a minimum N-1 Contingency planning) in
accordance with NERC, Regional Reliability Organization, subregional, and local reliability
requirements.
R7.
Each Balancing Authority shall plan to meet capacity and energy reserve requirements,
including the deliverability/capability for any single Contingency.
Adopted by Board of Trustees: February 10, 2009
Approved by FERC: December 2, 2009
* per BCUC Order G-162-11
Page 1 of 7
ATTACHMENT C
to Order G-162-11
Page 115 of 143
Standard TOP-002-2a — Normal Operations Planning
R8.
Each Balancing Authority shall plan to meet voltage and/or reactive limits, including the
deliverability/capability for any single contingency.
R9.
Each Balancing Authority shall plan to meet Interchange Schedules and ramps.
R10. Each Balancing Authority and Transmission Operator shall plan to meet all System Operating
Limits (SOLs) and Interconnection Reliability Operating Limits (IROLs).
R11. The Transmission Operator shall perform seasonal, next-day, and current-day Bulk Electric
System studies to determine SOLs. Neighboring Transmission Operators shall utilize identical
SOLs for common facilities. The Transmission Operator shall update these Bulk Electric
System studies as necessary to reflect current system conditions; and shall make the results of
Bulk Electric System studies available to the Transmission Operators, Balancing Authorities
(subject to confidentiality requirements), and to its Reliability Coordinator.
R12. The Transmission Service Provider shall include known SOLs or IROLs within its area and
neighboring areas in the determination of transfer capabilities, in accordance with filed tariffs
and/or regional Total Transfer Capability and Available Transfer Capability calculation
processes.
R13. At the request of the Balancing Authority or Transmission Operator, a Generator Operator shall
perform generating real and reactive capability verification that shall include, among other
variables, weather, ambient air and water conditions, and fuel quality and quantity, and provide
the results to the Balancing Authority or Transmission Operator operating personnel as
requested.
R14. Generator Operators shall, without any intentional time delay, notify their Balancing Authority
and Transmission Operator of changes in capabilities and characteristics including but not
limited to:
R14.1. Changes in real and reactive output capabilities. (Retired August 1, 2007)
R14.1. Changes in real output capabilities. (Effective August 1, 2007)
R14.2. Automatic Voltage Regulator status and mode setting. (Retired August 1, 2007)
R15. Generation Operators shall, at the request of the Balancing Authority or Transmission
Operator, provide a forecast of expected real power output to assist in operations planning
(e.g., a seven-day forecast of real output).
R16. Subject to standards of conduct and confidentiality agreements, Transmission Operators shall,
without any intentional time delay, notify their Reliability Coordinator and Balancing
Authority of changes in capabilities and characteristics including but not limited to:
R16.1. Changes in transmission facility status.
R16.2. Changes in transmission facility rating.
R17. Balancing Authorities and Transmission Operators shall, without any intentional time delay,
communicate the information described in the requirements R1 to R16 above to their
Reliability Coordinator.
R18. Neighboring Balancing Authorities, Transmission Operators, Generator Operators,
Transmission Service Providers and Load Serving Entities shall use uniform line identifiers
when referring to transmission facilities of an interconnected network.
R19. Each Balancing Authority and Transmission Operator shall maintain accurate computer models
utilized for analyzing and planning system operations.
C. Measures
Adopted by Board of Trustees: February 10, 2009
Approved by FERC: December 2, 2009
* per BCUC Order G-162-11
Page 2 of 7
ATTACHMENT C
to Order G-162-11
Page 116 of 143
Standard TOP-002-2a — Normal Operations Planning
M1. Each Balancing Authority and Transmission Operator shall have and provide upon request
evidence that could include, but is not limited to, documented planning procedures, copies of
current day plans, copies of seasonal operations plans, or other equivalent evidence that will be
used to confirm that it maintained a set of current plans. (Requirement 1 Part 1).
M2. Each Balancing Authority and Transmission Operator shall have and provide upon request
evidence that could include, but is not limited to, copies of current day plans or other
equivalent evidence that will be used to confirm that its plans address Requirements 5, 6, and
10.
M3. Each Balancing Authority shall have and provide upon request evidence that could include, but
is not limited to, copies of current day plans or other equivalent evidence that will be used to
confirm that its plans address Requirements 7, 8, and 9.
M4. Each Transmission Operator shall have and provide upon request evidence that could include,
but is not limited to, its next-day, and current-day Bulk Electric System studies used to
determine SOLs or other equivalent evidence that will be used to confirm that its studies reflect
current system conditions. (Requirement 11 Part 1)
M5. Each Transmission Operator shall have and provide upon request evidence that could include,
but is not limited to, voice recordings or transcripts of voice recordings, electronic
communications, or other equivalent evidence that will be used to confirm that the results of
Bulk Electric System studies were made available to the Transmission Operators, Balancing
Authorities (subject to confidentiality requirements), and to its Reliability Coordinator.
(Requirement 11 Part 2)
M6. Each Generator Operator shall have and provide upon request evidence that, when requested by
either a Transmission Operator or Balancing Authority, it performed a generating real and
reactive capability verification and provided the results to the requesting entity in accordance
with Requirement 13.
M7. Each Generator Operator shall have and provide upon request evidence that could include, but
is not limited to, voice recordings or transcripts of voice recordings, electronic
communications, or other equivalent evidence that will be used to confirm that without any
intentional time delay, it notified its Balancing Authority and Transmission Operator of
changes in real and reactive capabilities and AVR status. (Requirement 14)
M8. Each Generator Operator shall have and provide upon request evidence that could include, but
is not limited to, voice recordings or transcripts of voice recordings, electronic
communications, or other equivalent evidence that will be used to confirm that, on request, it
provided a forecast of expected real power output to assist in operations planning.
(Requirement 15)
M9. Each Transmission Operators shall have and provide upon request evidence that could include,
but is not limited to, voice recordings or transcripts of voice recordings, electronic
communications, or other equivalent evidence that will be used to confirm that, without any
intentional time delay, it notified its Balancing Authority and Reliability Coordinator of
changes in capabilities and characteristics. (Requirement16)
M10. Each Balancing Authority, Transmission Operator, Generator Operator, Transmission Service
Provider and Load Serving Entity shall have and provide upon request evidence that could
include, but is not limited to, a list of interconnected transmission facilities and their line
identifiers at each end or other equivalent evidence that will be used to confirm that it used
uniform line identifiers when referring to transmission facilities of an interconnected network.
(Requirement 18)
Adopted by Board of Trustees: February 10, 2009
Approved by FERC: December 2, 2009
* per BCUC Order G-162-11
Page 3 of 7
ATTACHMENT C
to Order G-162-11
Page 117 of 143
Standard TOP-002-2a — Normal Operations Planning
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
Compliance Monitor: the British Columbia Utilities Commission
Compliance Monitor’s Administrator: the Western Electricity Coordinating Council
1.2. Compliance Monitoring and Reset Time Frame
One or more of the following methods will be used to assess compliance:
-
Self-certification (Conducted annually with submission according to schedule.)
-
Spot Check Audits (Conducted anytime with up to 30 days notice given to prepare.)
-
Periodic Audit (Conducted once every three years according to schedule.)
-
Triggered Investigations (Notification of an investigation must be made within 60
days of an event or complaint of noncompliance. The entity will have up to 30
calendar days to prepare for the investigation. An entity may request an extension of
the preparation period and the extension will be considered by the Compliance
Monitor on a case-by-case basis.)
The Performance-Reset Period shall be 12 months from the last finding of noncompliance.
1.3. Data Retention
For Measures 1 and 2, each Transmission Operator shall have its current plans and a
rolling 6 months of historical records (evidence).
For Measures 1, 2, and 3 each Balancing Authority shall have its current plans and a
rolling 6 months of historical records (evidence).
For Measure 4, each Transmission Operator shall keep its current plans (evidence).
For Measures 5 and 9, each Transmission Operator shall keep 90 days of historical data
(evidence).
For Measures 6, 7 and 8, each Generator Operator shall keep 90 days of historical data
(evidence).
For Measure 10, each Balancing Authority, Transmission Operator, Generator Operator,
Transmission Service Provider, and Load-serving Entity shall have its current list
interconnected transmission facilities and their line identifiers at each end or other
equivalent evidence as evidence.
If an entity is found non-compliant the entity shall keep information related to the
noncompliance until found compliant or for two years plus the current year, whichever is
longer.
Evidence used as part of a triggered investigation shall be retained by the entity being
investigated for one year from the date that the investigation is closed, as determined by
the Compliance Monitor,
The Compliance Monitor shall keep the last periodic audit report and all supporting
compliance data
Adopted by Board of Trustees: February 10, 2009
Approved by FERC: December 2, 2009
* per BCUC Order G-162-11
Page 4 of 7
ATTACHMENT C
to Order G-162-11
Page 118 of 143
Standard TOP-002-2a — Normal Operations Planning
1.4. Additional Compliance Information
None.
2.
Levels of Non-Compliance for Balancing Authorities:
2.1. Level 1: Did not use uniform line identifiers when referring to transmission facilities of
an interconnected network as specified in R18.
2.2. Level 2: Not applicable.
2.3. Level 3: Not applicable.
2.4. Level 4: There shall be a separate Level 4 non-compliance, for every one of the following
requirements that is in violation:
3.
2.4.1
Did not maintain an updated set of current-day plans as specified in R1.
2.4.2
Plans did not meet one or more of the requirements specified in R5 through R10.
Levels of Non-Compliance for Transmission Operators
3.1. Level 1: Did not use uniform line identifiers when referring to transmission facilities of
an interconnected network as specified in R18.
3.2. Level 2: Not applicable.
3.3. Level 3: One or more of Bulk Electric System studies were not made available as
specified in R11.
3.4. Level 4: There shall be a separate Level 4 non-compliance, for every one of the
following requirements that is in violation:
4.
3.4.1
Did not maintain an updated set of current-day plans as specified in R1.
3.4.2
Plans did not meet one or more of the requirements in R5, R6, and R10.
3.4.3
Studies not updated to reflect current system conditions as specified in R11.
3.4.4
Did not notify its Balancing Authority and Reliability Coordinator of changes in
capabilities and characteristics as specified in R16.
Levels of Non-Compliance for Generator Operators:
4.1. Level 1: Did not use uniform line identifiers when referring to transmission facilities of
an interconnected network as specified in R18.
4.2. Level 2: Not applicable.
4.3. Level 3: Not applicable.
4.4. Level 4: There shall be a separate Level 4 non-compliance, for every one of the
following requirements that is in violation:
5.
4.4.1
Did not verify and provide a generating real and reactive capability verification
and provide the results to the requesting entity as specified in R13.
4.4.2
Did not notify its Balancing Authority and Transmission Operator of changes in
capabilities and characteristics as specified in R14.
4.4.3
Did not provide a forecast of expected real power output to assist in operations
planning as specified in R15.
Levels of Non-Compliance for Transmission Service Providers and Load-serving Entities:
Adopted by Board of Trustees: February 10, 2009
Approved by FERC: December 2, 2009
* per BCUC Order G-162-11
Page 5 of 7
ATTACHMENT C
to Order G-162-11
Page 119 of 143
Standard TOP-002-2a — Normal Operations Planning
5.1. Level 1: Did not use uniform line identifiers when referring to transmission facilities of
an interconnected network as specified in R18.
5.2. Level 2: Not applicable.
5.3. Level 3: Not applicable.
5.4. Level 4: Not applicable.
E. Regional Differences
None identified.
Version History
Version
Date
Action
Change Tracking
0
April 1, 2005
Effective Date
New
0
August 8, 2005
Removed “Proposed” from Effective Date
Errata
1
November 1, 2006
Adopted by Board of Trustees
Revised
2
June 14, 2007
Fixed typo in R11., (subject to …)
Errata
2a
February 10, 2009
Added Appendix 1 – Interpretation of R11
approved by BOT on February 10, 2009
Interpretation
2a
December 2, 2009
Interpretation of R11 approved by FERC on
December 2, 2009
Same Interpretation
Adopted by Board of Trustees: February 10, 2009
Approved by FERC: December 2, 2009
* per BCUC Order G-162-11
Page 6 of 7
ATTACHMENT C
to Order G-162-11
Page 120 of 143
Standard TOP-002-2a — Normal Operations Planning
Appendix 1
Interpretation of Requirement R11
Requirement Number and Text of Requirement
Requirement R11: The Transmission Operator shall perform seasonal, next-day, and current-day Bulk
Electric System studies to determine SOLs. Neighboring Transmission Operators shall utilize identical
SOLs for common facilities. The Transmission Operator shall update these Bulk Electric System studies
as necessary to reflect current system conditions; and shall make the results of Bulk Electric System
studies available to the Transmission Operators, Balancing Authorities (subject to confidentiality
requirements), and to its Reliability Coordinator.
Question #1
Is the Transmission Operator required to conduct a “unique” study for each operating day, even when the
actual or expected system conditions are identical to other days already studied? In other words, can a
study be used for more than one day?
Response to Question #1
Requirement R11 mandates that each Transmission Operator review (i.e., study) the state of its
Transmission Operator area both in advance of each day and during each day. Each day must have “a”
study that can be applied to it, but it is not necessary to generate a “unique” study for each day. Therefore,
it is acceptable for a Transmission Operator to use a particular study for more than one day.
Question #2
Are there specific actions required to implement a “study”? In other words, what constitutes a study?
Response to Question #2
The requirement does not mandate a particular type of review or study. The review or study may be based
on complex computer studies or a manual reasonability review of previously existing study results. The
requirement is designed to ensure the Transmission Operator maintains sensitivity to what is happening or
what is about to happen.
Question #3
Does the term, “to determine SOLs” as used in the first sentence of Requirement R11 mean the
“determination of system operating limits” or does it mean the “identification of potential SOL
violations?”
Response to Question #3
TOP-002-2 covers real-time and near-real-time studies. Requirement R11 is meant to include both
determining new limits and identifying potential “exceedances” of pre-defined SOLs. If system
conditions indicate to the Transmission Operator that prior studies and SOLs may be outdated, TOP-0022 mandates the Transmission Operator to conduct a study to identify SOLs for the new conditions. If the
Transmission Operator determines that system conditions do not warrant a new study, the primary
purpose of the review is to check that the previously defined (i.e., defined from the current SOLs in use,
or the set defined by the planners) SOLs are not expected to be exceeded. As written, the standard
provides the Transmission Operator discretion regarding when to look for new SOLs and when to rely on
its current set of SOLs.
Adopted by Board of Trustees: February 10, 2009
Approved by FERC: December 2, 2009
* per BCUC Order G-162-11
Page 7 of 7
ATTACHMENT C
to Order G-162-11
Page 121 of 143
Standard TPL-002-0a — System Performance Following Loss of a Single BES Element
A. Introduction
1.
Title:
System Performance Following Loss of a Single Bulk Electric System
Element (Category B)
2.
Number:
TPL-002-0a
3.
Purpose:
System simulations and associated assessments are needed periodically to ensure
that reliable systems are developed that meet specified performance requirements
with sufficient lead time, and continue to be modified or upgraded as necessary
to meet present and future system needs.
4.
Applicability:
4.1. Planning Authority
4.2. Transmission Planner
5.
*Effective Date:
April 23, 2010
B. Requirements
R1.
The Planning Authority and Transmission Planner shall each demonstrate through a valid
assessment that its portion of the interconnected transmission system is planned such that the
Network can be operated to supply projected customer demands and projected Firm (nonrecallable reserved) Transmission Services, at all demand levels over the range of forecast
system demands, under the contingency conditions as defined in Category B of Table I. To be
valid, the Planning Authority and Transmission Planner assessments shall:
R1.1.
Be made annually.
R1.2.
Be conducted for near-term (years one through five) and longer-term (years six
through ten) planning horizons.
R1.3.
Be supported by a current or past study and/or system simulation testing that
addresses each of the following categories,, showing system performance following
Category B of Table 1 (single contingencies). The specific elements selected (from
each of the following categories) for inclusion in these studies and simulations shall
be acceptable to the associated Regional Reliability Organization(s).
R1.3.1. Be performed and evaluated only for those Category B contingencies that
would produce the more severe System results or impacts. The rationale for
the contingencies selected for evaluation shall be available as supporting
information. An explanation of why the remaining simulations would
produce less severe system results shall be available as supporting
information.
R1.3.2. Cover critical system conditions and study years as deemed appropriate by
the responsible entity.
R1.3.3. Be conducted annually unless changes to system conditions do not warrant
such analyses.
R1.3.4. Be conducted beyond the five-year horizon only as needed to address
identified marginal conditions that may have longer lead-time solutions.
R1.3.5. Have all projected firm transfers modeled.
R1.3.6. Be performed and evaluated for selected demand levels over the range of
forecast system Demands.
Adopted by NERC Board of Trustees: July 30, 2008
Effective Date: April 23, 2010
* per BCUC Order G-162-11
Page 1 of 8
ATTACHMENT C
to Order G-162-11
Page 122 of 143
Standard TPL-002-0a — System Performance Following Loss of a Single BES Element
R1.3.7. Demonstrate that system performance meets Category B contingencies.
R1.3.8. Include existing and planned facilities.
R1.3.9. Include Reactive Power resources to ensure that adequate reactive resources
are available to meet system performance.
R1.3.10. Include the effects of existing and planned protection systems, including any
backup or redundant systems.
R1.3.11. Include the effects of existing and planned control devices.
R1.3.12. Include the planned (including maintenance) outage of any bulk electric
equipment (including protection systems or their components) at those
demand levels for which planned (including maintenance) outages are
performed.
R2.
R1.4.
Address any planned upgrades needed to meet the performance requirements of
Category B of Table I.
R1.5.
Consider all contingencies applicable to Category B.
When System simulations indicate an inability of the systems to respond as prescribed in
Reliability Standard TPL-002-0_R1, the Planning Authority and Transmission Planner shall
each:
R2.1.
Provide a written summary of its plans to achieve the required system performance as
described above throughout the planning horizon:
R2.1.1. Including a schedule for implementation.
R2.1.2. Including a discussion of expected required in-service dates of facilities.
R2.1.3. Consider lead times necessary to implement plans.
R2.2.
R3.
Review, in subsequent annual assessments, (where sufficient lead time exists), the
continuing need for identified system facilities. Detailed implementation plans are not
needed.
The Planning Authority and Transmission Planner shall each document the results of its
Reliability Assessments and corrective plans and shall annually provide the results to its
respective Regional Reliability Organization(s), as required by the Regional Reliability
Organization.
C. Measures
M1. The Planning Authority and Transmission Planner shall have a valid assessment and corrective
plans as specified in Reliability Standard TPL-002-0_R1 and TPL-002-0_R2.
M2. The Planning Authority and Transmission Planner shall have evidence it reported
documentation of results of its reliability assessments and corrective plans per Reliability
Standard TPL-002-0_R3.
Adopted by NERC Board of Trustees: July 30, 2008
Effective Date: April 23, 2010
* per BCUC Order G-162-11
Page 2 of 8
ATTACHMENT C
to Order G-162-11
Page 123 of 143
Standard TPL-002-0a — System Performance Following Loss of a Single BES Element
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
Compliance Monitor: the British Columbia Utilities Commission
Compliance Monitor’s Administrator: the Western Electricity Coordinating Council
1.2. Compliance Monitoring Period and Reset Timeframe
Annually.
1.3. Data Retention
None specified.
1.4. Additional Compliance Information
None.
2.
Levels of Non-Compliance
2.1. Level 1:
Not applicable.
2.2. Level 2: A valid assessment and corrective plan for the longer-term planning horizon is
not available.
2.3. Level 3:
Not applicable.
2.4. Level 4:
available.
A valid assessment and corrective plan for the near-term planning horizon is not
E. Regional Differences
1.
None identified.
Version History
Version
Date
Action
Change Tracking
0
April 1, 2005
Effective Date
New
0a
October 23,
2008
Added Appendix 1 – Interpretation of TPL002-0 Requirements R1.3.2 and R1.3.12
and TPL-003-0 Requirements R1.3.2 and
R1.3.12 for Ameren and MISO
Revised
0a
April 23, 2010
FERC approval of interpretation of TPL002-0 R1.3.2
Interpretation
Adopted by NERC Board of Trustees: July 30, 2008
Effective Date: April 23, 2010
* per BCUC Order G-162-11
Page 3 of 8
ATTACHMENT C
to Order G-162-11
Page 124 of 143
Standard TPL-002-0a — System Performance Following Loss of a Single BES Element
Table I. Transmission System Standards — Normal and Emergency Conditions
Category
Contingencies
Initiating Event(s) and Contingency
Element(s)
A
No Contingencies
B
Event resulting in
the loss of a single
element.
System Limits or Impacts
System Stable
and both
Loss of Demand
Thermal and
or
Voltage
Cascading
Outages
Curtailed Firm
Limits within
Transfers
Applicable
Rating a
All Facilities in Service
Yes
No
No
Single Line Ground (SLG) or 3-Phase (3Ø) Fault,
with Normal Clearing:
1. Generator
2. Transmission Circuit
3. Transformer
Loss of an Element without a Fault.
Yes
Yes
Yes
Yes
No b
No b
No b
No b
No
No
No
No
Yes
Nob
No
Yes
Planned/
Controlledc
Planned/
Controlledc
No
Planned/
Controlledc
No
e
Single Pole Block, Normal Clearing :
4. Single Pole (dc) Line
e
C
Event(s) resulting in
the loss of two or
more (multiple)
elements.
SLG Fault, with Normal Clearing :
1. Bus Section
2. Breaker (failure or internal Fault)
Yes
No
e
SLG or 3Ø Fault, with Normal Clearing , Manual
System Adjustments, followed by another SLG or
e
3Ø Fault, with Normal Clearing :
3. Category B (B1, B2, B3, or B4)
contingency, manual system adjustments,
followed by another Category B (B1, B2,
B3, or B4) contingency
Yes
e
Bipolar Block, with Normal Clearing :
4. Bipolar (dc) Line Fault (non 3Ø), with
e
Normal Clearing :
5. Any two circuits of a multiple circuit
towerlinef
Yes
Planned/
Controlledc
No
Yes
Planned/
Controlledc
No
Yes
Planned/
Controlledc
No
7. Transformer
Yes
Planned/
Controlledc
No
8. Transmission Circuit
Yes
Planned/
Controlledc
No
9. Bus Section
Yes
Planned/
Controlledc
No
e
SLG Fault, with Delayed Clearing (stuck breaker
or protection system failure):
6. Generator
Adopted by NERC Board of Trustees: July 30, 2008
Effective Date: April 23, 2010
* per BCUC Order G-162-11
Page 4 of 8
ATTACHMENT C
to Order G-162-11
Page 125 of 143
Standard TPL-002-0a — System Performance Following Loss of a Single BES Element
D
d
Extreme event resulting in
two or more (multiple)
elements removed or
Cascading out of service
e
3Ø Fault, with Delayed Clearing (stuck breaker or protection system
failure):
1. Generator
3. Transformer
2. Transmission Circuit
Evaluate for risks and
consequences.
ƒ
4. Bus Section
e
3Ø Fault, with Normal Clearing :
ƒ
5. Breaker (failure or internal Fault)
6. Loss of towerline with three or more circuits
7. All transmission lines on a common right-of way
8. Loss of a substation (one voltage level plus transformers)
ƒ
May involve substantial loss of
customer Demand and
generation in a widespread
area or areas.
Portions or all of the
interconnected systems may
or may not achieve a new,
stable operating point.
Evaluation of these events may
require joint studies with
neighboring systems.
9. Loss of a switching station (one voltage level plus transformers)
10. Loss of all generating units at a station
11. Loss of a large Load or major Load center
12. Failure of a fully redundant Special Protection System (or
remedial action scheme) to operate when required
13. Operation, partial operation, or misoperation of a fully redundant
Special Protection System (or Remedial Action Scheme) in
response to an event or abnormal system condition for which it
was not intended to operate
14. Impact of severe power swings or oscillations from Disturbances
in another Regional Reliability Organization.
a) Applicable rating refers to the applicable Normal and Emergency facility thermal Rating or system voltage limit as
determined and consistently applied by the system or facility owner. Applicable Ratings may include Emergency Ratings
applicable for short durations as required to permit operating steps necessary to maintain system control. All Ratings
must be established consistent with applicable NERC Reliability Standards addressing Facility Ratings.
b) Planned or controlled interruption of electric supply to radial customers or some local Network customers, connected to or
supplied by the Faulted element or by the affected area, may occur in certain areas without impacting the overall
reliability of the interconnected transmission systems. To prepare for the next contingency, system adjustments are
permitted, including curtailments of contracted Firm (non-recallable reserved) electric power Transfers.
c) Depending on system design and expected system impacts, the controlled interruption of electric supply to customers
(load shedding), the planned removal from service of certain generators, and/or the curtailment of contracted Firm (nonrecallable reserved) electric power Transfers may be necessary to maintain the overall reliability of the interconnected
transmission systems.
d) A number of extreme contingencies that are listed under Category D and judged to be critical by the transmission
planning entity(ies) will be selected for evaluation. It is not expected that all possible facility outages under each listed
contingency of Category D will be evaluated.
e) Normal clearing is when the protection system operates as designed and the Fault is cleared in the time normally expected
with proper functioning of the installed protection systems. Delayed clearing of a Fault is due to failure of any protection
system component such as a relay, circuit breaker, or current transformer, and not because of an intentional design delay.
f) System assessments may exclude these events where multiple circuit towers are used over short distances (e.g., station
entrance, river crossings) in accordance with Regional exemption criteria.
Adopted by NERC Board of Trustees: July 30, 2008
Effective Date: April 23, 2010
* per BCUC Order G-162-11
Page 5 of 8
ATTACHMENT C
to Order G-162-11
Page 126 of 143
Standard TPL-002-0a — System Performance Following Loss of a Single BES Element
Appendix 1
Interpretation of TPL-002-0 Requirements R1.3.2 and R1.3.12 and
TPL-003-0 Requirements R1.3.2 and R1.3.12 for Ameren and MISO
NERC received two requests for interpretation of identical requirements (Requirements R1.3.2 and
R1.3.12) in TPL-002-0 and TPL-003-0 from the Midwest ISO and Ameren. These requirements state:
TPL-002-0:
[To be valid, the Planning Authority and Transmission Planner assessments shall:]
R1.3
Be supported by a current or past study and/or system simulation testing that addresses each
of the following categories, showing system performance following Category B of Table 1
(single contingencies). The specific elements selected (from each of the following categories)
for inclusion in these studies and simulations shall be acceptable to the associated Regional
Reliability Organization(s).
R1.3.2
Cover critical system conditions and study years as deemed appropriate by the
responsible entity.
R1.3.12 Include the planned (including maintenance) outage of any bulk electric equipment
(including protection systems or their components) at those demand levels for which
planned (including maintenance) outages are performed.
TPL-003-0:
[To be valid, the Planning Authority and Transmission Planner assessments shall:]
R1.3
Be supported by a current or past study and/or system simulation testing that addresses each
of the following categories, showing system performance following Category C of Table 1
(multiple contingencies). The specific elements selected (from each of the following
categories) for inclusion in these studies and simulations shall be acceptable to the associated
Regional Reliability Organization(s).
R1.3.2
Cover critical system conditions and study years as deemed appropriate by the
responsible entity.
R1.3.12 Include the planned (including maintenance) outage of any bulk electric equipment
(including protection systems or their components) at those demand levels for which
planned (including maintenance) outages are performed.
Requirement R1.3.2
Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.2
Received from Ameren on July 25, 2007:
Ameren specifically requests clarification on the phrase, ‘critical system conditions’ in R1.3.2. Ameren
asks if compliance with R1.3.2 requires multiple contingent generating unit Outages as part of possible
generation dispatch scenarios describing critical system conditions for which the system shall be planned
and modeled in accordance with the contingency definitions included in Table 1.
Adopted by NERC Board of Trustees: July 30, 2008
Effective Date: April 23, 2010
* per BCUC Order G-162-11
Page 6 of 8
ATTACHMENT C
to Order G-162-11
Page 127 of 143
Standard TPL-002-0a — System Performance Following Loss of a Single BES Element
Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.2
Received from MISO on August 9, 2007:
MISO asks if the TPL standards require that any specific dispatch be applied, other than one that is
representative of supply of firm demand and transmission service commitments, in the modeling of system
contingencies specified in Table 1 in the TPL standards.
MISO then asks if a variety of possible dispatch patterns should be included in planning analyses
including a probabilistically based dispatch that is representative of generation deficiency scenarios,
would it be an appropriate application of the TPL standard to apply the transmission contingency
conditions in Category B of Table 1 to these possible dispatch pattern.
The following interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.2 was developed by
the NERC Planning Committee on March 13, 2008:
The selection of a credible generation dispatch for the modeling of critical system conditions is within the
discretion of the Planning Authority. The Planning Authority was renamed “Planning Coordinator” (PC)
in the Functional Model dated February 13, 2007. (TPL -002 and -003 use the former “Planning
Authority” name, and the Functional Model terminology was a change in name only and did not affect
responsibilities.)
−
Under the Functional Model, the Planning Coordinator “Provides and informs Resource Planners,
Transmission Planners, and adjacent Planning Coordinators of the methodologies and tools for the
simulation of the transmission system” while the Transmission Planner “Receives from the Planning
Coordinator methodologies and tools for the analysis and development of transmission expansion
plans.” A PC’s selection of “critical system conditions” and its associated generation dispatch falls
within the purview of “methodology.”
Furthermore, consistent with this interpretation, a Planning Coordinator would formulate critical system
conditions that may involve a range of critical generator unit outages as part of the possible generator
dispatch scenarios.
Both TPL-002-0 and TPL-003-0 have a similar measure M1:
M1.
The Planning Authority and Transmission Planner shall have a valid assessment and
corrective plans as specified in Reliability Standard TPL-002-0_R1 [or TPL-003-0_R1]
and TPL-002-0_R2 [or TPL-003-0_R2].”
The Regional Reliability Organization (RRO) is named as the Compliance Monitor in both standards.
Pursuant to Federal Energy Regulatory Commission (FERC) Order 693, FERC eliminated the RRO as the
appropriate Compliance Monitor for standards and replaced it with the Regional Entity (RE). See
paragraph 157 of Order 693. Although the referenced TPL standards still include the reference to the
RRO, to be consistent with Order 693, the RRO is replaced by the RE as the Compliance Monitor for this
interpretation. As the Compliance Monitor, the RE determines what a “valid assessment” means when
evaluating studies based upon specific sub-requirements in R1.3 selected by the Planning Coordinator and
the Transmission Planner. If a PC has Transmission Planners in more than one region, the REs must
coordinate among themselves on compliance matters.
Adopted by NERC Board of Trustees: July 30, 2008
Effective Date: April 23, 2010
* per BCUC Order G-162-11
Page 7 of 8
ATTACHMENT C
to Order G-162-11
Page 128 of 143
Standard TPL-002-0a — System Performance Following Loss of a Single BES Element
Requirement R1.3.12
Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.12
Received from Ameren on July 25, 2007:
Ameren also asks how the inclusion of planned outages should be interpreted with respect to the
contingency definitions specified in Table 1 for Categories B and C. Specifically, Ameren asks if R1.3.12
requires that the system be planned to be operated during those conditions associated with planned
outages consistent with the performance requirements described in Table 1 plus any unidentified outage.
Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.12
Received from MISO on August 9, 2007:
MISO asks if the term “planned outages” means only already known/scheduled planned outages that may
continue into the planning horizon, or does it include potential planned outages not yet scheduled that
may occur at those demand levels for which planned (including maintenance) outages are performed?
If the requirement does include not yet scheduled but potential planned outages that could occur in the
planning horizon, is the following a proper interpretation of this provision?
The system is adequately planned and in accordance with the standard if, in order for a system operator
to potentially schedule such a planned outage on the future planned system, planning studies show that a
system adjustment (load shed, re-dispatch of generating units in the interconnection, or system
reconfiguration) would be required concurrent with taking such a planned outage in order to prepare for
a Category B contingency (single element forced out of service)? In other words, should the system in
effect be planned to be operated as for a Category C3 n-2 event, even though the first event is a planned
base condition?
If the requirement is intended to mean only known and scheduled planned outages that will occur or may
continue into the planning horizon, is this interpretation consistent with the original interpretation by
NERC of the standard as provided by NERC in response to industry questions in the Phase I development
of this standard1?
The following interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.12 was developed by
the NERC Planning Committee on March 13, 2008:
This provision was not previously interpreted by NERC since its approval by FERC and other regulatory
authorities. TPL-002-0 and TPL-003-0 explicitly provide that the inclusion of planned (including
maintenance) outages of any bulk electric equipment at demand levels for which the planned outages are
required. For studies that include planned outages, compliance with the contingency assessment for TPL002-0 and TPL-003-0 as outlined in Table 1 would include any necessary system adjustments which
might be required to accommodate planned outages since a planned outage is not a “contingency” as
defined in the NERC Glossary of Terms Used in Standards.
Adopted by NERC Board of Trustees: July 30, 2008
Effective Date: April 23, 2010
* per BCUC Order G-162-11
Page 8 of 8
ATTACHMENT C
to Order G-162-11
Page 129 of 143
Standard TPL-003-0a — System Performance Following Loss of Two or More BES Elements
A. Introduction
1.
Title:
System Performance Following Loss of Two or More Bulk Electric System
Elements (Category C)
2.
Number:
3.
Purpose:
System simulations and associated assessments are needed periodically to ensure
that reliable systems are developed that meet specified performance requirements, with
sufficient lead time and continue to be modified or upgraded as necessary to meet present and
future System needs.
4.
Applicability:
TPL-003-0a
4.1. Planning Authority
4.2. Transmission Planner
5.
*Effective Date:
April 23, 2010
B. Requirements
R1.
The Planning Authority and Transmission Planner shall each demonstrate through a valid
assessment that its portion of the interconnected transmission systems is planned such that the
network can be operated to supply projected customer demands and projected Firm (nonrecallable reserved) Transmission Services, at all demand Levels over the range of forecast
system demands, under the contingency conditions as defined in Category C of Table I
(attached). The controlled interruption of customer Demand, the planned removal of
generators, or the Curtailment of firm (non-recallable reserved) power transfers may be
necessary to meet this standard. To be valid, the Planning Authority and Transmission Planner
assessments shall:
R1.1.
Be made annually.
R1.2.
Be conducted for near-term (years one through five) and longer-term (years six
through ten) planning horizons.
R1.3.
Be supported by a current or past study and/or system simulation testing that
addresses each of the following categories, showing system performance following
Category C of Table 1 (multiple contingencies). The specific elements selected (from
each of the following categories) for inclusion in these studies and simulations shall
be acceptable to the associated Regional Reliability Organization(s).
R1.3.1. Be performed and evaluated only for those Category C contingencies that
would produce the more severe system results or impacts. The rationale for
the contingencies selected for evaluation shall be available as supporting
information. An explanation of why the remaining simulations would
produce less severe system results shall be available as supporting
information.
R1.3.2. Cover critical system conditions and study years as deemed appropriate by
the responsible entity.
R1.3.3. Be conducted annually unless changes to system conditions do not warrant
such analyses.
R1.3.4. Be conducted beyond the five-year horizon only as needed to address
identified marginal conditions that may have longer lead-time solutions.
R1.3.5. Have all projected firm transfers modeled.
Adopted by NERC Board of Trustees: July 30, 2008
Effective Date: April 23, 2010
* per BCUC Order G-162-11
Page 1 of 8
ATTACHMENT C
to Order G-162-11
Page 130 of 143
Standard TPL-003-0a — System Performance Following Loss of Two or More BES Elements
R1.3.6. Be performed and evaluated for selected demand levels over the range of
forecast system demands.
R1.3.7. Demonstrate that System performance meets Table 1 for Category C
contingencies.
R1.3.8. Include existing and planned facilities.
R1.3.9. Include Reactive Power resources to ensure that adequate reactive resources
are available to meet System performance.
R1.3.10. Include the effects of existing and planned protection systems, including any
backup or redundant systems.
R1.3.11. Include the effects of existing and planned control devices.
R1.3.12. Include the planned (including maintenance) outage of any bulk electric
equipment (including protection systems or their components) at those
Demand levels for which planned (including maintenance) outages are
performed.
R2.
R1.4.
Address any planned upgrades needed to meet the performance requirements of
Category C.
R1.5.
Consider all contingencies applicable to Category C.
When system simulations indicate an inability of the systems to respond as prescribed in
Reliability Standard TPL-003-0_R1, the Planning Authority and Transmission Planner shall each:
R2.1.
Provide a written summary of its plans to achieve the required system performance as
described above throughout the planning horizon:
R2.1.1. Including a schedule for implementation.
R2.1.2. Including a discussion of expected required in-service dates of facilities.
R2.1.3. Consider lead times necessary to implement plans.
R2.2.
R3.
Review, in subsequent annual assessments, (where sufficient lead time exists), the
continuing need for identified system facilities. Detailed implementation plans are not
needed.
The Planning Authority and Transmission Planner shall each document the results of these
Reliability Assessments and corrective plans and shall annually provide these to its respective
NERC Regional Reliability Organization(s), as required by the Regional Reliability
Organization.
C. Measures
M1. The Planning Authority and Transmission Planner shall have a valid assessment and corrective
plans as specified in Reliability Standard TPL-003-0_R1 and TPL-003-0_R2.
M2. The Planning Authority and Transmission Planner shall have evidence it reported
documentation of results of its reliability assessments and corrective plans per Reliability
Standard TPL-003-0_R3.
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
Adopted by NERC Board of Trustees: July 30, 2008
Effective Date: April 23, 2010
* per BCUC Order G-162-11
Page 2 of 8
ATTACHMENT C
to Order G-162-11
Page 131 of 143
Standard TPL-003-0a — System Performance Following Loss of Two or More BES Elements
Compliance Monitor: the British Columbia Utilities Commission
Compliance Monitor’s Administrator: the Western Electricity Coordinating Council
1.2. Compliance Monitoring Period and Reset Timeframe
Annually.
1.3. Data Retention
None specified.
1.4. Additional Compliance Information
None.
2.
Levels of Non-Compliance
2.1. Level 1:
Not applicable.
2.2. Level 2:
A valid assessment and corrective plan for the longer-term planning horizon
is not available.
2.3. Level 3:
Not applicable.
2.4. Level 4:
A valid assessment and corrective plan for the near-term planning horizon is
not available.
E. Regional Differences
1.
None identified.
Version History
Version
Date
Action
Change Tracking
0
April 1, 2005
Effective Date
New
0
April 1, 2005
Add parenthesis to item “e” on page 8.
Errata
0a
October 23, 2008
Added Appendix 1 – Interpretation of TPL002-0 Requirements R1.3.2 and R1.3.12 and
TPL-003-0 Requirements R1.3.2 and R1.3.12
for Ameren and MISO
Revised
0a
April 23, 2010
FERC approval of interpretation of TPL-0030 R1.3.12
Interpretation
Adopted by NERC Board of Trustees: July 30, 2008
Effective Date: April 23, 2010
* per BCUC Order G-162-11
Page 3 of 8
ATTACHMENT C
to Order G-162-11
Page 132 of 143
Standard TPL-003-0a — System Performance Following Loss of Two or More BES Elements
Table I. Transmission System Standards – Normal and Emergency Conditions
Category
Contingencies
Initiating Event(s) and Contingency
Element(s)
A
No Contingencies
B
Event resulting in
the loss of a single
element.
System Limits or Impacts
System Stable
and both
Loss of Demand
Thermal and
or
Voltage
Cascading c
Outages
Curtailed Firm
Limits within
Transfers
Applicable
Rating a
All Facilities in Service
Yes
No
No
Single Line Ground (SLG) or 3-Phase (3Ø) Fault,
with Normal Clearing:
1. Generator
2. Transmission Circuit
3. Transformer
Loss of an Element without a Fault.
Yes
Yes
Yes
Yes
No b
No b
No b
No b
No
No
No
No
Yes
Nob
No
Yes
Planned/
Controlledc
Planned/
Controlledc
No
Planned/
Controlledc
No
e
Single Pole Block, Normal Clearing :
4. Single Pole (dc) Line
e
C
Event(s) resulting in
the loss of two or
more (multiple)
elements.
SLG Fault, with Normal Clearing :
1. Bus Section
2. Breaker (failure or internal Fault)
Yes
No
e
SLG or 3Ø Fault, with Normal Clearing , Manual
System Adjustments, followed by another SLG or
e
3Ø Fault, with Normal Clearing :
3. Category B (B1, B2, B3, or B4)
contingency, manual system adjustments,
followed by another Category B (B1, B2,
B3, or B4) contingency
Yes
e
Bipolar Block, with Normal Clearing :
4. Bipolar (dc) Line Fault (non 3Ø), with
e
Normal Clearing :
5. Any two circuits of a multiple circuit
towerlinef
Yes
Planned/
Controlledc
No
Yes
Planned/
Controlledc
No
Yes
Planned/
Controlledc
No
7. Transformer
Yes
Planned/
Controlledc
No
8. Transmission Circuit
Yes
Planned/
Controlledc
No
9. Bus Section
Yes
Planned/
Controlledc
No
e
SLG Fault, with Delayed Clearing (stuck breaker
or protection system failure):
6. Generator
Adopted by NERC Board of Trustees: July 30, 2008
Effective Date: April 23, 2010
* per BCUC Order G-162-11
Page 4 of 8
ATTACHMENT C
to Order G-162-11
Page 133 of 143
Standard TPL-003-0a — System Performance Following Loss of Two or More BES
Elements
D
d
Extreme event resulting in
two or more (multiple)
elements removed or
Cascading out of service
e
3Ø Fault, with Delayed Clearing (stuck breaker or protection system
failure):
1. Generator
3. Transformer
2. Transmission Circuit
4. Bus Section
Evaluate for risks and
consequences.
ƒ
ƒ
e
3Ø Fault, with Normal Clearing :
5. Breaker (failure or internal Fault)
6. Loss of towerline with three or more circuits
ƒ
May involve substantial loss of
customer Demand and
generation in a widespread
area or areas.
Portions or all of the
interconnected systems may
or may not achieve a new,
stable operating point.
Evaluation of these events may
require joint studies with
neighboring systems.
7. All transmission lines on a common right-of way
8. Loss of a substation (one voltage level plus transformers)
9. Loss of a switching station (one voltage level plus transformers)
10. Loss of all generating units at a station
11. Loss of a large Load or major Load center
12. Failure of a fully redundant Special Protection System (or
remedial action scheme) to operate when required
13. Operation, partial operation, or misoperation of a fully redundant
Special Protection System (or Remedial Action Scheme) in
response to an event or abnormal system condition for which it
was not intended to operate
14. Impact of severe power swings or oscillations from Disturbances
in another Regional Reliability Organization.
a) Applicable rating refers to the applicable Normal and Emergency facility thermal Rating or system voltage limit as
determined and consistently applied by the system or facility owner. Applicable Ratings may include Emergency Ratings
applicable for short durations as required to permit operating steps necessary to maintain system control. All Ratings
must be established consistent with applicable NERC Reliability Standards addressing Facility Ratings.
b) Planned or controlled interruption of electric supply to radial customers or some local Network customers, connected to or
supplied by the Faulted element or by the affected area, may occur in certain areas without impacting the overall
reliability of the interconnected transmission systems. To prepare for the next contingency, system adjustments are
permitted, including curtailments of contracted Firm (non-recallable reserved) electric power Transfers.
c) Depending on system design and expected system impacts, the controlled interruption of electric supply to customers
(load shedding), the planned removal from service of certain generators, and/or the curtailment of contracted Firm (nonrecallable reserved) electric power transfers may be necessary to maintain the overall reliability of the interconnected
transmission systems.
d) A number of extreme contingencies that are listed under Category D and judged to be critical by the transmission
planning entity(ies) will be selected for evaluation. It is not expected that all possible facility outages under each listed
contingency of Category D will be evaluated.
e) Normal clearing is when the protection system operates as designed and the Fault is cleared in the time normally expected
with proper functioning of the installed protection systems. Delayed clearing of a Fault is due to failure of any protection
system component such as a relay, circuit breaker, or current transformer, and not because of an intentional design delay.
f) System assessments may exclude these events where multiple circuit towers are used over short distances (e.g., station
entrance, river crossings) in accordance with Regional exemption criteria.
Adopted by NERC Board of Trustees: July 30, 2008
Effective Date: April 23, 2010
* per BCUC Order G-162-11
Page 5 of 8
ATTACHMENT C
to Order G-162-11
Page 134 of 143
Standard TPL-003-0a — System Performance Following Loss of Two or More BES
Elements
Appendix 1
Interpretation of TPL-002-0 Requirements R1.3.2 and R1.3.12 and TPL-003-0
Requirements R1.3.2 and R1.3.12 for Ameren and MISO
NERC received two requests for interpretation of identical requirements (Requirements R1.3.2 and
R1.3.12) in TPL-002-0 and TPL-003-0 from the Midwest ISO and Ameren. These requirements state:
TPL-002-0:
[To be valid, the Planning Authority and Transmission Planner assessments shall:]
R1.3
Be supported by a current or past study and/or system simulation testing that addresses each
of the following categories, showing system performance following Category B of Table 1
(single contingencies). The specific elements selected (from each of the following categories)
for inclusion in these studies and simulations shall be acceptable to the associated Regional
Reliability Organization(s).
R1.3.2
Cover critical system conditions and study years as deemed appropriate by the
responsible entity.
R1.3.12 Include the planned (including maintenance) outage of any bulk electric equipment
(including protection systems or their components) at those demand levels for which
planned (including maintenance) outages are performed.
TPL-003-0:
[To be valid, the Planning Authority and Transmission Planner assessments shall:]
R1.3
Be supported by a current or past study and/or system simulation testing that addresses each
of the following categories, showing system performance following Category C of Table 1
(multiple contingencies). The specific elements selected (from each of the following
categories) for inclusion in these studies and simulations shall be acceptable to the associated
Regional Reliability Organization(s).
R1.3.2
Cover critical system conditions and study years as deemed appropriate by the
responsible entity.
R1.3.12 Include the planned (including maintenance) outage of any bulk electric equipment
(including protection systems or their components) at those demand levels for which
planned (including maintenance) outages are performed.
Requirement R1.3.2
Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.2
Received from Ameren on July 25, 2007:
Ameren specifically requests clarification on the phrase, ‘critical system conditions’ in R1.3.2. Ameren
asks if compliance with R1.3.2 requires multiple contingent generating unit Outages as part of possible
generation dispatch scenarios describing critical system conditions for which the system shall be planned
and modeled in accordance with the contingency definitions included in Table 1.
Adopted by NERC Board of Trustees: July 30, 2008
Effective Date: April 23, 2010
* per BCUC Order G-162-11
Page 6 of 8
ATTACHMENT C
to Order G-162-11
Page 135 of 143
Standard TPL-003-0a — System Performance Following Loss of Two or More BES
Elements
Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.2
Received from MISO on August 9, 2007:
MISO asks if the TPL standards require that any specific dispatch be applied, other than one that is
representative of supply of firm demand and transmission service commitments, in the modeling of system
contingencies specified in Table 1 in the TPL standards.
MISO then asks if a variety of possible dispatch patterns should be included in planning analyses
including a probabilistically based dispatch that is representative of generation deficiency scenarios,
would it be an appropriate application of the TPL standard to apply the transmission contingency
conditions in Category B of Table 1 to these possible dispatch pattern.
The following interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.2 was developed by
the NERC Planning Committee on March 13, 2008:
The selection of a credible generation dispatch for the modeling of critical system conditions is within the
discretion of the Planning Authority. The Planning Authority was renamed “Planning Coordinator” (PC)
in the Functional Model dated February 13, 2007. (TPL -002 and -003 use the former “Planning
Authority” name, and the Functional Model terminology was a change in name only and did not affect
responsibilities.)
−
Under the Functional Model, the Planning Coordinator “Provides and informs Resource Planners,
Transmission Planners, and adjacent Planning Coordinators of the methodologies and tools for the
simulation of the transmission system” while the Transmission Planner “Receives from the Planning
Coordinator methodologies and tools for the analysis and development of transmission expansion
plans.” A PC’s selection of “critical system conditions” and its associated generation dispatch falls
within the purview of “methodology.”
Furthermore, consistent with this interpretation, a Planning Coordinator would formulate critical system
conditions that may involve a range of critical generator unit outages as part of the possible generator
dispatch scenarios.
Both TPL-002-0 and TPL-003-0 have a similar measure M1:
M1.
The Planning Authority and Transmission Planner shall have a valid assessment and
corrective plans as specified in Reliability Standard TPL-002-0_R1 [or TPL-003-0_R1]
and TPL-002-0_R2 [or TPL-003-0_R2].”
The Regional Reliability Organization (RRO) is named as the Compliance Monitor in both standards.
Pursuant to Federal Energy Regulatory Commission (FERC) Order 693, FERC eliminated the RRO as the
appropriate Compliance Monitor for standards and replaced it with the Regional Entity (RE). See
paragraph 157 of Order 693. Although the referenced TPL standards still include the reference to the
RRO, to be consistent with Order 693, the RRO is replaced by the RE as the Compliance Monitor for this
interpretation. As the Compliance Monitor, the RE determines what a “valid assessment” means when
evaluating studies based upon specific sub-requirements in R1.3 selected by the Planning Coordinator and
the Transmission Planner. If a PC has Transmission Planners in more than one region, the REs must
coordinate among themselves on compliance matters.
Adopted by NERC Board of Trustees: July 30, 2008
Effective Date: April 23, 2010
* per BCUC Order G-162-11
Page 7 of 8
ATTACHMENT C
to Order G-162-11
Page 136 of 143
Standard TPL-003-0a — System Performance Following Loss of Two or More BES
Elements
Requirement R1.3.12
Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.12
Received from Ameren on July 25, 2007:
Ameren also asks how the inclusion of planned outages should be interpreted with respect to the
contingency definitions specified in Table 1 for Categories B and C. Specifically, Ameren asks if R1.3.12
requires that the system be planned to be operated during those conditions associated with planned
outages consistent with the performance requirements described in Table 1 plus any unidentified outage.
Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.12
Received from MISO on August 9, 2007:
MISO asks if the term “planned outages” means only already known/scheduled planned outages that may
continue into the planning horizon, or does it include potential planned outages not yet scheduled that
may occur at those demand levels for which planned (including maintenance) outages are performed?
If the requirement does include not yet scheduled but potential planned outages that could occur in the
planning horizon, is the following a proper interpretation of this provision?
The system is adequately planned and in accordance with the standard if, in order for a system operator
to potentially schedule such a planned outage on the future planned system, planning studies show that a
system adjustment (load shed, re-dispatch of generating units in the interconnection, or system
reconfiguration) would be required concurrent with taking such a planned outage in order to prepare for
a Category B contingency (single element forced out of service)? In other words, should the system in
effect be planned to be operated as for a Category C3 n-2 event, even though the first event is a planned
base condition?
If the requirement is intended to mean only known and scheduled planned outages that will occur or may
continue into the planning horizon, is this interpretation consistent with the original interpretation by
NERC of the standard as provided by NERC in response to industry questions in the Phase I development
of this standard1?
The following interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.12 was developed by
the NERC Planning Committee on March 13, 2008:
This provision was not previously interpreted by NERC since its approval by FERC and other regulatory
authorities. TPL-002-0 and TPL-003-0 explicitly provide that the inclusion of planned (including
maintenance) outages of any bulk electric equipment at demand levels for which the planned outages are
required. For studies that include planned outages, compliance with the contingency assessment for TPL002-0 and TPL-003-0 as outlined in Table 1 would include any necessary system adjustments which
might be required to accommodate planned outages since a planned outage is not a “contingency” as
defined in the NERC Glossary of Terms Used in Standards.
Adopted by NERC Board of Trustees: July 30, 2008
Effective Date: April 23, 2010
* per BCUC Order G-162-11
Page 8 of 8
ATTACHMENT C
to Order G-162-11
Page 137 of 143
Standard VAR-002-1.1b — Generator Operation for Maintaining Network Voltage Schedules
A. Introduction
1.
Title:
Generator Operation for Maintaining Network Voltage Schedules
2.
Number:
VAR-002-1.1b
3.
Purpose:
To ensure generators provide reactive and voltage control necessary to ensure
voltage levels, reactive flows, and reactive resources are maintained within applicable Facility
Ratings to protect equipment and the reliable operation of the Interconnection.
4.
Applicability
4.1. Generator Operator.
4.2. Generator Owner.
5.
*Effective Date:
Immediately after approval of applicable regulatory authorities.
B. Requirements
R1.
The Generator Operator shall operate each generator connected to the interconnected
transmission system in the automatic voltage control mode (automatic voltage regulator in
service and controlling voltage) unless the Generator Operator has notified the Transmission
Operator.
R2.
Unless exempted by the Transmission Operator, each Generator Operator shall maintain the
generator voltage or Reactive Power output (within applicable Facility Ratings 1 ) as directed by
the Transmission Operator.
R3.
R4.
R2.1.
When a generator’s automatic voltage regulator is out of service, the Generator
Operator shall use an alternative method to control the generator voltage and reactive
output to meet the voltage or Reactive Power schedule directed by the Transmission
Operator.
R2.2.
When directed to modify voltage, the Generator Operator shall comply or provide an
explanation of why the schedule cannot be met.
Each Generator Operator shall notify its associated Transmission Operator as soon as practical,
but within 30 minutes of any of the following:
R3.1.
A status or capability change on any generator Reactive Power resource, including the
status of each automatic voltage regulator and power system stabilizer and the
expected duration of the change in status or capability.
R3.2.
A status or capability change on any other Reactive Power resources under the
Generator Operator’s control and the expected duration of the change in status or
capability.
The Generator Owner shall provide the following to its associated Transmission Operator and
Transmission Planner within 30 calendar days of a request.
R4.1.
For generator step-up transformers and auxiliary transformers with primary voltages
equal to or greater than the generator terminal voltage:
R4.1.1. Tap settings.
R4.1.2. Available fixed tap ranges.
1
When a Generator is operating in manual control, reactive power capability may change based on stability
considerations and this will lead to a change in the associated Facility Ratings.
Board of Trustees Adoption: February 10, 2009
* per BCUC Order G-162-11
Page 1 of 7
ATTACHMENT C
to Order G-162-11
Page 138 of 143
Standard VAR-002-1.1b — Generator Operation for Maintaining Network Voltage Schedules
R4.1.3. Impedance data.
R4.1.4. The +/- voltage range with step-change in % for load-tap changing
transformers.
R5.
After consultation with the Transmission Operator regarding necessary step-up transformer tap
changes, the Generator Owner shall ensure that transformer tap positions are changed
according to the specifications provided by the Transmission Operator, unless such action
would violate safety, an equipment rating, a regulatory requirement, or a statutory requirement.
R5.1.
If the Generator Operator can’t comply with the Transmission Operator’s
specifications, the Generator Operator shall notify the Transmission Operator and
shall provide the technical justification.
C. Measures
M1. The Generator Operator shall have evidence to show that it notified its associated Transmission
Operator any time it failed to operate a generator in the automatic voltage control mode as
specified in Requirement 1.
M2. The Generator Operator shall have evidence to show that it controlled its generator voltage and
reactive output to meet the voltage or Reactive Power schedule provided by its associated
Transmission Operator as specified in Requirement 2.
M3. The Generator Operator shall have evidence to show that it responded to the Transmission
Operator’s directives as identified in Requirement 2.1 and Requirement 2.2.
M4. The Generator Operator shall have evidence it notified its associated Transmission Operator
within 30 minutes of any of the changes identified in Requirement 3.
M5. The Generator Owner shall have evidence it provided its associated Transmission Operator and
Transmission Planner with information on its step-up transformers and auxiliary transformers
as required in Requirements 4.1.1 through 4.1.4
M6. The Generator Owner shall have evidence that its step-up transformer taps were modified per
the Transmission Operator’s documentation as identified in Requirement 5.
M7. The Generator Operator shall have evidence that it notified its associated Transmission
Operator when it couldn’t comply with the Transmission Operator’s step-up transformer tap
specifications as identified in Requirement 5.1.
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
Compliance Monitor: the British Columbia Utilities Commission
Compliance Monitor’s Administrator: the Western Electricity Coordinating Council
.
1.2. Compliance Monitoring Period and Reset Time Frame
One calendar year.
1.3. Data Retention
The Generator Operator shall maintain evidence needed for Measure 1 through Measure
5 and Measure 7 for the current and previous calendar years.
Board of Trustees Adoption: February 10, 2009
* per BCUC Order G-162-11
Page 2 of 7
ATTACHMENT C
to Order G-162-11
Page 139 of 143
Standard VAR-002-1.1b — Generator Operation for Maintaining Network Voltage Schedules
The Generator Owner shall keep its latest version of documentation on its step-up and
auxiliary transformers. (Measure 6)
The Compliance Monitor shall retain any audit data for three years.
1.4. Additional Compliance Information
The Generator Owner and Generator Operator shall each demonstrate compliance
through self-certification or audit (periodic, as part of targeted monitoring or initiated by
complaint or event), as determined by the Compliance Monitor.
2.
Levels of Non-Compliance for Generator Operator
2.1. Level 1: There shall be a Level 1 non-compliance if any of the following conditions exist:
2.1.1
One incident of failing to notify the Transmission Operator as identified in, R3.1,
R3.2 or R5.1.
2.1.2
One incident of failing to maintain a voltage or reactive power schedule (R2).
2.2. Level 2: There shall be a Level 2 non-compliance if any of the following conditions exist:
2.2.1
More than one but less than five incidents of failing to notify the Transmission as
identified in R1, R3.1, R3.2 or R5.1.
2.2.2
More than one but less than five incidents of failing to maintain a voltage or
reactive power schedule (R2).
2.3. Level 3: There shall be a Level 3 non-compliance if any of the following conditions exist:
2.3.1
More than five but less than ten incidents of failing to notify the Transmission
Operator as identified in R1, R3.1, R3.2 or R5.1.
2.3.2
More than five but less than ten incidents of failing to maintain a voltage or
reactive power schedule (R2).
2.4. Level 4: There shall be a Level 4 non-compliance if any of the following conditions exist:
3.
2.4.1
Failed to comply with the Transmission Operator’s directives as identified in R2.
2.4.2
Ten or more incidents of failing to notify the Transmission Operator as identified
in R1, R3.1, R3.2 or R5.1.
2.4.3
Ten or more incidents of failing to maintain a voltage or reactive power schedule (R2).
Levels of Non-Compliance for Generator Owner:
3.1.1
Level One: Not applicable.
3.1.2
Level Two: Documentation of generator step-up transformers and auxiliary
transformers with primary voltages equal to or greater than the generator terminal
voltage was missing two of the data types identified in R4.1.1 through R4.1.4.
3.1.3
Level Three: No documentation of generator step-up transformers and auxiliary
transformers with primary voltages equal to or greater than the generator terminal
voltage
3.1.4
Level Four: Did not ensure generating unit step-up transformer settings were
changed in compliance with the specifications provided by the Transmission
Operator as identified in R5.
Board of Trustees Adoption: February 10, 2009
* per BCUC Order G-162-11
Page 3 of 7
ATTACHMENT C
to Order G-162-11
Page 140 of 143
Standard VAR-002-1.1b — Generator Operation for Maintaining Network Voltage Schedules
E. Regional Differences
None identified.
F. Associated Documents
1.
Appendix 1 ⎯ Interpretation of Requirements R1 and R2 (August 1, 2007).
Version History
Version
Date
Action
Change Tracking
1
May 15, 2006
Added “(R2)” to the end of levels on noncompliance 2.1.2, 2.2.2, 2.3.2, and 2.4.3.
July 5, 2006
1a
December 19, 2007
Added Appendix 1 – Interpretation of R1 and
R2 approved by BOT on August 1, 2007
Revised
1a
January 16, 2007
In Section A.2., Added “a” to end of standard
number.
Section F: added “1.”; and added date.
Errata
1.1a
October 29, 2008
BOT adopted errata changes; updated version
number to “1.1a”
Errata
1.1b
March 3, 2009
Added Appendix 2 – Interpretation of VAR002-1.1a approved by BOT on February 10,
2009
Revised
Board of Trustees Adoption: February 10, 2009
* per BCUC Order G-162-11
Page 4 of 7
ATTACHMENT C
to Order G-162-11
Page 141 of 143
Standard VAR-002-1.1b — Generator Operation for Maintaining Network Voltage Schedules
Appendix 1
Interpretation of Requirements R1 and R2
Request:
Requirement R1 of Standard VAR-002-1 states that Generation Operators shall operate each generator
connected to the interconnected transmission system in the automatic voltage control mode (automatic
voltage regulator in service and controlling voltage) unless the Generator Operator has notified the
Transmission Operator.
Requirement R2 goes on to state that each Generation Operator shall maintain the generator voltage or
Reactive Power output as directed by the Transmission Operator.
The two underlined phrases are the reasons for this interpretation request.
Most generation excitation controls include a device known as the Automatic Voltage Regulator, or AVR.
This is the device which is referred to by the R1 requirement above. Most AVR’s have the option of
being set in various operating modes, such as constant voltage, constant power factor, and constant Mvar.
In the course of helping members of the WECC insure that they are in full compliance with NERC
Reliability Standards, I have discovered both Transmission Operators and Generation Operators who have
interpreted this standard to mean that AVR operation in the constant power factor or constant Mvar
modes complies with the R1 and R2 requirements cited above. Their rational is as follows:
ƒ
ƒ
ƒ
The AVR is clearly in service because it is operating in one of its operating modes
The AVR is clearly controlling voltage because to maintain constant PF or constant Mvar, it
controls the generator terminal voltage
R2 clearly gives the Transmission Operator the option of directing the Generation Operator to
maintain a constant reactive power output rather than a constant voltage.
Other parties have interpreted this standard to require operation in the constant voltage mode only. Their
rational stems from the belief that the purpose of the VAR-002-1 standard is to insure the automatic
delivery of additional reactive to the system whenever a voltage decline begins to occur.
The material impact of misinterpretation of these standards is twofold.
ƒ
ƒ
First, misinterpretation may result in reduced reactive response during system disturbances,
which in turn may contribute to voltage collapse.
Second, misinterpretation may result in substantial financial penalties imposed on generation
operators and transmission operators who believe that they are in full compliance with the
standard.
In accordance with the NERC Reliability Standards Development Procedure, I am requesting that a
formal interpretation of the VAR-002-1 standard be provided. Two specific questions need to be
answered.
ƒ
ƒ
First, does AVR operation in the constant PF or constant Mvar modes comply with R1?
Second, does R2 give the Transmission Operator the option of directing the Generation Owner to
operate the AVR in the constant Pf or constant Mvar modes rather than the constant voltage
mode?
Board of Trustees Adoption: February 10, 2009
* per BCUC Order G-162-11
Page 5 of 7
ATTACHMENT C
to Order G-162-11
Page 142 of 143
Standard VAR-002-1.1b — Generator Operation for Maintaining Network Voltage Schedules
Interpretation:
1. First, does AVR operation in the constant PF or constant Mvar modes comply with R1?
Interpretation: No, only operation in constant voltage mode meets this requirement. This
answer is predicated on the assumption that the generator has the physical equipment that
will allow such operation and that the Transmission Operator has not directed the generator
to run in a mode other than constant voltage.
2. Second, does R2 give the Transmission Operator the option of directing the Generation
Owner (sic) to operate the AVR in the constant Pf or constant Mvar modes rather than the
constant voltage mode?
Interpretation: Yes, if the Transmission Operator specifically directs a Generator Operator to
operate the AVR in a mode other than constant voltage mode, then that directed mode of AVR
operation is allowed.
Board of Trustees Adoption: February 10, 2009
* per BCUC Order G-162-11
Page 6 of 7
ATTACHMENT C
to Order G-162-11
Page 143 of 143
Standard VAR-002-1.1b — Generator Operation for Maintaining Network Voltage Schedules
Appendix 2
Interpretation of VAR-002-1a
Request:
VAR-002 — Generator Operation for Maintaining Network Voltage Schedules, addresses the generator’s
provision of voltage and VAR control. Confusion exists in the industry and regions as to which
requirements in this standard apply to Generator Operators that operate generators that do not have
automatic voltage regulation capability.
The Standard’s requirements do not identify the subset of generator operators that need to comply –
forcing some generator operators that do not have any automatic voltage regulation capability to
demonstrate how they complied with the requirements, even when they aren’t physically able to comply
with the requirements. Generator owners want clarification to verify that they are not expected to acquire
AVR devices to comply with the requirements in this standard.
Many generators do not have automatic voltage regulators and do not receive voltage schedules. These
entities are at a loss as to how to comply with these requirements and are expending resources attempting
to demonstrate compliance with these requirements. A clarification will avoid challenges and potential
litigation stemming from sanctions and penalties applied to entities that are being audited for compliance
with this standard, but who do not fall within the scope or intent of the standard itself.
Please identify which requirements apply to generators that do not operate generators equipped with
AVRs.
Response: All the requirements and associated subrequirements in VAR-002-1a apply to Generator
Owners and Generator Operators that own or operate generators whether equipped with an automatic
voltage regulator or not. The standard is predicated on the assumption that the generator has the physical
equipment (automatic voltage regulator) that is capable of automatic operation. A generator that is not
equipped with an automatic voltage regulator results in a functionally equivalent condition to a generator
equipped with an automatic voltage regulator that is out of service due to maintenance or failure.
There are no requirements in the standard that require a generator to have an automatic voltage regulator,
nor are there any requirements for a Generator Owner to modify its generator to add an automatic voltage
regulator. Unless exempted by the Transmission Operator, each Generator Operator shall maintain the
generator voltage or Reactive Power output (within applicable Facility Ratings) as directed by the
Transmission Operator.
Board of Trustees Adoption: February 10, 2009
* per BCUC Order G-162-11
Page 7 of 7
ATTACHMENT D
to Order G-162-11
Page 1 of 55
Glossary of Terms Used in NERC Reliability Standards
Updated August 4, 2011
Introduction:
This Glossary lists each term that was defined for use in one or more of
NERC’s continent-wide or Regional Reliability Standards and adopted by the
NERC Board of Trustees from February 8, 2005 through August 4, 2011.
This reference is divided into two sections, and each section is organized in
alphabetical order. The first section identifies all terms that have been
adopted by the NERC Board of Trustees for use in continent-wide standards;
the second section identifies all terms that have been adopted by the NERC
Board of Trustees for use in regional standards. (WECC, NPCC and
ReliabilityFirst are the only Regions that have definitions approved by the
NERC Board of Trustees. If other Regions develop definitions for approved
Regional Standards using a NERC-approved standards development process,
those definitions will be added to the Regional Definitions section of this
glossary.)
Most of the terms identified in this glossary were adopted as part of the
development of NERC’s initial set of reliability standards, called the “Version
0” standards. Subsequent to the development of Version 0 standards, new
definitions have been developed and approved following NERC’s Reliability
Standards Development Process, and added to this glossary following board
adoption, with the “FERC approved” date added following a final Order
approving the definition.
Immediately under each term is a link to the archive for the development of
that term.
Definitions that have been adopted by the NERC Board of Trustees but have
not been approved by FERC, or FERC has not approved but has directed be
modified, are shaded in blue. Definitions that have been remanded or
retired are shaded in orange.
Any comments regarding this glossary should be reported to the following:
[email protected] with “Glossary Comment” in the subject line.
August 4, 2011
Page 1 of 55
ATTACHMENT D
to Order G-162-11
Page 2 of 55
Glossary of Terms Used in NERC Reliability Standards
Continent-wide Definitions:
A ............................................................................................... 4
B ............................................................................................... 8
C............................................................................................. 10
D ............................................................................................ 14
E ............................................................................................. 17
F ............................................................................................. 19
G ............................................................................................ 22
H ............................................................................................ 22
I ............................................................................................. 23
J ............................................................................................. 25
L ............................................................................................. 26
M ............................................................................................ 26
N ............................................................................................ 27
O ............................................................................................ 30
P ............................................................................................. 33
R............................................................................................. 35
S ............................................................................................. 40
T ............................................................................................. 43
V ............................................................................................. 46
W ............................................................................................ 46
August 4, 2011
Page 2 of 55
ATTACHMENT D
to Order G-162-11
Page 3 of 55
Glossary of Terms Used in NERC Reliability Standards
Regional Definitions
ReliabilityFirst Regional Definitions .............................................. 48
NPCC Regional Definitions .......................................................... 49
WECC Regional Definitions ......................................................... 50
August 4, 2011
Page 3 of 55
ATTACHMENT D
to Order G-162-11
Page 4 of 55
Glossary of Terms Used in NERC Reliability Standards
Continent-wide
Term
Acronym
Adequacy
BOT
Approval
Date
FERC
Approval
Date
2/8/2005
3/16/2007
The ability of the electric system to supply the aggregate
electrical demand and energy requirements of the end-use
customers at all times, taking into account scheduled and
reasonably expected unscheduled outages of system
elements.
2/8/2005
3/16/2007
A Balancing Authority Area that is interconnected another
Balancing Authority Area either directly or via a multi-party
agreement or transmission tariff.
2/7/2006
3/16/2007
The impact of an event that results in frequency-related
instability; unplanned tripping of load or generation; or
uncontrolled separation or cascading outages that affects a
widespread area of the Interconnection.
[Archive]
Adjacent Balancing
Authority
[Archive]
Adverse Reliability
Impact
[Archive]
Adverse Reliability
Impact
Definition
8/4/2011
The impact of an event that results in Bulk Electric System
instability or Cascading.
[Archive]
After the Fact
ATF
10/29/2008
12/17/2009
A time classification assigned to an RFI when the submittal
time is greater than one hour after the start time of the RFI.
2/8/2005
3/16/2007
A contract or arrangement, either written or verbal and
sometimes enforceable by law.
2/7/2006
3/16/2007
A multiplier applied to specify distances, which adjusts the
distances to account for the change in relative air density
(RAD) due to altitude from the RAD used to determine the
specified distance. Altitude correction factors apply to both
minimum worker approach distances and to minimum
vegetation clearance distances.
[Archive]
Agreement
[Archive]
Altitude Correction
Factor
[Archive]
August 4, 2011
Page 4 of 55
ATTACHMENT D
to Order G-162-11
Page 5 of 55
Glossary of Terms Used in NERC Reliability Standards
Continent-wide
Term
Acronym
Ancillary Service
BOT
Approval
Date
FERC
Approval
Date
2/8/2005
3/16/2007
Those services that are necessary to support the
transmission of capacity and energy from resources to loads
while maintaining reliable operation of the Transmission
Service Provider's transmission system in accordance with
good utility practice. (From FERC order 888-A.)
2/8/2005
3/16/2007
An analog filter installed at a metering point to remove the
high frequency components of the signal over the AGC
sample period.
2/8/2005
3/16/2007
The instantaneous difference between a Balancing
Authority’s net actual and scheduled interchange, taking
into account the effects of Frequency Bias and correction for
meter error.
08/22/2008
11/24/2009
The Area Interchange methodology is characterized by
determination of incremental transfer capability via
simulation, from which Total Transfer Capability (TTC) can
be mathematically derived. Capacity Benefit Margin,
Transmission Reliability Margin, and Existing Transmission
Commitments are subtracted from the TTC, and Postbacks
and counterflows are added, to derive Available Transfer
Capability. Under the Area Interchange Methodology, TTC
results are generally reported on an area to area basis.
5/2/2006
3/16/2007
The state where the Interchange Authority has received the
Interchange information (initial or revised).
2/8/2005
3/16/2007
Equipment that automatically adjusts generation in a
Balancing Authority Area from a central location to maintain
the Balancing Authority’s interchange schedule plus
Frequency Bias. AGC may also accommodate automatic
inadvertent payback and time error correction.
[Archive]
Anti-Aliasing Filter
[Archive]
Area Control Error
ACE
[Archive]
Area Interchange
Methodology
[Archive]
Arranged Interchange
[Archive]
Automatic Generation
Control
[Archive]
August 4, 2011
AGC
Definition
Page 5 of 55
ATTACHMENT D
to Order G-162-11
Page 6 of 55
Glossary of Terms Used in NERC Reliability Standards
Continent-wide
Term
Available Flowgate
Capability
BOT
Approval
Date
FERC
Approval
Date
AFC
08/22/2008
11/24/2009
A measure of the flow capability remaining on a Flowgate
for further commercial activity over and above already
committed uses. It is defined as TFC less Existing
Transmission Commitments (ETC), less a Capacity Benefit
Margin, less a Transmission Reliability Margin, plus
Postbacks, and plus counterflows.
ATC
2/8/2005
3/16/2007
A measure of the transfer capability remaining in the
physical transmission network for further commercial
activity over and above already committed uses. It is
defined as Total Transfer Capability less existing
transmission commitments (including retail customer
service), less a Capacity Benefit Margin, less a Transmission
Reliability Margin.
ATC
08/22/2008
11/24/2009
A measure of the transfer capability remaining in the
physical transmission network for further commercial
activity over and above already committed uses. It is
defined as Total Transfer Capability less Existing
Transmission Commitments (including retail customer
service), less a Capacity Benefit Margin, less a Transmission
Reliability Margin, plus Postbacks, plus counterflows.
Acronym
[Archive]
Available Transfer
Capability
[Archive]
Available Transfer
Capability
[Archive]
August 4, 2011
Definition
Page 6 of 55
ATTACHMENT D
to Order G-162-11
Page 7 of 55
Glossary of Terms Used in NERC Reliability Standards
Continent-wide
Term
Available Transfer
Capability
Implementation
Document
Acronym
ATCID
BOT
Approval
Date
FERC
Approval
Date
08/22/2008
11/24/2009
A document that describes the implementation of a
methodology for calculating ATC or AFC, and provides
information related to a Transmission Service Provider’s
calculation of ATC or AFC.
08/22/2008
Not
approved;
Any combination of Point of Receipt and Point of Delivery for
which ATC is calculated; and any Posted Path 1.
Definition
[Archive]
ATC Path
[Archive]
Modification
directed
11/24/09
1
See 18 CFR 37.6(b)(1)
August 4, 2011
Page 7 of 55
ATTACHMENT D
to Order G-162-11
Page 8 of 55
Glossary of Terms Used in NERC Reliability Standards
Continent-wide
Term
Balancing Authority
Acronym
BA
BOT
Approved
Date
FERC
Approved
Date
2/8/2005
3/16/2007
The responsible entity that integrates resource plans ahead
of time, maintains load-interchange-generation balance
within a Balancing Authority Area, and supports
Interconnection frequency in real time.
2/8/2005
3/16/2007
The collection of generation, transmission, and loads within
the metered boundaries of the Balancing Authority. The
Balancing Authority maintains load-resource balance within
this area.
2/8/2005
3/16/2007
The minimum amount of electric power delivered or
required over a given period at a constant rate.
2/8/2005
3/16/2007
A documented procedure for a generating unit or station to
go from a shutdown condition to an operating condition
delivering electric power without assistance from the electric
system. This procedure is only a portion of an overall
system restoration plan.
[Archive]
Balancing Authority
Area
[Archive]
Base Load
[Archive]
Blackstart Capability
Plan
[Archive]
Definition
Approved
Retirement
when EOP005-2
becomes
effective
8/5/2009
Blackstart Resource
[Archive]
August 4, 2011
8/5/2009
A generating unit(s) and its associated set of equipment
which has the ability to be started without support from the
System or is designed to remain energized without
connection to the remainder of the System, with the ability
to energize a bus, meeting the Transmission Operator’s
restoration plan needs for real and reactive power
capability, frequency and voltage control, and that has been
included in the Transmission Operator’s restoration plan
Page 8 of 55
ATTACHMENT D
to Order G-162-11
Page 9 of 55
Glossary of Terms Used in NERC Reliability Standards
Continent-wide
Term
Block Dispatch
Acronym
BOT
Approved
Date
FERC
Approved
Date
08/22/2008
11/24/2009
A set of dispatch rules such that given a specific amount of
load to serve, an approximate generation dispatch can be
determined. To accomplish this, the capacity of a given
generator is segmented into loadable “blocks,” each of
which is grouped and ordered relative to other blocks
(based on characteristics including, but not limited to,
efficiency, run of river or fuel supply considerations, and/or
“must-run” status).
2/8/2005
3/16/2007
As defined by the Regional Reliability Organization, the
electrical generation resources, transmission lines,
interconnections with neighboring systems, and associated
equipment, generally operated at voltages of 100 kV or
higher. Radial transmission facilities serving only load with
one transmission source are generally not included in this
definition.
2/8/2005
3/16/2007
Operation of the Bulk Electric System that violates or is
expected to violate a System Operating Limit or
Interconnection Reliability Operating Limit in the
Interconnection, or that violates any other NERC, Regional
Reliability Organization, or local operating reliability
standards or criteria.
8/22/2008
Not
approved;
Those business rules contained in the Transmission Service
Provider’s applicable tariff, rules, or procedures; associated
Regional Reliability Organization or regional entity business
practices; or NAESB Business Practices.
[Archive]
Bulk Electric System
[Archive]
Burden
[Archive]
Business Practices
[Archive]
Bus-tie Breaker
[Archive]
August 4, 2011
Modification
directed
11/24/09
8/4/2011
Definition
A circuit breaker that is positioned to connect two individual
substation bus configurations.
Page 9 of 55
ATTACHMENT D
to Order G-162-11
Page 10 of 55
Glossary of Terms Used in NERC Reliability Standards
Continent-wide
Term
Capacity Benefit
Margin
Acronym
BOT
Approved
Date
FERC
Approved
Date
CBM
2/8/2005
3/16/2007
The amount of firm transmission transfer capability
preserved by the transmission provider for Load-Serving
Entities (LSEs), whose loads are located on that
Transmission Service Provider’s system, to enable access by
the LSEs to generation from interconnected systems to
meet generation reliability requirements. Preservation of
CBM for an LSE allows that entity to reduce its installed
generating capacity below that which may otherwise have
been necessary without interconnections to meet its
generation reliability requirements. The transmission
transfer capability preserved as CBM is intended to be used
by the LSE only in times of emergency generation
deficiencies.
CBMID
11/13/2008
11/24/2009
A document that describes the implementation of a Capacity
Benefit Margin methodology.
2/8/2005
3/16/2007
A capacity emergency exists when a Balancing Authority
Area’s operating capacity, plus firm purchases from other
systems, to the extent available or limited by transfer
capability, is inadequate to meet its demand plus its
regulating requirements.
2/8/2005
3/16/2007
The uncontrolled successive loss of system elements
triggered by an incident at any location. Cascading results
in widespread electric service interruption that cannot be
restrained from sequentially spreading beyond an area
predetermined by studies.
[Archive]
Capacity Benefit
Margin
Implementation
Document
Definition
[Archive]
Capacity Emergency
[Archive]
Cascading
[Archive]
August 4, 2011
Page 10 of 55
ATTACHMENT D
to Order G-162-11
Page 11 of 55
Glossary of Terms Used in NERC Reliability Standards
Continent-wide
Term
Acronym
BOT
Approved
Date
FERC
Approved
Date
Definition
Cascading Outages
11/1/2006
[Archive]
Withdrawn
2/12/2008
FERC
Remanded
12/27/2007
The uncontrolled successive loss of Bulk Electric System
Facilities triggered by an incident (or condition) at any
location resulting in the interruption of electric service that
cannot be restrained from spreading beyond a predetermined area.
Clock Hour
2/8/2005
3/16/2007
The 60-minute period ending at :00. All surveys,
measurements, and reports are based on Clock Hour
periods unless specifically noted.
2/8/2005
3/16/2007
Production of electricity from steam, heat, or other forms of
energy produced as a by-product of another process.
2/8/2005
3/16/2007
The entity that monitors, reviews, and ensures compliance
of responsible entities with reliability standards.
5/2/2006
3/16/2007
The state where the Interchange Authority has verified the
Arranged Interchange.
2/8/2005
3/16/2007
A report that the Interchange Distribution Calculator issues
when a Reliability Coordinator initiates the Transmission
Loading Relief procedure. This report identifies the
transactions and native and network load curtailments that
must be initiated to achieve the loading relief requested by
the initiating Reliability Coordinator.
[Archive]
Cogeneration
[Archive]
Compliance Monitor
[Archive]
Confirmed
Interchange
[Archive]
Congestion
Management Report
[Archive]
Consequential Load
Loss
8/4/2011
All Load that is no longer served by the Transmission
system as a result of Transmission Facilities being removed
from service by a Protection System operation designed to
isolate the fault.
[Archive]
Constrained Facility
[Archive]
August 4, 2011
2/8/2005
3/16/2007
A transmission facility (line, transformer, breaker, etc.) that
is approaching, is at, or is beyond its System Operating
Limit or Interconnection Reliability Operating Limit.
Page 11 of 55
ATTACHMENT D
to Order G-162-11
Page 12 of 55
Glossary of Terms Used in NERC Reliability Standards
Continent-wide
Term
Acronym
Contingency
BOT
Approved
Date
FERC
Approved
Date
2/8/2005
3/16/2007
The unexpected failure or outage of a system component,
such as a generator, transmission line, circuit breaker,
switch or other electrical element.
2/8/2005
3/16/2007
The provision of capacity deployed by the Balancing
Authority to meet the Disturbance Control Standard (DCS)
and other NERC and Regional Reliability Organization
contingency requirements.
2/8/2005
3/16/2007
An agreed upon electrical path for the continuous flow of
electrical power between the parties of an Interchange
Transaction.
2/8/2005
3/16/2007
The reliability standard that sets the limits of a Balancing
Authority’s Area Control Error over a specified time period.
2/7/2006
3/16/2007
A list of actions and an associated timetable for
implementation to remedy a specific problem.
5/2/2006
3/16/2007
A portion of the electric system that can be isolated and
then energized to deliver electric power from a generation
source to enable the startup of one or more other
generating units.
5/2/2006
1/18/2008
Facilities, systems, and equipment which, if destroyed,
degraded, or otherwise rendered unavailable, would affect
the reliability or operability of the Bulk Electric System.
5/2/2006
1/18/2008
Cyber Assets essential to the reliable operation of Critical
Assets.
2/8/2005
3/16/2007
A reduction in the scheduled capacity or energy delivery of
an Interchange Transaction.
[Archive]
Contingency Reserve
[Archive]
Contract Path
[Archive]
Control Performance
Standard
CPS
Definition
[Archive]
Corrective Action Plan
[Archive]
Cranking Path
[Archive]
Critical Assets
[Archive]
Critical Cyber Assets
[Archive]
Curtailment
[Archive]
August 4, 2011
Page 12 of 55
ATTACHMENT D
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Page 13 of 55
Glossary of Terms Used in NERC Reliability Standards
Continent-wide
Term
Curtailment Threshold
Acronym
BOT
Approved
Date
FERC
Approved
Date
2/8/2005
3/16/2007
The minimum Transfer Distribution Factor which, if
exceeded, will subject an Interchange Transaction to
curtailment to relieve a transmission facility constraint.
5/2/2006
1/18/2008
Programmable electronic devices and communication
networks including hardware, software, and data.
5/2/2006
1/18/2008
Any malicious act or suspicious event that:
[Archive]
Cyber Assets
[Archive]
Cyber Security
Incident
[Archive]
August 4, 2011
Definition
•
Compromises, or was an attempt to compromise, the
Electronic Security Perimeter or Physical Security
Perimeter of a Critical Cyber Asset, or,
•
Disrupts, or was an attempt to disrupt, the operation
of a Critical Cyber Asset.
Page 13 of 55
ATTACHMENT D
to Order G-162-11
Page 14 of 55
Glossary of Terms Used in NERC Reliability Standards
Continent-wide
Term
Acronym
Delayed Fault Clearing
BOT
Approved
Date
FERC
Approved
Date
11/1/2006
12/27/2007
Fault clearing consistent with correct operation of a breaker
failure protection system and its associated breakers, or of
a backup protection system with an intentional time delay.
2/8/2005
3/16/2007
1. The rate at which electric energy is delivered to or by a
system or part of a system, generally expressed in
kilowatts or megawatts, at a given instant or averaged
over any designated interval of time.
[Archive]
Demand
Definition
[Archive]
2. The rate at which energy is being used by the customer.
Demand-Side
Management
DSM
2/8/2005
3/16/2007
The term for all activities or programs undertaken by LoadServing Entity or its customers to influence the amount or
timing of electricity they use.
DCLM
2/8/2005
3/16/2007
Demand-Side Management that is under the direct control
of the system operator. DCLM may control the electric
supply to individual appliances or equipment on customer
premises. DCLM as defined here does not include
Interruptible Demand.
08/22/2008
11/24/2009
A set of dispatch rules such that given a specific amount of
load to serve, an approximate generation dispatch can be
determined. To accomplish this, each generator is ranked by
priority.
2/8/2005
3/16/2007
Substation load information configured to represent a
system for power flow or system dynamics modeling
purposes, or both.
2/8/2005
3/16/2007
The portion of an Interchange Transaction, typically
expressed in per unit that flows across a transmission
facility (Flowgate).
[Archive]
Direct Control Load
Management
[Archive]
Dispatch Order
[Archive]
Dispersed Load by
Substations
[Archive]
Distribution Factor
[Archive]
August 4, 2011
DF
Page 14 of 55
ATTACHMENT D
to Order G-162-11
Page 15 of 55
Glossary of Terms Used in NERC Reliability Standards
Continent-wide
Term
Acronym
Distribution Provider
BOT
Approved
Date
FERC
Approved
Date
2/8/2005
3/16/2007
Provides and operates the “wires” between the transmission
system and the end-use customer. For those end-use
customers who are served at transmission voltages, the
Transmission Owner also serves as the Distribution
Provider. Thus, the Distribution Provider is not defined by a
specific voltage, but rather as performing the Distribution
function at any voltage.
2/8/2005
3/16/2007
1. An unplanned event that produces an abnormal system
condition.
[Archive]
Disturbance
Definition
[Archive]
2. Any perturbation to the electric system.
3. The unexpected change in ACE that is caused by the
sudden failure of generation or interruption of load.
Disturbance Control
Standard
DCS
2/8/2005
3/16/2007
The reliability standard that sets the time limit following a
Disturbance within which a Balancing Authority must return
its Area Control Error to within a specified range.
DME
8/2/2006
3/16/2007
Devices capable of monitoring and recording system data
pertaining to a Disturbance. Such devices include the
following categories of recorders 2:
[Archive]
Disturbance
Monitoring Equipment
[Archive]
2
•
Sequence of event recorders which record equipment
response to the event
•
Fault recorders, which record actual waveform data
replicating the system primary voltages and
currents. This may include protective relays.
•
Dynamic Disturbance Recorders (DDRs), which
record incidents that portray power system behavior
during dynamic events such as low-frequency (0.1
Hz – 3 Hz) oscillations and abnormal frequency or
voltage excursions
Phasor Measurement Units and any other equipment that meets the functional requirements of DMEs may qualify as DMEs.
August 4, 2011
Page 15 of 55
ATTACHMENT D
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Page 16 of 55
Glossary of Terms Used in NERC Reliability Standards
Continent-wide
Term
Dynamic Interchange
Schedule or
Acronym
BOT
Approved
Date
FERC
Approved
Date
2/8/2005
3/16/2007
A telemetered reading or value that is updated in real time
and used as a schedule in the AGC/ACE equation and the
integrated value of which is treated as a schedule for
interchange accounting purposes. Commonly used for
scheduling jointly owned generation to or from another
Balancing Authority Area.
2/8/2005
3/16/2007
The provision of the real-time monitoring, telemetering,
computer software, hardware, communications,
engineering, energy accounting (including inadvertent
interchange), and administration required to electronically
move all or a portion of the real energy services associated
with a generator or load out of one Balancing Authority Area
into another.
Dynamic Schedule
[Archive]
Dynamic Transfer
[Archive]
August 4, 2011
Definition
Page 16 of 55
ATTACHMENT D
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Page 17 of 55
Glossary of Terms Used in NERC Reliability Standards
Continent-wide
Term
Economic Dispatch
Acronym
BOT
Approved
Date
FERC
Approved
Date
2/8/2005
3/16/2007
The allocation of demand to individual generating units on
line to effect the most economical production of electricity.
2/8/2005
3/16/2007
The generation or use of electric power by a device over a
period of time, expressed in kilowatthours (kWh),
megawatthours (MWh), or gigawatthours (GWh).
5/2/2006
1/18/2008
The logical border surrounding a network to which Critical
Cyber Assets are connected and for which access is
controlled.
2/8/2005
3/16/2007
Any electrical device with terminals that may be connected
to other electrical devices such as a generator, transformer,
circuit breaker, bus section, or transmission line. An
element may be comprised of one or more components.
2/8/2005
3/16/2007
Any abnormal system condition that requires automatic or
immediate manual action to prevent or limit the failure of
transmission facilities or generation supply that could
adversely affect the reliability of the Bulk Electric System.
2/8/2005
3/16/2007
The rating as defined by the equipment owner that specifies
the level of electrical loading or output, usually expressed in
megawatts (MW) or Mvar or other appropriate units, that a
system, facility, or element can support, produce, or
withstand for a finite period. The rating assumes acceptable
loss of equipment life or other physical or safety limitations
for the equipment involved.
10/29/2008
12/17/2009
Request for Interchange to be initiated for Emergency or
Energy Emergency conditions.
[Archive]
Electrical Energy
[Archive]
Electronic Security
Perimeter
[Archive]
Element
[Archive]
Emergency or
BES Emergency
[Archive]
Emergency Rating
[Archive]
Emergency Request
for Interchange
(Emergency RFI)
Definition
[Archive]
August 4, 2011
Page 17 of 55
ATTACHMENT D
to Order G-162-11
Page 18 of 55
Glossary of Terms Used in NERC Reliability Standards
Continent-wide
Term
Acronym
Energy Emergency
BOT
Approved
Date
FERC
Approved
Date
2/8/2005
3/16/2007
A condition when a Load-Serving Entity has exhausted all
other options and can no longer provide its customers’
expected energy requirements.
2/7/2006
3/16/2007
The maximum and minimum voltage, current, frequency,
real and reactive power flows on individual equipment under
steady state, short-circuit and transient conditions, as
permitted or assigned by the equipment owner.
08/22/2008
11/24/2009
Committed uses of a Transmission Service Provider’s
Transmission system considered when determining ATC or
AFC.
[Archive]
Equipment Rating
[Archive]
Existing Transmission
Commitments
[Archive]
August 4, 2011
ETC
Definition
Page 18 of 55
ATTACHMENT D
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Page 19 of 55
Glossary of Terms Used in NERC Reliability Standards
Continent-wide
Term
Facility
Acronym
BOT
Approved
Date
FERC
Approved
Date
2/7/2006
3/16/2007
A set of electrical equipment that operates as a single Bulk
Electric System Element (e.g., a line, a generator, a shunt
compensator, transformer, etc.)
2/8/2005
3/16/2007
The maximum or minimum voltage, current, frequency, or
real or reactive power flow through a facility that does not
violate the applicable equipment rating of any equipment
comprising the facility.
2/8/2005
3/16/2007
An event occurring on an electric system such as a short
circuit, a broken wire, or an intermittent connection.
2/7/2006
3/16/2007
The likelihood that a fire will ignite or spread in a particular
geographic area.
2/8/2005
3/16/2007
That portion of the Demand that a power supplier is
obligated to provide except when system reliability is
threatened or during emergency conditions.
2/8/2005
3/16/2007
The highest quality (priority) service offered to customers
under a filed rate schedule that anticipates no planned
interruption.
2/7/2006
3/16/2007
An electrical discharge through air around or over the
surface of insulation, between objects of different potential,
caused by placing a voltage across the air space that results
in the ionization of the air space.
2/8/2005
3/16/2007
A designated point on the transmission system through
which the Interchange Distribution Calculator calculates the
power flow from Interchange Transactions.
[Archive]
Facility Rating
[Archive]
Fault
[Archive]
Fire Risk
[Archive]
Firm Demand
[Archive]
Firm Transmission
Service
[Archive]
Flashover
[Archive]
Flowgate
[Archive]
August 4, 2011
Definition
Page 19 of 55
ATTACHMENT D
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Page 20 of 55
Glossary of Terms Used in NERC Reliability Standards
Continent-wide
Term
Flowgate
Acronym
BOT
Approved
Date
FERC
Approved
Date
08/22/2008
11/24/2009
[Archive]
Definition
1.) A portion of the Transmission system through which the
Interchange Distribution Calculator calculates the power
flow from Interchange Transactions.
2.) A mathematical construct, comprised of one or more
monitored transmission Facilities and optionally one or more
contingency Facilities, used to analyze the impact of power
flows upon the Bulk Electric System.
Flowgate Methodology
08/22/2008
11/24/2009
The Flowgate methodology is characterized by identification
of key Facilities as Flowgates. Total Flowgate Capabilities
are determined based on Facility Ratings and voltage and
stability limits. The impacts of Existing Transmission
Commitments (ETCs) are determined by simulation. The
impacts of ETC, Capacity Benefit Margin (CBM) and
Transmission Reliability Margin (TRM) are subtracted from
the Total Flowgate Capability, and Postbacks and
counterflows are added, to determine the Available
Flowgate Capability (AFC) value for that Flowgate. AFCs
can be used to determine Available Transfer Capability
(ATC).
2/8/2005
3/16/2007
1. The removal from service availability of a generating
unit, transmission line, or other facility for emergency
reasons.
[Archive]
Forced Outage
[Archive]
2. The condition in which the equipment is unavailable due
to unanticipated failure.
Frequency Bias
[Archive]
August 4, 2011
2/8/2005
3/16/2007
A value, usually expressed in megawatts per 0.1 Hertz
(MW/0.1 Hz), associated with a Balancing Authority Area
that approximates the Balancing Authority Area’s response
to Interconnection frequency error.
Page 20 of 55
ATTACHMENT D
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Page 21 of 55
Glossary of Terms Used in NERC Reliability Standards
Continent-wide
Term
Frequency Bias
Setting
Acronym
BOT
Approved
Date
FERC
Approved
Date
2/8/2005
3/16/2007
A value, usually expressed in MW/0.1 Hz, set into a
Balancing Authority ACE algorithm that allows the Balancing
Authority to contribute its frequency response to the
Interconnection.
2/8/2005
3/16/2007
A change in Interconnection frequency.
2/8/2005
3/16/2007
The difference between the actual and scheduled frequency.
(FA – FS)
2/8/2005
3/16/2007
The ability of a Balancing Authority to help the
Interconnection maintain Scheduled Frequency. This
assistance can include both turbine governor response and
Automatic Generation Control.
2/8/2005
3/16/2007
(Equipment) The ability of a system or elements of the
system to react or respond to a change in system
frequency.
[Archive]
Frequency Deviation
Definition
[Archive]
Frequency Error
[Archive]
Frequency Regulation
[Archive]
Frequency Response
[Archive]
(System) The sum of the change in demand, plus the
change in generation, divided by the change in frequency,
expressed in megawatts per 0.1 Hertz (MW/0.1 Hz).
August 4, 2011
Page 21 of 55
ATTACHMENT D
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Page 22 of 55
Glossary of Terms Used in NERC Reliability Standards
Continent-wide
Term
Acronym
Generator Operator
BOT
Approved
Date
FERC
Approved
Date
Definition
2/8/2005
3/16/2007
The entity that operates generating unit(s) and performs
the functions of supplying energy and Interconnected
Operations Services.
2/8/2005
3/16/2007
Entity that owns and maintains generating units.
GSF
2/8/2005
3/16/2007
A factor to be applied to a generator’s expected change in
output to determine the amount of flow contribution that
change in output will impose on an identified transmission
facility or Flowgate.
GLDF
2/8/2005
3/16/2007
The algebraic sum of a Generator Shift Factor and a Load
Shift Factor to determine the total impact of an Interchange
Transaction on an identified transmission facility or
Flowgate.
GCIR
11/13/2008
11/24/2009
The amount of generation capability from external sources
identified by a Load-Serving Entity (LSE) or Resource
Planner (RP) to meet its generation reliability or resource
adequacy requirements as an alternative to internal
resources.
2/8/2005
3/16/2007
1. A Balancing Authority that confirms and implements
Interchange Transactions for a Purchasing Selling Entity
that operates generation or serves customers directly
within the Balancing Authority’s metered boundaries.
[Archive]
Generator Owner
[Archive]
Generator Shift Factor
[Archive]
Generator-to-Load
Distribution Factor
[Archive]
Generation Capability
Import Requirement
[Archive]
Host Balancing
Authority
[Archive]
2. The Balancing Authority within whose metered
boundaries a jointly owned unit is physically located.
Hourly Value
2/8/2005
3/16/2007
Data measured on a Clock Hour basis.
[Archive]
August 4, 2011
Page 22 of 55
ATTACHMENT D
to Order G-162-11
Page 23 of 55
Glossary of Terms Used in NERC Reliability Standards
Continent-wide
Term
Acronym
BOT
Approved
Date
FERC
Approved
Date
Definition
5/2/2006
3/16/2007
The state where the Balancing Authority enters the
Confirmed Interchange into its Area Control Error equation.
2/8/2005
3/16/2007
The difference between the Balancing Authority’s Net Actual
Interchange and Net Scheduled Interchange.
(IA – IS)
IPP
2/8/2005
3/16/2007
Any entity that owns or operates an electricity generating
facility that is not included in an electric utility’s rate base.
This term includes, but is not limited to, cogenerators and
small power producers and all other nonutility electricity
producers, such as exempt wholesale generators, who sell
electricity.
IEEE
2/7/2006
3/16/2007
5/2/2006
3/16/2007
Energy transfers that cross Balancing Authority boundaries.
5/2/2006
3/16/2007
The responsible entity that authorizes implementation of
valid and balanced Interchange Schedules between
Balancing Authority Areas, and ensures communication of
Interchange information for reliability assessment purposes.
2/8/2005
3/16/2007
The mechanism used by Reliability Coordinators in the
Eastern Interconnection to calculate the distribution of
Interchange Transactions over specific Flowgates. It includes
a database of all Interchange Transactions and a matrix of
the Distribution Factors for the Eastern Interconnection.
Implemented
Interchange
[Archive]
Inadvertent
Interchange
[Archive]
Independent Power
Producer
[Archive]
Institute of Electrical
and Electronics
Engineers, Inc.
[Archive]
Interchange
[Archive]
Interchange Authority
[Archive]
Interchange
Distribution Calculator
[Archive]
August 4, 2011
IDC
Page 23 of 55
ATTACHMENT D
to Order G-162-11
Page 24 of 55
Glossary of Terms Used in NERC Reliability Standards
Continent-wide
Term
Acronym
Interchange Schedule
BOT
Approved
Date
FERC
Approved
Date
2/8/2005
3/16/2007
An agreed-upon Interchange Transaction size (megawatts),
start and end time, beginning and ending ramp times and
rate, and type required for delivery and receipt of power and
energy between the Source and Sink Balancing Authorities
involved in the transaction.
2/8/2005
3/16/2007
An agreement to transfer energy from a seller to a buyer
that crosses one or more Balancing Authority Area
boundaries.
2/8/2005
3/16/2007
The details of an Interchange Transaction required for its
physical implementation.
2/8/2005
3/16/2007
A service (exclusive of basic energy and transmission
services) that is required to support the reliable operation of
interconnected Bulk Electric Systems.
2/8/2005
3/16/2007
When capitalized, any one of the three major electric system
networks in North America: Eastern, Western, and ERCOT.
2/8/2005
3/16/2007
The value (such as MW, MVar, Amperes, Frequency or Volts)
derived from, or a subset of the System Operating Limits,
which if exceeded, could expose a widespread area of the
Bulk Electric System to instability, uncontrolled separation(s)
or cascading outages.
[Archive]
Interchange
Transaction
[Archive]
Interchange
Transaction Tag
Definition
or
Tag
[Archive]
Interconnected
Operations Service
[Archive]
Interconnection
[Archive]
Interconnection
Reliability Operating
Limit
IROL
Retired
12/27/2007
[Archive]
Interconnection
Reliability Operating
Limit
[Archive]
August 4, 2011
IROL
11/1/2006
12/27/2007
A System Operating Limit that, if violated, could lead to
instability, uncontrolled separation, or Cascading Outages
that adversely impact the reliability of the Bulk Electric
System.
Page 24 of 55
ATTACHMENT D
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Page 25 of 55
Glossary of Terms Used in NERC Reliability Standards
Continent-wide
Term
Interconnection
Reliability Operating
Limit Tv
Acronym
IROL Tv
BOT
Approved
Date
FERC
Approved
Date
11/1/2006
12/27/2007
The maximum time that an Interconnection Reliability
Operating Limit can be violated before the risk to the
interconnection or other Reliability Coordinator Area(s)
becomes greater than acceptable. Each Interconnection
Reliability Operating Limit’s Tv shall be less than or equal to
30 minutes.
2/8/2005
3/16/2007
A Balancing Authority Area that has connecting facilities in
the Scheduling Path between the Sending Balancing
Authority Area and Receiving Balancing Authority Area and
operating agreements that establish the conditions for the
use of such facilities
11/1/2006
3/16/2007
Demand that the end-use customer makes available to its
Load-Serving Entity via contract or agreement for
curtailment.
2/8/2005
3/16/2007
Automatic Generation Control of jointly owned units by two
or more Balancing Authorities.
[Archive]
Intermediate
Balancing Authority
[Archive]
Interruptible Load
or
Interruptible Demand
Definition
[Archive]
Joint Control
[Archive]
August 4, 2011
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ATTACHMENT D
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Page 26 of 55
Glossary of Terms Used in NERC Reliability Standards
Continent-wide
Term
Acronym
Limiting Element
BOT
Approved
Date
FERC
Approved
Date
2/8/2005
3/16/2007
The element that is 1. )Either operating at its appropriate
rating, or 2,) Would be following the limiting contingency.
Thus, the Limiting Element establishes a system limit.
2/8/2005
3/16/2007
An end-use device or customer that receives power from the
electric system.
2/8/2005
3/16/2007
A factor to be applied to a load’s expected change in demand
to determine the amount of flow contribution that change in
demand will impose on an identified transmission facility or
monitored Flowgate.
2/8/2005
3/16/2007
Secures energy and transmission service (and related
Interconnected Operations Services) to serve the electrical
demand and energy requirements of its end-use customers.
[Archive]
Load
[Archive]
Load Shift Factor
LSF
[Archive]
Load-Serving Entity
[Archive]
Long-Term
Transmission Planning
Horizon
8/4/2011
Transmission planning period that covers years six through
ten or beyond when required to accommodate any known
longer lead time projects that may take longer than ten years
to complete.
[Archive]
Market Flow
11/4/2010
4/21/2011
The total amount of power flowing across a specified Facility
or set of Facilities due to a market dispatch of generation
internal to the market to serve load internal to the market.
2/7/2006
3/16/2007

Any failure of a Protection System element to operate
within the specified time when a fault or abnormal
condition occurs within a zone of protection.

Any operation for a fault not within a zone of protection
(other than operation as backup protection for a fault in
an adjacent zone that is not cleared within a specified
time for the protection for that zone).

Any unintentional Protection System operation when no
fault or other abnormal condition has occurred unrelated
to on-site maintenance and testing activity.
[Archive]
Misoperation
Definition
[Archive]
August 4, 2011
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Glossary of Terms Used in NERC Reliability Standards
Continent-wide
Term
Native Load
Acronym
BOT
Approved
Date
2/8/2005
FERC
Approved
Date
3/16/2007
[Archive]
Near-Term
Transmission Planning
Horizon
1/24/2011
Definition
The end-use customers that the Load-Serving Entity is
obligated to serve.
The transmission planning period that covers Year One
through five.
[Archive]
Net Actual Interchange
2/8/2005
3/16/2007
The algebraic sum of all metered interchange over all
interconnections between two physically Adjacent Balancing
Authority Areas.
2/8/2005
3/16/2007
Net Balancing Authority Area generation, plus energy
received from other Balancing Authority Areas, less energy
delivered to Balancing Authority Areas through interchange.
It includes Balancing Authority Area losses but excludes
energy required for storage at energy storage facilities.
2/8/2005
3/16/2007
The algebraic sum of all Interchange Schedules with each
Adjacent Balancing Authority.
2/8/2005
3/16/2007
The algebraic sum of all Interchange Schedules across a
given path or between Balancing Authorities for a given
period or instant in time.
2/8/2005
3/16/2007
Service that allows an electric transmission customer to
integrate, plan, economically dispatch and regulate its
network reserves in a manner comparable to that in which
the Transmission Owner serves Native Load customers.
[Archive]
Net Energy for Load
[Archive]
Net Interchange
Schedule
[Archive]
Net Scheduled
Interchange
[Archive]
Network Integration
Transmission Service
[Archive]
Non-Consequential
Load Loss
[Archive]
August 4, 2011
8/4/2011
Non-Interruptible Load loss that does not include: (1)
Consequential Load Loss, (2) the response of voltage
sensitive Load, or (3) Load that is disconnected from the
System by end-user equipment.
Page 27 of 55
ATTACHMENT D
to Order G-162-11
Page 28 of 55
Glossary of Terms Used in NERC Reliability Standards
Continent-wide
Term
Non-Firm Transmission
Service
Acronym
BOT
Approved
Date
FERC
Approved
Date
Definition
2/8/2005
3/16/2007
Transmission service that is reserved on an as-available
basis and is subject to curtailment or interruption.
2/8/2005
3/16/2007
1. That generating reserve not connected to the system but
capable of serving demand within a specified time.
[Archive]
Non-Spinning Reserve
[Archive]
2. Interruptible load that can be removed from the system in
a specified time.
Normal Clearing
11/1/2006
12/27/2007
A protection system operates as designed and the fault is
cleared in the time normally expected with proper
functioning of the installed protection systems.
2/8/2005
3/16/2007
The rating as defined by the equipment owner that specifies
the level of electrical loading, usually expressed in
megawatts (MW) or other appropriate units that a system,
facility, or element can support or withstand through the
daily demand cycles without loss of equipment life.
5/2/2007
10/16/2008
Any Generator Operator or Generator Owner that is a
Nuclear Plant Licensee responsible for operation of a nuclear
facility licensed to produce commercial power.
5/2/2007
10/16/2008
The electric power supply provided from the electric system
to the nuclear power plant distribution system as required
per the nuclear power plant license.
[Archive]
Normal Rating
[Archive]
Nuclear Plant
Generator Operator
[Archive]
Nuclear Plant Off-site
Power Supply (Off-site
Power)
[Archive]
August 4, 2011
Page 28 of 55
ATTACHMENT D
to Order G-162-11
Page 29 of 55
Glossary of Terms Used in NERC Reliability Standards
Continent-wide
Term
Nuclear Plant Licensing
Requirements (NPLRs)
Acronym
BOT
Approved
Date
5/2/2007
FERC
Approved
Date
10/16/2008
[Archive]
Definition
Requirements included in the design basis of the nuclear
plant and statutorily mandated for the operation of the plant,
including nuclear power plant licensing requirements for:
1) Off-site power supply to enable safe shutdown of the
plant during an electric system or plant event; and
2) Avoiding preventable challenges to nuclear safety as a
result of an electric system disturbance, transient, or
condition.
Nuclear Plant Interface
Requirements (NPIRs)
[Archive]
August 4, 2011
5/2/2007
10/16/2008
The requirements based on NPLRs and Bulk Electric System
requirements that have been mutually agreed to by the
Nuclear Plant Generator Operator and the applicable
Transmission Entities.
Page 29 of 55
ATTACHMENT D
to Order G-162-11
Page 30 of 55
Glossary of Terms Used in NERC Reliability Standards
Continent-wide
Term
Acronym
Off-Peak
BOT
Approved
Date
FERC
Approved
Date
2/8/2005
3/16/2007
Those hours or other periods defined by NAESB business
practices, contract, agreements, or guides as periods of
lower electrical demand.
2/8/2005
3/16/2007
Those hours or other periods defined by NAESB business
practices, contract, agreements, or guides as periods of
higher electrical demand.
OASIS
2/8/2005
3/16/2007
An electronic posting system that the Transmission Service
Provider maintains for transmission access data and that
allows all transmission customers to view the data
simultaneously.
OATT
2/8/2005
3/16/2007
Electronic transmission tariff accepted by the U.S. Federal
Energy Regulatory Commission requiring the Transmission
Service Provider to furnish to all shippers with nondiscriminating service comparable to that provided by
Transmission Owners to themselves.
2/7/2006
3/16/2007
A document that identifies a group of activities that may be
used to achieve some goal. An Operating Plan may contain
Operating Procedures and Operating Processes. A
company-specific system restoration plan that includes an
Operating Procedure for black-starting units, Operating
Processes for communicating restoration progress with
other entities, etc., is an example of an Operating Plan.
[Archive]
On-Peak
[Archive]
Open Access Same
Time Information
Service
[Archive]
Open Access
Transmission Tariff
[Archive]
Operating Plan
[Archive]
August 4, 2011
Definition
Page 30 of 55
ATTACHMENT D
to Order G-162-11
Page 31 of 55
Glossary of Terms Used in NERC Reliability Standards
Continent-wide
Term
Operating Procedure
Acronym
BOT
Approved
Date
FERC
Approved
Date
2/7/2006
3/16/2007
A document that identifies specific steps or tasks that
should be taken by one or more specific operating positions
to achieve specific operating goal(s). The steps in an
Operating Procedure should be followed in the order in
which they are presented, and should be performed by the
position(s) identified. A document that lists the specific
steps for a system operator to take in removing a specific
transmission line from service is an example of an
Operating Procedure.
2/7/2006
3/16/2007
A document that identifies general steps for achieving a
generic operating goal. An Operating Process includes steps
with options that may be selected depending upon Realtime conditions. A guideline for controlling high voltage is
an example of an Operating Process.
2/8/2005
3/16/2007
That capability above firm system demand required to
provide for regulation, load forecasting error, equipment
forced and scheduled outages and local area protection. It
consists of spinning and non-spinning reserve.
2/8/2005
3/16/2007
The portion of Operating Reserve consisting of:
[Archive]
Operating Process
[Archive]
Operating Reserve
[Archive]
Operating Reserve –
Spinning
[Archive]
Definition
• Generation synchronized to the system and fully
available to serve load within the Disturbance Recovery
Period following the contingency event; or
• Load fully removable from the system within the
Disturbance Recovery Period following the contingency
event.
August 4, 2011
Page 31 of 55
ATTACHMENT D
to Order G-162-11
Page 32 of 55
Glossary of Terms Used in NERC Reliability Standards
Continent-wide
Term
Acronym
Operating Reserve –
Supplemental
BOT
Approved
Date
2/8/2005
FERC
Approved
Date
3/16/2007
Definition
The portion of Operating Reserve consisting of:
• Generation (synchronized or capable of being
synchronized to the system) that is fully available to
serve load within the Disturbance Recovery Period
following the contingency event; or
[Archive]
• Load fully removable from the system within the
Disturbance Recovery Period following the contingency
event.
Operating Voltage
2/7/2006
3/16/2007
[Archive]
Operational Planning
Analysis
10/17/2008
An analysis of the expected system conditions for the next
day’s operation. (That analysis may be performed either a
day ahead or as much as 12 months ahead.) Expected
system conditions include things such as load forecast(s),
generation output levels, and known system constraints
(transmission facility outages, generator outages,
equipment limitations, etc.).
[Archive]
Outage Transfer
Distribution Factor
OTDF
8/22/2008
11/24/2009
In the post-contingency configuration of a system under
study, the electric Power Transfer Distribution Factor (PTDF)
with one or more system Facilities removed from service
(outaged).
2/8/2005
3/16/2007
A method of providing regulation service in which the
Balancing Authority providing the regulation service
incorporates another Balancing Authority’s actual
interchange, frequency response, and schedules into
providing Balancing Authority’s AGC/ACE equation.
[Archive]
Overlap Regulation
Service
[Archive]
August 4, 2011
The voltage level by which an electrical system is
designated and to which certain operating characteristics of
the system are related; also, the effective (root-meansquare) potential difference between any two conductors or
between a conductor and the ground. The actual voltage of
the circuit may vary somewhat above or below this value.
Page 32 of 55
ATTACHMENT D
to Order G-162-11
Page 33 of 55
Glossary of Terms Used in NERC Reliability Standards
Continent-wide
Term
Acronym
Participation Factors
BOT
Approved
Date
FERC
Approved
Date
8/22/2008
11/24/2009
A set of dispatch rules such that given a specific amount of
load to serve, an approximate generation dispatch can be
determined. To accomplish this, generators are assigned a
percentage that they will contribute to serve load.
2/8/2005
3/16/2007
1. The highest hourly integrated Net Energy For Load within
a Balancing Authority Area occurring within a given
period (e.g., day, month, season, or year).
[Archive]
Peak Demand
Definition
[Archive]
2. The highest instantaneous demand within the Balancing
Authority Area.
Performance-Reset
Period
2/7/2006
3/16/2007
The time period that the entity being assessed must operate
without any violations to reset the level of non compliance
to zero.
5/2/2006
1/18/2008
The physical, completely enclosed (“six-wall”) border
surrounding computer rooms, telecommunications rooms,
operations centers, and other locations in which Critical
Cyber Assets are housed and for which access is controlled.
[Archive]
Physical Security
Perimeter
[Archive]
Planning Assessment
8/4/2011
Documented evaluation of future Transmission system
performance and Corrective Action Plans to remedy
identified deficiencies.
[Archive]
Planning Authority
2/8/2005
3/16/2007
The responsible entity that coordinates and integrates
transmission facility and service plans, resource plans, and
protection systems.
8/22/2008
11/24/2009
See Planning Authority.
2/8/2005
3/16/2007
A location that the Transmission Service Provider specifies
on its transmission system where an Interchange
Transaction leaves or a Load-Serving Entity receives its
energy.
[Archive]
Planning Coordinator
[Archive]
Point of Delivery
[Archive]
August 4, 2011
POD
Page 33 of 55
ATTACHMENT D
to Order G-162-11
Page 34 of 55
Glossary of Terms Used in NERC Reliability Standards
Continent-wide
Term
Point of Receipt
Acronym
BOT
Approved
Date
FERC
Approved
Date
POR
2/8/2005
3/16/2007
A location that the Transmission Service Provider specifies
on its transmission system where an Interchange
Transaction enters or a Generator delivers its output.
PTP
2/8/2005
3/16/2007
The reservation and transmission of capacity and energy on
either a firm or non-firm basis from the Point(s) of Receipt
to the Point(s) of Delivery.
08/22/2008
Not
approved;
Positive adjustments to ATC or AFC as defined in Business
Practices. Such Business Practices may include processing
of redirects and unscheduled service.
[Archive]
Point to Point
Transmission Service
[Archive]
Postback
[Archive]
Modification
directed
11/24/09
Power Transfer
Distribution Factor
PTDF
08/22/2008
11/24/2009
In the pre-contingency configuration of a system under
study, a measure of the responsiveness or change in
electrical loadings on transmission system Facilities due to a
change in electric power transfer from one area to another,
expressed in percent (up to 100%) of the change in power
transfer
2/8/2005
3/16/2007
Usually refers to the standard OATT and/or associated
transmission rights mandated by the U.S. Federal Energy
Regulatory Commission Order No. 888.
2/7/2006
3/17/07
Protective relays, associated communication systems,
voltage and current sensing devices, station batteries and
DC control circuitry.
[Archive]
Pro Forma Tariff
[Archive]
Protection System
[Archive]
August 4, 2011
Definition
Page 34 of 55
ATTACHMENT D
to Order G-162-11
Page 35 of 55
Glossary of Terms Used in NERC Reliability Standards
Continent-wide
Term
Protection System
Acronym
BOT
Approved
Date
FERC
Approved
Date
11/19/2010
Protection System –
[Archive]
Pseudo-Tie
•
Voltage and current sensing devices providing inputs
to protective relays,
•
Station dc supply associated with protective
functions (including batteries, battery chargers, and
non-battery-based dc supply), and
•
Control circuitry associated with protective functions
through the trip coil(s) of the circuit breakers or
other interrupting devices.
3/16/2007
The entity that purchases or sells, and takes title to,
energy, capacity, and Interconnected Operations Services.
Purchasing-Selling Entities may be affiliated or unaffiliated
merchants and may or may not own generating facilities.
2/8/2005
3/16/2007
(Schedule) The rate, expressed in megawatts per minute, at
which the interchange schedule is attained during the ramp
period.
(Generator) The rate, expressed in megawatts per minute,
that a generator changes its output.
[Archive]
August 4, 2011
Communications systems necessary for correct
operation of protective functions
2/8/2005
Ramp
[Archive]
•
A telemetered reading or value that is updated in real time
and used as a “virtual” tie line flow in the AGC/ACE equation
but for which no physical tie or energy metering actually
exists. The integrated value is used as a metered MWh
value for interchange accounting purposes.
or
Rated Electrical
Operating Conditions
Protective relays which respond to electrical
quantities,
3/16/2007
[Archive]
Ramp Rate
•
2/8/2005
[Archive]
Purchasing-Selling
Entity
Definition
2/7/2006
3/16/2007
The specified or reasonably anticipated conditions under
which the electrical system or an individual electrical circuit
is intend/designed to operate
Page 35 of 55
ATTACHMENT D
to Order G-162-11
Page 36 of 55
Glossary of Terms Used in NERC Reliability Standards
Continent-wide
Term
Rating
Acronym
BOT
Approved
Date
FERC
Approved
Date
2/8/2005
3/16/2007
The operational limits of a transmission system element
under a set of specified conditions.
08/22/2008
11/24/2009
The Rated System Path Methodology is characterized by an
initial Total Transfer Capability (TTC), determined via
simulation. Capacity Benefit Margin, Transmission
Reliability Margin, and Existing Transmission Commitments
are subtracted from TTC, and Postbacks and counterflows
are added as applicable, to derive Available Transfer
Capability. Under the Rated System Path Methodology, TTC
results are generally reported as specific transmission path
capabilities.
2/8/2005
3/16/2007
The portion of electricity that establishes and sustains the
electric and magnetic fields of alternating-current
equipment. Reactive power must be supplied to most types
of magnetic equipment, such as motors and transformers.
It also must supply the reactive losses on transmission
facilities. Reactive power is provided by generators,
synchronous condensers, or electrostatic equipment such as
capacitors and directly influences electric system voltage. It
is usually expressed in kilovars (kvar) or megavars (Mvar).
2/8/2005
3/16/2007
The portion of electricity that supplies energy to the load.
2/8/2005
3/16/2007
The total or partial curtailment of Transactions during TLR
Level 3a or 5a to allow Transactions using higher priority to
be implemented.
2/7/2006
3/16/2007
Present time as opposed to future time. (From
Interconnection Reliability Operating Limits standard.)
[Archive]
Rated System Path
Methodology
[Archive]
Reactive Power
[Archive]
Real Power
Definition
[Archive]
Reallocation
[Archive]
Real-time
[Archive]
Real-time Assessment
[Archive]
August 4, 2011
10/17/2008
An examination of existing and expected system conditions,
conducted by collecting and reviewing immediately available
data
Page 36 of 55
ATTACHMENT D
to Order G-162-11
Page 37 of 55
Glossary of Terms Used in NERC Reliability Standards
Continent-wide
Term
Receiving Balancing
Authority
Acronym
BOT
Approved
Date
FERC
Approved
Date
Definition
2/8/2005
3/16/2007
The Balancing Authority importing the Interchange.
2/8/2005
3/16/2007
1. An entity that ensures that a defined area of the Bulk
Electric System is reliable, adequate and secure.
[Archive]
Regional Reliability
Organization
2. A member of the North American Electric Reliability
Council. The Regional Reliability Organization can serve
as the Compliance Monitor.
[Archive]
Regional Reliability
Plan
2/8/2005
3/16/2007
The plan that specifies the Reliability Coordinators and
Balancing Authorities within the Regional Reliability
Organization, and explains how reliability coordination will
be accomplished.
2/8/2005
3/16/2007
An amount of reserve responsive to Automatic Generation
Control, which is sufficient to provide normal regulating
margin.
2/8/2005
3/16/2007
The process whereby one Balancing Authority contracts to
provide corrective response to all or a portion of the ACE of
another Balancing Authority. The Balancing Authority
providing the response assumes the obligation of meeting
all applicable control criteria as specified by NERC for itself
and the Balancing Authority for which it is providing the
Regulation Service.
10/29/2008
12/17/2009
Request to modify an Implemented Interchange Schedule
for reliability purposes.
[Archive]
Regulating Reserve
[Archive]
Regulation Service
[Archive]
Reliability Adjustment
RFI
[Archive]
August 4, 2011
Page 37 of 55
ATTACHMENT D
to Order G-162-11
Page 38 of 55
Glossary of Terms Used in NERC Reliability Standards
Continent-wide
Term
Acronym
Reliability Coordinator
BOT
Approved
Date
FERC
Approved
Date
2/8/2005
3/16/2007
The entity that is the highest level of authority who is
responsible for the reliable operation of the Bulk Electric
System, has the Wide Area view of the Bulk Electric
System, and has the operating tools, processes and
procedures, including the authority to prevent or mitigate
emergency operating situations in both next-day analysis
and real-time operations. The Reliability Coordinator has
the purview that is broad enough to enable the calculation
of Interconnection Reliability Operating Limits, which may
be based on the operating parameters of transmission
systems beyond any Transmission Operator’s vision.
2/8/2005
3/16/2007
The collection of generation, transmission, and loads within
the boundaries of the Reliability Coordinator. Its boundary
coincides with one or more Balancing Authority Areas.
RCIS
2/8/2005
3/16/2007
The system that Reliability Coordinators use to post
messages and share operating information in real time.
RAS
2/8/2005
3/16/2007
See “Special Protection System”
2/8/2005
3/16/2007
Any event that causes an ACE change greater than or equal
to 80% of a Balancing Authority’s or reserve sharing group’s
most severe contingency. The definition of a reportable
disturbance is specified by each Regional Reliability
Organization. This definition may not be retroactively
adjusted in response to observed performance.
5/2/2006
3/16/2007
A collection of data as defined in the NAESB RFI Datasheet,
to be submitted to the Interchange Authority for the
purpose of implementing bilateral Interchange between a
Source and Sink Balancing Authority.
[Archive]
Reliability Coordinator
Area
[Archive]
Reliability Coordinator
Information System
Definition
[Archive]
Remedial Action
Scheme
[Archive]
Reportable
Disturbance
[Archive]
Request for
Interchange
[Archive]
August 4, 2011
RFI
Page 38 of 55
ATTACHMENT D
to Order G-162-11
Page 39 of 55
Glossary of Terms Used in NERC Reliability Standards
Continent-wide
Term
Reserve Sharing
Group
Acronym
BOT
Approved
Date
FERC
Approved
Date
2/8/2005
3/16/2007
A group whose members consist of two or more Balancing
Authorities that collectively maintain, allocate, and supply
operating reserves required for each Balancing Authority’s
use in recovering from contingencies within the group.
Scheduling energy from an Adjacent Balancing Authority to
aid recovery need not constitute reserve sharing provided
the transaction is ramped in over a period the supplying
party could reasonably be expected to load generation in
(e.g., ten minutes). If the transaction is ramped in quicker
(e.g., between zero and ten minutes) then, for the purposes
of Disturbance Control Performance, the Areas become a
Reserve Sharing Group.
2/8/2005
3/16/2007
The entity that develops a long-term (generally one year
and beyond) plan for the resource adequacy of specific
loads (customer demand and energy requirements) within a
Planning Authority Area.
2/8/2005
3/16/2007
The Ramp Rate that a generating unit can achieve under
normal operating conditions expressed in megawatts per
minute (MW/Min).
2/7/2006
3/16/2007
A corridor of land on which electric lines may be located.
The Transmission Owner may own the land in fee, own an
easement, or have certain franchise, prescription, or license
rights to construct and maintain lines.
[Archive]
Resource Planner
[Archive]
Response Rate
[Archive]
Right-of-Way (ROW)
[Archive]
August 4, 2011
Definition
Page 39 of 55
ATTACHMENT D
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Page 40 of 55
Glossary of Terms Used in NERC Reliability Standards
Continent-wide
Term
Scenario
Acronym
BOT
Approved
Date
FERC
Approved
Date
2/7/2006
3/16/2007
Possible event.
2/8/2005
3/16/2007
(Verb) To set up a plan or arrangement for an Interchange
Transaction.
Definition
[Archive]
Schedule
[Archive]
(Noun) An Interchange Schedule.
Scheduled Frequency
2/8/2005
3/16/2007
60.0 Hertz, except during a time correction.
2/8/2005
3/16/2007
An entity responsible for approving and implementing
Interchange Schedules.
2/8/2005
3/16/2007
The Transmission Service arrangements reserved by the
Purchasing-Selling Entity for a Transaction.
2/8/2005
3/16/2007
The Balancing Authority exporting the Interchange.
2/8/2005
3/16/2007
The Balancing Authority in which the load (sink) is located for
an Interchange Transaction. (This will also be a Receiving
Balancing Authority for the resulting Interchange Schedule.)
2/8/2005
3/16/2007
The Balancing Authority in which the generation (source) is
located for an Interchange Transaction. (This will also be a
Sending Balancing Authority for the resulting Interchange
Schedule.)
[Archive]
Scheduling Entity
[Archive]
Scheduling Path
[Archive]
Sending Balancing
Authority
[Archive]
Sink Balancing
Authority
[Archive]
Source Balancing
Authority
[Archive]
August 4, 2011
Page 40 of 55
ATTACHMENT D
to Order G-162-11
Page 41 of 55
Glossary of Terms Used in NERC Reliability Standards
Continent-wide
Term
Acronym
Special Protection
System
BOT
Approved
Date
FERC
Approved
Date
2/8/2005
3/16/2007
An automatic protection system designed to detect abnormal
or predetermined system conditions, and take corrective
actions other than and/or in addition to the isolation of faulted
components to maintain system reliability. Such action may
include changes in demand, generation (MW and Mvar), or
system configuration to maintain system stability, acceptable
voltage, or power flows. An SPS does not include (a)
underfrequency or undervoltage load shedding or (b) fault
conditions that must be isolated or (c) out-of-step relaying
(not designed as an integral part of an SPS). Also called
Remedial Action Scheme.
2/8/2005
3/16/2007
Unloaded generation that is synchronized and ready to serve
additional demand.
2/8/2005
3/16/2007
The ability of an electric system to maintain a state of
equilibrium during normal and abnormal conditions or
disturbances.
2/8/2005
3/16/2007
The maximum power flow possible through some particular
point in the system while maintaining stability in the entire
system or the part of the system to which the stability limit
refers.
2/8/2005
3/16/2007
A system of remote control and telemetry used to monitor
and control the transmission system.
2/8/2005
3/16/2007
A method of providing regulation service in which the
Balancing Authority providing the regulation service receives a
signal representing all or a portion of the other Balancing
Authority’s ACE.
2/8/2005
3/16/2007
A transient variation of current, voltage, or power flow in an
electric circuit or across an electric system.
(Remedial Action
Scheme)
[Archive]
Spinning Reserve
[Archive]
Stability
[Archive]
Stability Limit
[Archive]
Supervisory Control
and Data Acquisition
SCADA
Definition
[Archive]
Supplemental
Regulation Service
[Archive]
Surge
[Archive]
August 4, 2011
Page 41 of 55
ATTACHMENT D
to Order G-162-11
Page 42 of 55
Glossary of Terms Used in NERC Reliability Standards
Continent-wide
Term
Sustained Outage
Acronym
BOT
Approved
Date
FERC
Approved
Date
2/7/2006
3/16/2007
The deenergized condition of a transmission line resulting
from a fault or disturbance following an unsuccessful
automatic reclosing sequence and/or unsuccessful manual
reclosing procedure.
2/8/2005
3/16/2007
A combination of generation, transmission, and distribution
components.
2/8/2005
3/16/2007
The value (such as MW, MVar, Amperes, Frequency or Volts)
that satisfies the most limiting of the prescribed operating
criteria for a specified system configuration to ensure
operation within acceptable reliability criteria. System
Operating Limits are based upon certain operating criteria.
These include, but are not limited to:
[Archive]
System
[Archive]
System Operating
Limit
[Archive]
Definition
• Facility Ratings (Applicable pre- and post-Contingency
equipment or facility ratings)
• Transient Stability Ratings (Applicable pre- and postContingency Stability Limits)
• Voltage Stability Ratings (Applicable pre- and postContingency Voltage Stability)
• System Voltage Limits (Applicable pre- and postContingency Voltage Limits)
System Operator
[Archive]
August 4, 2011
2/8/2005
3/16/2007
An individual at a control center (Balancing Authority,
Transmission Operator, Generator Operator, Reliability
Coordinator) whose responsibility it is to monitor and control
that electric system in real time.
Page 42 of 55
ATTACHMENT D
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Page 43 of 55
Glossary of Terms Used in NERC Reliability Standards
Continent-wide
Term
Telemetering
Acronym
BOT
Approved
Date
FERC
Approved
Date
2/8/2005
3/16/2007
The process by which measurable electrical quantities from
substations and generating stations are instantaneously
transmitted to the control center, and by which operating
commands from the control center are transmitted to the
substations and generating stations.
2/8/2005
3/16/2007
The maximum amount of electrical current that a
transmission line or electrical facility can conduct over a
specified time period before it sustains permanent damage
by overheating or before it sags to the point that it violates
public safety requirements.
2/8/2005
3/16/2007
A circuit connecting two Balancing Authority Areas.
2/8/2005
3/16/2007
A mode of Automatic Generation Control that allows the
Balancing Authority to 1.) maintain its Interchange
Schedule and 2.) respond to Interconnection frequency
error.
2/8/2005
3/16/2007
The difference between the Interconnection time measured
at the Balancing Authority(ies) and the time specified by the
National Institute of Standards and Technology. Time error
is caused by the accumulation of Frequency Error over a
given period.
2/8/2005
3/16/2007
An offset to the Interconnection’s scheduled frequency to
return the Interconnection’s Time Error to a predetermined
value.
2/8/2005
3/16/2007
Report required to be filed after every TLR Level 2 or higher
in a specified format. The NERC IDC prepares the report for
review by the issuing Reliability Coordinator. After approval
by the issuing Reliability Coordinator, the report is
electronically filed in a public area of the NERC Web site.
[Archive]
Thermal Rating
[Archive]
Tie Line
Definition
[Archive]
Tie Line Bias
[Archive]
Time Error
[Archive]
Time Error Correction
[Archive]
TLR Log
[Archive]
August 4, 2011
Page 43 of 55
ATTACHMENT D
to Order G-162-11
Page 44 of 55
Glossary of Terms Used in NERC Reliability Standards
Continent-wide
Term
Total Flowgate
Capability
BOT
Approved
Date
FERC
Approved
Date
TFC
08/22/2008
11/24/2009
The maximum flow capability on a Flowgate, is not to
exceed its thermal rating, or in the case of a flowgate used
to represent a specific operating constraint (such as a
voltage or stability limit), is not to exceed the associated
System Operating Limit.
TTC
2/8/2005
3/16/2007
The amount of electric power that can be moved or
transferred reliably from one area to another area of the
interconnected transmission systems by way of all
transmission lines (or paths) between those areas under
specified system conditions.
2/8/2005
3/16/2007
See Interchange Transaction.
2/8/2005
3/16/2007
The measure of the ability of interconnected electric
systems to move or transfer power in a reliable manner
from one area to another over all transmission lines (or
paths) between those areas under specified system
conditions. The units of transfer capability are in terms of
electric power, generally expressed in megawatts (MW).
The transfer capability from “Area A” to “Area B” is not
generally equal to the transfer capability from “Area B” to
“Area A.”
2/8/2005
3/16/2007
See Distribution Factor.
2/8/2005
3/16/2007
An interconnected group of lines and associated equipment
for the movement or transfer of electric energy between
points of supply and points at which it is transformed for
delivery to customers or is delivered to other electric
systems.
Acronym
[Archive]
Total Transfer
Capability
[Archive]
Transaction
Definition
[Archive]
Transfer Capability
[Archive]
Transfer Distribution
Factor
[Archive]
Transmission
[Archive]
August 4, 2011
Page 44 of 55
ATTACHMENT D
to Order G-162-11
Page 45 of 55
Glossary of Terms Used in NERC Reliability Standards
Continent-wide
Term
Transmission
Constraint
Acronym
BOT
Approved
Date
FERC
Approved
Date
2/8/2005
3/16/2007
A limitation on one or more transmission elements that may
be reached during normal or contingency system
operations.
2/8/2005
3/16/2007
1. Any eligible customer (or its designated agent) that can
or does execute a transmission service agreement or can
or does receive transmission service.
[Archive]
Transmission
Customer
Definition
[Archive]
2. Any of the following responsible entities: Generator
Owner, Load-Serving Entity, or Purchasing-Selling Entity.
Transmission Line
2/7/2006
3/16/2007
A system of structures, wires, insulators and associated
hardware that carry electric energy from one point to
another in an electric power system. Lines are operated at
relatively high voltages varying from 69 kV up to 765 kV,
and are capable of transmitting large quantities of electricity
over long distances.
2/8/2005
3/16/2007
The entity responsible for the reliability of its “local”
transmission system, and that operates or directs the
operations of the transmission facilities.
08/22/2008
11/24/2009
The collection of Transmission assets over which the
Transmission Operator is responsible for operating.
2/8/2005
3/16/2007
The entity that owns and maintains transmission facilities.
2/8/2005
3/16/2007
The entity that develops a long-term (generally one year
and beyond) plan for the reliability (adequacy) of the
interconnected bulk electric transmission systems within its
portion of the Planning Authority Area.
[Archive]
Transmission Operator
[Archive]
Transmission Operator
Area
[Archive]
Transmission Owner
[Archive]
Transmission Planner
[Archive]
August 4, 2011
Page 45 of 55
ATTACHMENT D
to Order G-162-11
Page 46 of 55
Glossary of Terms Used in NERC Reliability Standards
Continent-wide
Term
Transmission
Reliability Margin
Acronym
BOT
Approved
Date
FERC
Approved
Date
TRM
2/8/2005
3/16/2007
The amount of transmission transfer capability necessary to
provide reasonable assurance that the interconnected
transmission network will be secure. TRM accounts for the
inherent uncertainty in system conditions and the need for
operating flexibility to ensure reliable system operation as
system conditions change.
TRMID
08/22/2008
11/24/2009
A document that describes the implementation of a
Transmission Reliability Margin methodology, and provides
information related to a Transmission Operator’s calculation
of TRM.
2/8/2005
3/16/2007
Services provided to the Transmission Customer by the
Transmission Service Provider to move energy from a Point
of Receipt to a Point of Delivery.
2/8/2005
3/16/2007
The entity that administers the transmission tariff and
provides Transmission Service to Transmission Customers
under applicable transmission service agreements.
2/7/2006
3/16/2007
All plant material, growing or not, living or dead.
2/7/2006
3/16/2007
The systematic examination of a transmission corridor to
document vegetation conditions.
2/8/2005
3/16/2007
The entire Reliability Coordinator Area as well as the critical
flow and status information from adjacent Reliability
Coordinator Areas as determined by detailed system studies
to allow the calculation of Interconnected Reliability
Operating Limits.
[Archive]
Transmission
Reliability Margin
Implementation
Document
Definition
[Archive]
Transmission Service
[Archive]
Transmission Service
Provider
[Archive]
Vegetation
[Archive]
Vegetation Inspection
[Archive]
Wide Area
[Archive]
August 4, 2011
Page 46 of 55
ATTACHMENT D
to Order G-162-11
Page 47 of 55
Glossary of Terms Used in NERC Reliability Standards
Continent-wide
Term
Year One
[Archive]
August 4, 2011
Acronym
BOT
Approved
Date
1/24/2011
FERC
Approved
Date
Definition
The first twelve month period that a Planning Coordinator or
a Transmission Planner is responsible for assessing. For an
assessment started in a given calendar year, Year One
includes the forecasted peak Load period for one of the
following two calendar years. For example, if a Planning
Assessment was started in 2011, then Year One includes
the forecasted peak Load period for either 2012 or 2013.
Page 47 of 55
ATTACHMENT D
to Order G-162-11
Page 48 of 55
Glossary of Terms Used in NERC Reliability Standards
ReliabilityFirst Regional Definitions
The following definitions were developed for use in ReliabilityFirst Regional Standards.
RFC Regional
Term
Resource Adequacy
Acronym
BOT
Approved
Date
FERC
Approved
Date
08/05/2009
03/17/2011
The ability of supply-side and demand-side resources to meet
the aggregate electrical demand (including losses)
08/05/2009
03/17/2011
Total of all end-use customer demand and electric system
losses within specified metered boundaries, less Direct Control
Management and Interruptible Demand
08/05/2009
03/17/2011
A period consisting of two (2) or more calendar months but
less than seven (7) calendar months, which includes the
period during which the responsible entity’s annual peak
demand is expected to occur
08/05/2009
03/17/2011
The planning year that begins with the upcoming annual Peak
Period
[Archive]
Net Internal
Demand
[Archive]
Peak Period
[Archive]
Year One
[Archive]
August 4, 2011
Definition
Page 48 of 55
ATTACHMENT D
to Order G-162-11
Page 49 of 55
Glossary of Terms Used in NERC Reliability Standards
NPCC Regional Definitions
The following definitions were developed for use in NPCC Regional Standards.
NPCC Regional
Term
Current Zero Time
Acronym
BOT
Approved
Date
[Archive]
August 4, 2011
Definition
11/04/2010
The time of the final current zero on the last phase to
interrupt.
11/04/2010
One or more generators at a single physical location whereby
any single contingency can affect all the generators at that
location.
[Archive]
Generating Plant
FERC
Approved
Date
Page 49 of 55
ATTACHMENT D
to Order G-162-11
Page 50 of 55
Glossary of Terms Used in NERC Reliability Standards
WECC Regional Definitions
The following definitions were developed for use in WECC Regional Standards.
WECC Regional
Term
Area Control Error †
Acronym
BOT
Approved
Date
FERC
Approved
Date
Definition
ACE
3/12/2007
6/8/2007
Means the instantaneous difference between net actual and
scheduled interchange, taking into account the effects of
Frequency Bias including correction for meter error.
AGC
3/12/2007
6/8/2007
Means equipment that automatically adjusts a Control Area’s
generation from a central location to maintain its interchange
schedule plus Frequency Bias.
3/26/2008
5/21/2009
A frequency control automatic action that a Balancing Authority
uses to offset its frequency contribution to support the
Interconnection’s scheduled frequency.
Average
Generation†
[Archive]
3/12/2007
6/8/2007
Means the total MWh generated within the Balancing Authority
Operator’s Balancing Authority Area during the prior year
divided by 8760 hours (8784 hours if the prior year had 366
days).
Business Day†
3/12/2007
6/8/2007
Means any day other than Saturday, Sunday, or a legal public
holiday as designated in section 6103 of title 5, U.S. Code.
3/12/2007
6/8/2007
Means (i) any perturbation to the electric system, or (ii) the
unexpected change in ACE that is caused by the sudden loss of
generation or interruption of load.
[Archive]
Automatic
Generation Control†
[Archive]
Automatic Time
Error Correction
[Archive]
[Archive]
Disturbance†
[Archive]
August 4, 2011
Page 50 of 55
ATTACHMENT D
to Order G-162-11
Page 51 of 55
Glossary of Terms Used in NERC Reliability Standards
WECC Regional
Term
Extraordinary
Contingency†
Acronym
BOT
Approved
Date
3/12/2007
FERC
Approved
Date
6/8/2007
[Archive]
Definition
Shall have the meaning set out in Excuse of Performance,
section B.4.c.
language in section B.4.c:
means any act of God, actions by a non-affiliated third party,
labor disturbance, act of the public enemy, war, insurrection,
riot, fire, storm or flood, earthquake, explosion, accident to or
breakage, failure or malfunction of machinery or equipment, or
any other cause beyond the Reliability Entity’s reasonable
control; provided that prudent industry standards (e.g.
maintenance, design, operation) have been employed; and
provided further that no act or cause shall be considered an
Extraordinary Contingency if such act or cause results in any
contingency contemplated in any WECC Reliability Standard
(e.g., the “Most Severe Single Contingency” as defined in the
WECC Reliability Criteria or any lesser contingency).
Frequency Bias†
3/12/2007
6/8/2007
Means a value, usually given in megawatts per 0.1 Hertz,
associated with a Control Area that relates the difference
between scheduled and actual frequency to the amount of
generation required to correct the difference.
3/12/2007
6/8/2007
Means the MVA nameplate rating of a generator.
3/12/2007
6/8/2007
Means that Operating Reserve not connected to the system but
capable of serving demand within a specified time, or
interruptible load that can be removed from the system in a
specified time.
3/12/2007
6/8/2007
Is the maximum path rating in MW that has been demonstrated
to WECC through study results or actual operation, whichever
is greater. For a path with transfer capability limits that vary
seasonally, it is the maximum of all the seasonal values.
[Archive]
Generating Unit
Capability†
[Archive]
Non-spinning
Reserve†
[Archive]
Normal Path
Rating†
[Archive]
August 4, 2011
Page 51 of 55
ATTACHMENT D
to Order G-162-11
Page 52 of 55
Glossary of Terms Used in NERC Reliability Standards
WECC Regional
Term
Acronym
Operating Reserve†
BOT
Approved
Date
FERC
Approved
Date
3/12/2007
6/8/2007
Means that capability above firm system demand required to
provide for regulation, load-forecasting error, equipment forced
and scheduled outages and local area protection. Operating
Reserve consists of Spinning Reserve and Nonspinning
Reserve.
3/12/2007
6/8/2007
Means the maximum value of the most critical system
operating parameter(s) which meets: (a) precontingency
criteria as determined by equipment loading capability and
acceptable voltage conditions, (b) transient criteria as
determined by equipment loading capability and acceptable
voltage conditions, (c) transient performance criteria, and (d)
post-contingency loading and voltage criteria.
3/26/2008
5/21/2009
The component of area (n) inadvertent interchange caused by
the regulating deficiencies of the area (n).
3/26/2008
5/21/2009
The component of area (n) inadvertent interchange caused by
the regulating deficiencies of area (i).
3/12/2007
6/8/2007
Means unloaded generation which is synchronized and ready to
serve additional demand. It consists of Regulating reserve and
Contingency reserve (as each are described in Sections B.a.i
and ii).
3/12/2007
6/8/2007
Means the table maintained by the WECC identifying those
transfer paths monitored by the WECC regional Reliability
coordinators. As of the date set out therein, the transmission
paths identified in Table 2 are as listed in Attachment A to this
Standard.
[Archive]
Operating Transfer
Capability Limit†
OTC
[Archive]
Primary
Inadvertent
Interchange
Definition
[Archive]
Secondary
Inadvertent
Interchange
[Archive]
Spinning Reserve†
[Archive]
WECC Table 2†
[Archive]
August 4, 2011
Page 52 of 55
ATTACHMENT D
to Order G-162-11
Page 53 of 55
Glossary of Terms Used in NERC Reliability Standards
WECC Regional
Term
Functionally
Equivalent
Protection System
Acronym
FEPS
BOT
Approved
Date
FERC
Approved
Date
10/29/2008
4/21/2011
Definition
A Protection System that provides performance as follows:
• Each Protection System can detect the same faults within the
zone of protection and provide the clearing times and
coordination needed to comply with all Reliability Standards.
[Archive]
• Each Protection System may have different components and
operating characteristics.
Functionally
Equivalent RAS
FERAS
10/29/2008
4/21/2011
A Remedial Action Scheme (“RAS”) that provides the same
performance as follows:
• Each RAS can detect the same conditions and provide
mitigation to comply with all Reliability Standards.
[Archive]
• Each RAS may have different components and operating
characteristics.
Security-Based
Misoperation
10/29/2008
4/21/2011
A Misoperation caused by the incorrect operation of a
Protection System or RAS. Security is a component of reliability
and is the measure of a device’s certainty not to operate
falsely.
10/29/2008
4/21/2011
Is the absence of a Protection System or RAS operation when
intended. Dependability is a component of reliability and is the
measure of a device’s certainty to operate when required.
10/29/2008
4/21/2011
Achievement of this designation indicates that the
[Archive]
DependabilityBased Misoperation
[Archive]
Commercial
Operation
Generator Operator or Transmission Operator of the
synchronous generator or synchronous condenser has received
all approvals necessary for operation after completion of initial
start-up testing.
[Archive]
Qualified Transfer
Path Curtailment
Event
[Archive]
August 4, 2011
2/10/2009
3/17/2011
Each hour that a Transmission Operator calls for Step 4 or
higher for one or more consecutive hours (See Attachment 1
IRO-006-WECC-1) during which the curtailment tool is
functional.
Page 53 of 55
ATTACHMENT D
to Order G-162-11
Page 54 of 55
Glossary of Terms Used in NERC Reliability Standards
WECC Regional
Term
Acronym
Relief Requirement
BOT
Approved
Date
FERC
Approved
Date
2/10/2009
3/17/2011
The expected amount of the unscheduled flow reduction on the
Qualified Transfer Path that would result by curtailing each Sink
Balancing Authority’s Contributing Schedules by the
percentages listed in the columns of WECC Unscheduled Flow
Mitigation Summary of Actions Table in Attachment 1 WECC
IRO-006-WECC-1.
2/10/2009
3/17/2011
The percentage of USF that flows across a Qualified Transfer
Path when an Interchange Transaction (Contributing Schedule)
is implemented. [See the WECC Unscheduled Flow Mitigation
Summary of Actions Table (Attachment 1 WECC IRO-006WECC-1).]
2/10/2009
3/17/2011
A Schedule not on the Qualified Transfer Path between a
Source Balancing Authority and a Sink Balancing Authority that
contributes unscheduled flow across the Qualified Transfer
Path.
2/10/2009
3/17/2011
A transfer path designated by the WECC Operating Committee
as being qualified for WECC unscheduled flow mitigation.
2/10/2009
3/17/2011
A controllable device installed in the Interconnection for
controlling energy flow and the WECC Operating Committee
has approved using the device for controlling the USF on the
Qualified Transfer Paths.
[Archive]
Transfer
Distribution Factor
TDF
[Archive]
Contributing
Schedule
[Archive]
Qualified Transfer
Path
Definition
[Archive]
Qualified
Controllable Device
[Archive]
August 4, 2011
Page 54 of 55
ATTACHMENT D
to Order G-162-11
Page 55 of 55
Glossary of Terms Used in NERC Reliability Standards
Endnotes
†
FERC approved the WECC Tier One Reliability Standards in the Order Approving Regional Reliability Standards for the Western Interconnection and
Directing Modifications, 119 FERC ¶ 61,260 (June 8, 2007). In that Order, FERC directed WECC to address the inconsistencies between the regional
definitions and the NERC Glossary in developing permanent replacement standards. The replacement standards designed to address the shortcomings were
filed with FERC in 2009.
August 4, 2011
Page 55 of 55