VANCOUVER, BC CANADA V6Z TELEPHONE: BC TOLL FREE ... · Project No. 3698595/R‐72‐12 ......

ERICA HAMILTON COMMISSION SECRETARY

[email protected] web site: http://www.bcuc.com

SIXTH FLOOR, 900 HOWE STREET, BOX 250 VANCOUVER, BC CANADA V6Z 2N3

TELEPHONE: (604) 660‐4700 BC TOLL FREE: 1‐800‐663‐1385 FACSIMILE: (604) 660‐1102

Log No. 41453

PF/BCUC/MRS/A2‐11_Order G‐162‐11_Assessment Report No 3 by BCH

VIA EMAIL October 29, 2012 BCUC INQUIRY INTO THE

BC MRS PROGRAM EXHIBIT A2‐11 To: All Registered Parties (BCUC – MRS Inquiry)

Re: British Columbia Utilities Commission Project No. 3698595/R‐72‐12

An Inquiry into potential adjustments for the British Columbia Mandatory Reliability Standards Program

Commission staff submits the following document for the record in this proceeding:

British Columbia Utilities Commission Order G‐162‐11

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 Yours truly, Erica Hamilton /sk Enclosure

SIXTH FLOOR, 900 HOWE STREET, BOX 250 VANCOUVER, BC V6Z 2N3 CANADA web site: http://www.bcuc.com

BRIT I SH COLUMBIA

UTIL I T I ES COMMISS ION ORDER NUMBER G‐162‐11

TELEPHONE: (604) 660‐4700 BC TOLL FREE: 1‐800‐663‐1385 FACSIMILE: (604) 660‐1102

…/2

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

BEFORE: 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;

skhaira

A2-11

2

.../3

BRIT I SH COLUMBIA

UTIL IT I ES COMMISS ION 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.

BRITISH COLUMBIA

UTILITIES COMMISSION

3

ORDER

NUMBER G-162-11

DATED at the City of Vancouver, in the Province of British Columbia, this

9. The Commission directs that individual requirements within reliability standards that incorporate by referencereliability 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 inBritish Columbia, that accompany each of the adopted British Columbia reliability standards, in the form directed bythe 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 tothis Order are the reliability standards adopted in British Columbia as of the date of this Order.

;;...(.,

/ day of October 2011.

;;:~ "-.-/'....-- '--" ,,"'----L.F. KelseyCommissioner

Attachments

Order/G-162-11_MRS Assessment Report #3-Revised Standards

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 BCUC Order Adopting

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‐003‐1 Cyber Security – Security Management Controls G‐67‐09

CIP‐003‐2 Cyber Security – Security management Controls G‐67‐09

CIP‐003‐3 Cyber Security – Security Management Controls G‐162‐11

CIP‐004‐1 Cyber Security – Personnel and Training G‐67‐09



CIP‐005‐1 Cyber Security – Electronic Security Perimeter(s) G‐67‐09



CIP‐006‐1 Cyber Security – Physical Security of Critical Cyber Assets G‐67‐09

CIP‐006‐2c Cyber Security – Physical Security of Critical Cyber Assets G‐67‐09

CIP‐006‐3c Cyber Security – Physical Security of Critical Cyber Assets G‐162‐11

CIP‐007‐1 Cyber Security – Systems Security Management G‐67‐09

CIP‐007‐2a Cyber Security – Systems Security Management G‐67‐09

CIP‐007‐3 Cyber Security – Systems Security Management G‐162‐11

CIP‐008‐1 Cyber Security – Incident Reporting and Response Planning

G‐67‐09


G‐67‐09


G‐162‐11

CIP‐009‐1 Cyber Security – Recovery Plans for Critical Cyber Assets G‐67‐09



COM‐001‐1.1 Telecommunications G‐167‐10

COM‐002‐2 Communication and Coordination G‐67‐09


Page 2 of 5


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

FAC‐010‐2 System Operating Limits Methodology for the Planning Horizon

G‐167‐10

FAC‐010‐2.1 System Operating Limits Methodology for the Planning Horizon

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 Interchange Authority Distributes Arranged Interchange G‐67‐09

INT‐005‐3 Interchange Authority Distributes Arranged Interchange G‐162‐11

INT‐006‐2 Response to Interchange Authority G‐67‐09

INT‐006‐3 Response to Interchange Authority G‐162‐11

INT‐007‐1 Interchange Confirmation G‐67‐09

INT‐008‐2 Interchange Authority Distributes Status G‐67‐09

INT‐008‐3 Interchange Authority Distributes Status 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 Reliability Coordination‐Transmission Loading Relief G‐67‐09

IRO‐006‐4.1 Reliability Coordination – Transmission Loading Relief G‐162‐11


Page 3 of 5


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

G‐67‐09

MOD‐021‐0.1 Documentation of the Accounting Methodology for the Effects of Demand‐Side Management in Demand and Energy Forecasts

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 Operating Personnel Responsibility and Authority G‐67‐09

PER‐001‐0.1 Operating Personnel Responsibility and Authority 2009/06/08

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


Page 4 of 5


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 MisoperationScheme

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 Normal Operations Planning G‐67‐09

TOP‐002‐2a Normal Operations Planning 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)

G‐67‐09

TPL‐002‐0a System Performance Following Loss of a Single Bulk Electric System Element (Category B)

G‐162‐11

TPL‐003‐0 System Performance Following Loss of a Single Bulk Electric System Element (Category C)

G‐67‐09

TPL‐003‐0a System Performance Following Loss of a Single Bulk Electric System Element (Category C)

G‐162‐11


Page 5 of 5


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

VAR‐002‐1.1a Generator Operation for Maintaining Network Voltage Schedules

G‐167‐10

VAR‐002‐1.1b Generator Operation for Maintaining Network Voltage Schedules

G‐162‐11

VAR‐STD‐002a‐1 Automatic Voltage Regulators G‐67‐09

VAR‐STD‐002b‐1 Power System Stabilizer G‐67‐09

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:

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.

5. *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 1 of 143


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 inter-utility 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:

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.

R4. 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




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-002-3 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.

1.4.2 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.





Version History

Version Date Action Change Tracking 1 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 Update


Standard CIP–003–3 — Cyber Security — Security Management Controls

A. Introduction 1. Title: Cyber Security — Security Management Controls


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:











4.1.10 NERC.





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 CIP-003-3 Requirement R2.

5. *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.




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 CIP-002-3, 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.




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 vendor-related 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.





Not applicable.


Compliance Audits

Self-Certifications

Spot Checking


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.



1.5.1 None



Version History

Version Date Action Change Tracking 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 Update


Standard CIP–004–3 — Cyber Security — Personnel and Training


A. Introduction 1. Title: Cyber Security — Personnel & Training


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:











4.1.10 NERC.





4.2.3 Responsible Entities that, in compliance with Standard CIP-002-3, identify that they have no Critical Cyber Assets.


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.);




• 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:

R2.2.1. 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.

R2.3. 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 seven-year 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.




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.





Not Applicable.


Compliance Audits

Self-Certifications

Spot Checking


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.




E. Regional Variances




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 Update


Standard CIP–005–3 — Cyber Security — Electronic Security Perimeter(s)


A. Introduction 1. Title: Cyber Security — Electronic Security Perimeter(s)


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











4.1.10 NERC.

4.1.11 Regional Entity





5. *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.




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 CIP-003-3; 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:

R2.5.1. 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.

R2.6. 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.




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-005-3.

R5.1. The Responsible Entity shall ensure that all documentation required by Standard CIP-005-3 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.








Not applicable.


Compliance Audits

Self-Certifications

Spot Checking


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.





Version History

Version Date Action Change Tracking 1 01/16/06 D.2.3.1 — Change “Critical Assets,” to “Critical Cyber Assets”

as intended. 03/24/06

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. 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




Authority.

3 Update version from -2 to -3



Standard CIP-006-3c — Cyber Security — Physical Security

* Mandatory BC effective date October 16, 2011 * per BCUC Order G-162-11 1

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:


4.1.1 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





4.2.3 Responsible Entities that, in compliance with Standard CIP-002-3, identify that they have no Critical Cyber Assets


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.




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.

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.

R2. 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 CIP-004-3 Requirement R3; Standard CIP-005-3 Requirements R2 and R3; Standard CIP-006-3 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:

• 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.

R5. 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




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:

• 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.

R6. 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.




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.





Not applicable.


Compliance Audits

Self-Certifications

Spot Checking


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.



1.5.1 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.

2. Violation Severity Levels (Under development by the CIP VSL Drafting Team)





Version History

Version Date Action Change Tracking 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.

11/18/2009 Updated Requirements R1.6.1 and R1.6.2 to be responsive to FERC Order RD09-7


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)



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.


1.4.4 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.




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.





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.


Standard CIP–007–3 — Cyber Security — Systems Security Management


A. Introduction 1. Title: Cyber Security — Systems Security Management


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:











4.1.10 NERC.







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.




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.

R2. 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.

R3. 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.

R4. 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.

R5. 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.




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 CIP-008-3.

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.




R7. 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.

R8. 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. A document identifying the vulnerability assessment process; R8.2. 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. A review of controls for default accounts; and, R8.4. 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.

R9. 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.








Not applicable.


Compliance Audits

Self-Certifications

Spot Checking


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.


1.5. Additional Compliance Information.



Version History


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 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)




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 Updated version numbers from -2 to -3

3 12/16/09 Approved by the NERC Board of Trustees


Standard CIP–008–3 — Cyber Security — Incident Reporting and Response Planning


A. Introduction 1. Title: Cyber Security — Incident Reporting and Response Planning


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 CIP-009-3.

4. Applicability











4.1.10 NERC.







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.




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.

R2. 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.





Not applicable.


Compliance Audits

Self-Certifications

Spot Checking


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.






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.



Version History


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.



Standard CIP–009–3 — Cyber Security — Recovery Plans for Critical Cyber Assets


A. Introduction 1. Title: Cyber Security — Recovery Plans for Critical Cyber Assets


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:


4.1.1 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







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.




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.





Not applicable.


Compliance Audits

Self-Certifications

Spot Checking


Self-Reporting

Complaints

1.4. Data Retention

1.4.1 The Responsible Entity shall keep documentation required by Standard CIP-009-3 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.








Version History


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



Standard FAC-010-2.1 — System Operating Limits Methodology for the Planning Horizon

Adopted by Board of Trustees: November 5, 2009 Page 1 of 9 Effective Date: April 19, 2010 * per BCUC Order G-162-11

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. 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.

R2. 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 Contingencies1 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.


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. 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.

R4. 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.

R5. 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.




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.


1.1. Compliance Monitoring Responsibility

Compliance Monitor: British Columbia Utilities Commission

Compliance Monitor’s Administrator: Western Electricity Coordinating Council


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.


The Planning Authority shall make the following available for inspection during an on-site 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.




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: The SOL Methodology was not issued to all required entities in accordance with R4



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 pre-contingency 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 pre-contingency 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 pre-contingency 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




Requirement Lower Moderate High Severe 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.

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.

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.

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





Requirement 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.

R5

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.



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 (non-recallable 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.





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

2 Changed the effective date to July 1, 2008 Changed “Cascading Outage” to “Cascading” Replaced Levels of Non-compliance with Violation Severity Levels

Revised

2 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 FAC-010-2.

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-010-1 to R2.5 and R2.6 in FAC-010-2.

Errata


Standard INT-005-3 — Interchange Authority Distributes Arranged Interchange

Adopted by NERC Board of Trustees: October 29, 2008 Page 1 of 6 Effective Date: July 1, 2010 * per BCUC Order G-162-11

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 non-compliance 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.


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.




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.

2. Levels of Non-Compliance

2.1. Level 1: One occurrence1 of not distributing information to all involved reliability entities as described in R1.

2.2. Level 2: Two occurrences1 of not distributing information to all involved reliability entities as described in R1.

2.3. Level 3: Three occurrences1 of not distributing information to all involved reliability entities as described in R1.

2.4. Level 4: Four or more occurrences1 of not distributing information to all involved reliability entities 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

1 This does not include instances of not distributing information due to extenuating circumstances approved by the Compliance Monitor.



Timing Requirements for all Interconnections except WECC

Ramp Start

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

BA Prepares Confirmed Interchange

for Implementation

>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.


< 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


> 3 minutes prior to ramp start

>1 hour to < 4 hours prior to ramp

start



receipt from IA



> 4 hours prior to ramp start


< 2 hours from Arranged Interchange receipt from

IA


> 1 hour 58 minutes prior to ramp start

Interchange Timeline with Minimum Reliability-Related Response Times

Request for Interchange Submitted

2 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 Page 3 of 6 * per BCUC Order G-162-11



Example of Timing Requirements for all Interconnections except WECC




Timing Requirements for WECC A B C D

If Arranged Interchange (RFI)3 is Submitted

IA Assigned Time

Classification





BA Prepares Confirmed Interchange for Implementation

>1 hour after the start time ATF < 1minute from RFI submission


< 1minute from receipt of all Reliability Assessments

NA

<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

< 5 minutes from Arranged Interchange receipt from IA























<1 hour and > 15 minutes prior to ramp start





> 1hour and < 4 hours prior to ramp start


< 20 minutes from Arranged interchange receipt from IA





< 2 hours from Arranged Interchange receipt from IA



Submitted before 10:00 PPT with start time > 00:00 PPT

of following day


By 12:00 PPT of day the Arranged Interchange was

received by the IA








Example of Timing Requirements for WECC


Standard INT-006-3 — Response to Interchange Authority

Adopted by NERC Board of Trustee: October 29, 2008 Page 1 of 7 Effective Date: July 1, 2010 * per BCUC Order G-162-11

A. Introduction 1. Title: Response to Interchange Authority


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.


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.




ed in R1.


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.


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:



1.4.3 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:

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.


2.1. Level 1: One occurrence2 of not responding to the Interchange Authority as describ

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.




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






Ramp Start

A B C D


is Submitted

IA Assigned Time

Classification






for Implementation





NA


start time






ramp start



receipt from IA




start



receipt from IA






IA











IA Assigned Time

Classification









NA


start time














































of following day



received by the IA






Standard INT-008-3 — Interchange Authority Distributes Status


A. Introduction

1. Title: Interchange Authority Distributes Status


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.

R1.1. For Confirmed Interchange, the Interchange Authority shall also communicate:

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.

M1.1 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.

D. Compliance


1.1. Compliance Monitoring Responsibility Compliance Monitor: the British Columbia Utilities Commission






The Performance-Reset Period shall be twelve months from the last non-compliance 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.


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:



1.4.3 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:

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.


2.1. Level 1: One occurrence1 of not distributing final status and information as described in R1.

1 This does not include instances of not distributing information due to extenuating circumstances approved by the Compliance Monitor.




2.2. Level 2: Two occurrences1 of not distributing final status and information as described in R1.

2.3. Level 3: Three occurrences1 of not distributing final status and information as described in R1.

2.4. Level 4: Four or more occurrences1 of not distributing final status and information as described in R1 or no evidence provided.


None.

Version History Version Date Action Change Tracking

1 May 2, 2006 Approved by BOT New






Ramp Start

A B C D


is Submitted

IA Assigned Time

Classification






for Implementation





NA


start time






ramp start



receipt from IA




start



receipt from IA






IA











IA Assigned Time

Classification









NA


start time














































of following day



received by the IA






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

This requirement simply states; the RC has the authority to act, the RC should know at what limits he/she needs to act, the RC has pre-identified regional, interregional and sub-regional TLR procedures.

R1. A Reliability Coordinator experiencing a potential or actual SOL or IROL violation within its Reliability Coordinator Area shall, with its authority and at its discretion, select one or more procedures to provide transmission loading relief. These procedures can be a “local” (regional, interregional, or sub-regional) transmission loading relief procedure or one of the following Interconnection-wide procedures: [Violation Risk Factor: Medium] [Time Horizon: Real-time Operations]

Comment: see FERC Order 693 paragraph 964 regarding recommendation for using tools other than TLR to mitigate an actual IROL.

R1.1. The Interconnection-wide Transmission Loading Relief (TLR) procedure for use in the Eastern Interconnection provided in Attachment 1-IRO-006-4. The TLR procedure alone is an inappropriate and ineffective tool to mitigate an 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_2001-clean_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 Page 1 of 35 Effective Date: December 10, 2009 * per BCUC Order G-162-11


http://www.wecc.biz/documents/library/UFAS/UFAS_mitigation_plan_rev_2001-clean_8-8-03.pdf








http://www.ercot.com/mktrules/protocols/current.html





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).



Compliance Monitor: the British Columbia Utilities Commission



Compliance Monitoring Period: One calendar year.

Reset Period: One month without a violation.

1.3. Data Retention




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.


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:

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.

2. 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).




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.

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.

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 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



ftp://www.nerc.com/pub/sys/all_updl/standards/sar/Waver_Enhanced_Congestion_Management.pdf





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




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-IRO-006-1 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

Transaction that has been curtailed or halted by TLR to reload to the lesser of its current-hour MW amount or next-hour schedule in accordance with its energy profile.

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.

S3 To allow a flowing Transaction to increase from its current-hour schedule to its next-hour schedule in accordance with its energy profile.

The MW amounts used in this sub-priority is determined by the e-tag ENERGY PROFILE table. If the calculated amount is negative, zero is used instead.




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 sub-priority (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





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



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. The flexibility for ISOs and RTOs to use redispatch is contained explicitly in the NAESB business practice Section 1.3.

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. 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.

This notification is automated in the Interchange Distribution Calculator (IDC) and populates a message on the NERC RCIS.

1.4. Notification of TLR Procedure implementation. The Reliability Coordinator initiating the use of the TLR Procedure shall notify other Reliability 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.




Actions expected. The Reliability Coordinator initiating the TLR Procedure shall indicate the actions expected to be taken by other Reliability Coordinators.

This notification is automated in the Interchange Distribution Calculator (IDC) and populates a message on the NERC RCIS.

1.4.2. Notifying Transmission Operators and Balancing Authorities. The Reliability Coordinator shall notify Transmission Operators and Balancing Authorities in its Reliability Area when entering 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.

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 of questionable IDC results may include: cts of questionable IDC results may include:




• 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.

Creation and distribution of the TLR Procedure Log is now automated in the IDC.

The Market Committee no longer exists and this requirement will be removed in Phase 3.

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.

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 Committee may conduct reviews of certain TLR events based on the size and number of Interchange Transactions that are affected, the 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.”




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-to-Point 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. The Reliability Coordinator shall use the following circumstances to establish the need for TLR Level 1:

• 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.

2.1.2. 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.

2.2. TLR Level 2 — Hold transfers at present level to prevent SOL or IROL Violations

2.2.1. The Reliability Coordinator shall use the following circumstances to establish the need for entering TLR Level 2:


• One or more transmission facilities are expected to approach, or are approaching, or are at their SOL or IROL.

2.3 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:


• 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.




• The Transmission Provider has previously approved a higher priority Point-to-Point Transmission Service reservation over which a Transmission Customer wishes to begin an Interchange Transaction.

2.4. TLR Level 3b — Curtail Interchange Transactions using Non-Firm Transmission Service Arrangements to mitigate a SOL or IROL Violation

2.4.1. 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.

2.5 TLR Level 4 — Reconfigure Transmission

2.5.1. 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.

2.5.2. 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.

2.6. 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:


• 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.




• No further transmission reconfiguration is possible or effective.

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. 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


• 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. formerly NERC

section 3.3 2.8. Curtailment of Interchange Transactions Using Firm Transmission Service

2.8.1. 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 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.


2.9.2 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.

2.10 TLR Level 0 — TLR concluded




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

3.2.2 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.

3.3 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)




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.




Appendix A. Transaction Management and Curtailment Process

This flowchart depicts an overview of the Transaction Management and Curtailment process. Detailed decisions are not shown.

SystemSecure OSL Violation

MonitorSystem

Security LimitViolation? TLR 3b

PotentialSLV?

CurtailmentMethod:

NERC TLRTLR 1 Local

Requestfor Transmission

Service?

StillConstrained? IDC

Curtail Non-Firm Priorities 1-6Accommodate?

StillConstrained?TLR 2

HoldTLR 4

Reconfigure

CanReconfigure?Request for Higher Priority

Service

StillConstrained?

TLR 5b Calc TCF

Curtail Firm

TLR 3a Curtail Non-firm Accommodate?

TLR 4 Reconfigure

Accommodate?

TakeEmergency

Action

No

Yes

Yes

No

No

Yes

Yes

No

Yes

No

Yes

No

No

Yes

No

Yes

Yes

No

No

Yes

TLR 5a TCF

Curtail Firm




Appendix C. Sample NERC Transmission Loading Relief Procedure Log

SAVE FILE DIRECTORY:

NERC TRANSMISSION LOADING RELIEF (TLR) PROCEDURE LOG FILE SAVED AS: .XLS

INCIDENT : DATE: IMPACTED RELIABILITY COORDINATOR : ID NO:

I N I T I A L C O N D I T I O N S

Limiting Flowgate (LIMIT) Rating Contingent Flowgate (CONT.) ODF

TLR Levels PrioritiesNX Next Hour Market Service

0: TLR Incident Canceled NS Service over secondary receipt and delivery points1. Notify Reliability Coordinators of potential problems. NH Hourly Service2: Halt additional transactions that contribute to the overload ND Daily Service3a and 3b: Curtail transactions using Non-firm Transmission Service NW Weekly Service4. Reconfigure to continue firm transactions if needed. NM Monthly Service5a and 5b: Curtail Transactions using Firm Transmission Service. NN Non-firm imports for native load and network customers from 6: Implement emergency procedures. non-designated network resources

F Firm ServiceT L R A C T I O N S

TLR 3,5TLR 3,5LEVEL TIME Priority No. TX MW Cont. Elem't C O M M E N T S A B O U T A C T I O N S

Curtail Curtail Present Post Cont. Present

MW FlowLimiting Element


























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 next-hour 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.




Transactions with E-tags submitted to Tag Authority after TLR 2 or higher was declared (post-tagged) 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.




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.




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 Coordinator may declare a TLR Level 3a or 5a at any time during the course of an hour. However, if a TLR Level 3a 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 distributed to the other Reliability Coordinators or the market. Instead, the issuing Reliability Coordinator will be reminded by an IDC alarm at 00:25 to generate a new Reallocation/Reloading report that will include all tags submitted prior to the approved tag submission deadline for Reallocation.

IDC results priorto 00:25 and01:25 arenot distributed

01:00 02:00:25 :25

00:00Figure 5 - IDC report may be run prior to 00:25, but results are not distributed.

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




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-to-Point 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



950 MW


50 MW



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



950 MW


-200 MW



750 MW – 800 MW = -50 MW None are held




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




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 sub-priority setting for an Interchange Transaction under different circumstances of current-hour and next-hour schedules and active MW flowing as modified by tag adjust table in E-Tag.




Example 1 – Transaction curtailed, next-hour Energy Profile is higher

Energy Profile: Current hour 20 MW

Actual flow following curtailment: Current hour 10 MW

Energy Profile: Next hour 40 MW

MW

TLR

Time

10

20

40S3

S2

S1

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




Example 2 – Transaction curtailed, next-hour Energy Profile is lower


Actual flow following curtailment: Current hour 10 MW


MW

Time

10

20

40

S2

S1

TLR



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




Example 3 – Transaction not curtailed, next-hour Energy Profile is higher


Actual flow following curtailment: Current hour

20 MW (no curtailment)


MW

Time

10

20

40


S1 20 MW Maintain current flow (not curtailed)


S3 +20 MW Next-hour Energy Profile is 40MW

S4

S3

S1

TLR




Example 4 – Transaction not curtailed, next-hour Energy Profile is lower


Actual flow following curtailment: Current hour 40 MW (no curtailment)


MW

Time

10

20

40

S1

TLR



S1 20 MW Reduce flow to next-hour Energy Profile (20MW)



S4




Example 5 — TLR Issued before Transaction was scheduled to start


Actual flow following curtailment: Current hour 0 MW (Transaction scheduled to start after TLR initiated)


MW

Time

10

20

40

S3

Tag TLR


S1 0 MW Transaction was not allowed to start

S2 +0 MW Transaction was not allowed to start


S4 +0 Tag submitted prior to TLR




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 Point-to-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.

00:00 01:00

Beginning ofNext Hour

00:2000:10 00:30 00:40 00:50

00:25

Beginning ofCurrent Hour

Firm Transactionsmust be submittedto IDC by 00:25 to

start as scheduled

TLR 3b

IDC issues CongestionManagement Reportbased on time of callingTLR 3b. ADJUST Listfollows.

IDC checks foradditional approvedFirm Transactions.CongestionManagement Reportand second ADJUSTList issued if needed.

TLR 3a

Firm Transactionsthat were held areallowed to start at

02:00

FirmTransactions in

IDC by 00:25allowed to startas scheduled.

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.




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.

00:00 01:00


00:2000:10 00:30 00:40 00:50

00:25


Firm Transactionsmust be submitted

to IDC by start ofTLR 3b to start

TLR 3b

IDC issuesCongestion

ManagementReport based on

time of callingTLR 3b. ADJUST

List follows.

Firm Transactionsthat are in the IDCby start of TLR 3b

are started asscheduled

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).




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.

00:00 01:00


00:2000:10 00:30 00:40 00:50

00:25


TLR 3b

IDC issuesCongestion

ManagementReport based on

time of callingTLR 3b. ADJUST

List follows.

Firm Transactionsthat are in IDC by00:25 may start as

scheduled


start as scheduled

TLR 2 or higher

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.




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.

00:00 01:00Beginning of

Next Hour

00:2000:10 00:30 00:40 00:50

00:25



start as scheduled

Non-firmTransactions are

Reallocated at01:00.

TLR 3b

IDC issuesCongestionManagementReport based ontime of calling TLR3b. ADJUST Listfollows.


TLR 3a

FirmTransactions are

started asscheduled

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.




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.

00:00 01:00


00:2000:10 00:30 00:40 00:50

00:25



start as scheduled

TLR 3b

IDC issuesCongestionManagementReport based ontime of callingTLR 3b. ADJUSTList follows.


TLR 1

FirmTransactions are

started asscheduled. Non-

firmTransactions

may be loaded.

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.



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: MOD-021-0.1

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:

4.1. Load-Serving Entity

4.2. Transmission Planner

4.3. Resource Planner


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, time-of-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).





Adopted by NERC Board of Trustees: April 15, 2009 1 of 2 Effective Date: December 10, 2009 * per BCUC Order G-162-11


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.


None.


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.


2.4. 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


0.1 April 15, 2009 R1. – comma inserted after Load-Serving Entity

0.1 December 10, 2009 Approved by FERC — Added effective date Update


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.


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 real-time 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.


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.



Standard PER-001-0.1 — Operating Personnel Responsibility and Authority



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.


One calendar year.

1.3. Data Retention

Permanent.



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



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


Approved by Board of Trustees: February 12, 2008 * per BCUC Order G‐162‐11 1

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 non- compliance 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.



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 sending- end 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.



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.




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






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.



The Compliance Monitor shall retain its compliance documentation for three years.


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.





2. Violation Severity Levels:

Requirement Lower Moderate High Severe

R1 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.

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.





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


http://www.nerc.com/%7Efilez/reports.html





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.


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 Page 1 of 7 Approved by FERC: December 2, 2009 * per BCUC Order G-162-11



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 Page 2 of 7 Approved by FERC: December 2, 2009 * per BCUC Order G-162-11



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)








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 non-compliance.

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





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.



2.4. Level 4: There shall be a separate Level 4 non-compliance, for every one of the following requirements that is in violation:

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.

3. Levels of Non-Compliance for Transmission Operators



3.3. Level 3: One or more of Bulk Electric System studies were not made available as specified in R11.


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.

4. Levels of Non-Compliance for Generator Operators:





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.

5. Levels of Non-Compliance for Transmission Service Providers and Load-serving Entities:










Version History



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



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-002-2 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.



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:




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 (non-recallable 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 Page 1 of 8 Effective Date: April 23, 2010 * per BCUC Order G-162-11



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.

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.

R2. 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. Review, in subsequent annual assessments, (where sufficient lead time exists), the continuing need for identified system facilities. Detailed implementation plans are not needed.

R3. 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.









Annually.

1.3. Data Retention

None specified.


None.



2.2. Level 2: A valid assessment and corrective plan for the longer-term planning horizon is not available.


2.4. Level 4: A valid assessment and corrective plan for the near-term planning horizon is not available.


Version History


0a October 23, 2008

Added 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

Revised

0a April 23, 2010 FERC approval of interpretation of TPL-002-0 R1.3.2

Interpretation





Table I. Transmission System Standards — Normal and Emergency Conditions

Category Contingencies System Limits or Impacts

Initiating Event(s) and Contingency

Element(s)

System Stable and both

Thermal and Voltage

Limits within Applicable

Rating a

Loss of Demand or

Curtailed Firm Transfers

Cascading Outages

A

No Contingencies

All Facilities in Service

Yes

No

No

B

Event resulting in the loss of a single element.

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

Single Pole Block, Normal Clearinge: 4. Single Pole (dc) Line

Yes

Nob

No

C

Event(s) resulting in the loss of two or more (multiple) elements.

SLG Fault, with Normal Clearinge: 1. Bus Section 2. Breaker (failure or internal Fault)

Yes

Yes

Planned/

Controlledc Planned/

Controlledc

No

No

SLG or 3Ø Fault, with Normal Clearinge, Manual System Adjustments, followed by another SLG or 3Ø Fault, with Normal Clearinge:

3. Category B (B1, B2, B3, or B4) contingency, manual system adjustments, followed by another Category B (B1, B2, B3, or B4) contingency

Yes

Planned/ Controlledc

No

Bipolar Block, with Normal Clearinge: 4. Bipolar (dc) Line Fault (non 3Ø), with

Normal Clearinge: 5. Any two circuits of a multiple circuit

towerlinef

Yes

Yes

Planned/

Controlledc


No

No

SLG Fault, with Delayed Clearinge (stuck breaker or protection system failure):

6. Generator 7. Transformer 8. Transmission Circuit 9. Bus Section

Yes

Yes

Yes

Yes


Planned/

Controlledc

Planned/

Controlledc

Planned/

Controlledc

No

No

No

No



D d

Extreme event resulting in two or more (multiple) elements removed or Cascading out of service

3Ø Fault, with Delayed Clearinge (stuck breaker or protection system failure):

1. Generator 3. Transformer

2. Transmission Circuit 4. Bus Section

3Ø Fault, with Normal Clearinge:

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) 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.

Evaluate for risks and consequences.

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.

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 (non-recallable 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.




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:


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).



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.




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.





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?


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 TPL-002-0 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.


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: TPL-003-0a

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:




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 (non-recallable 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 Page 1 of 8 Effective Date: April 23, 2010 * per BCUC Order G-162-11



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.

R1.4. Address any planned upgrades needed to meet the performance requirements of Category C.

R1.5. Consider all contingencies applicable to Category C.

R2. 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. Review, in subsequent annual assessments, (where sufficient lead time exists), the continuing need for identified system facilities. Detailed implementation plans are not needed.

R3. 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.









Annually.

1.3. Data Retention

None specified.


None.



2.2. Level 2: A valid assessment and corrective plan for the longer-term planning horizon is not available.


2.4. Level 4: A valid assessment and corrective plan for the near-term planning horizon is not available.


Version History


0 April 1, 2005 Add parenthesis to item “e” on page 8. Errata

0a October 23, 2008 Added 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

Revised

0a April 23, 2010 FERC approval of interpretation of TPL-003-0 R1.3.12

Interpretation





Table I. Transmission System Standards – Normal and Emergency Conditions

Category Contingencies System Limits or Impacts

Initiating Event(s) and Contingency

Element(s)

System Stable and both

Thermal and Voltage

Limits within Applicable

Rating a

Loss of Demand or

Curtailed Firm Transfers

Cascading c

Outages

A

No Contingencies

All Facilities in Service

Yes

No

No

B

Event resulting in the loss of a single element.

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

Single Pole Block, Normal Clearinge: 4. Single Pole (dc) Line

Yes

Nob

No

C

Event(s) resulting in the loss of two or more (multiple) elements.

SLG Fault, with Normal Clearinge: 1. Bus Section 2. Breaker (failure or internal Fault)

Yes

Yes

Planned/

Controlledc Planned/

Controlledc

No

No

SLG or 3Ø Fault, with Normal Clearinge, Manual System Adjustments, followed by another SLG or 3Ø Fault, with Normal Clearinge:

3. Category B (B1, B2, B3, or B4) contingency, manual system adjustments, followed by another Category B (B1, B2, B3, or B4) contingency

Yes


No

Bipolar Block, with Normal Clearinge: 4. Bipolar (dc) Line Fault (non 3Ø), with

Normal Clearinge: 5. Any two circuits of a multiple circuit

towerlinef

Yes

Yes

Planned/

Controlledc


No

No

SLG Fault, with Delayed Clearinge (stuck breaker or protection system failure):

6. Generator 7. Transformer 8. Transmission Circuit 9. Bus Section

Yes

Yes

Yes

Yes


Planned/

Controlledc

Planned/

Controlledc

Planned/

Controlledc

No

No

No

No



D d

Extreme event resulting in two or more (multiple) elements removed or Cascading out of service

3Ø Fault, with Delayed Clearing e (stuck breaker or protection system failure):

1. Generator 3. Transformer

2. Transmission Circuit 4. Bus Section

3Ø Fault, with Normal Clearinge:

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) 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.

Evaluate for risks and consequences.

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.

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 (non-recallable 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.




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:


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).



TPL-003-0:


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).



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.




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 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.





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?


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 TPL-002-0 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.


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 Ratings1) as directed by the Transmission Operator.

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.

R3. 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.

R4. 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



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.





.


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.




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.


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).


2.2.1 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).


2.3.1 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).


2.4.1 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).

3. 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.





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 non-

compliance 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 VAR-002-1.1a approved by BOT on February 10, 2009

Revised




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:

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.

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.

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?




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.





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.


August 4, 2011 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.

ATTACHMENT D to Order G-162-11 Page 1 of 55

mailto:[email protected]�

mailto:[email protected]�

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




Regional Definitions

ReliabilityFirst Regional Definitions .............................................. 48

NPCC Regional Definitions .......................................................... 49

WECC Regional Definitions ......................................................... 50




Continent-wide Term Acronym

BOT Approval

Date

FERC Approval

Date Definition

Adequacy

[Archive]

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.

Adjacent Balancing Authority

[Archive]

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.

Adverse Reliability Impact

[Archive]

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.

Adverse Reliability Impact

[Archive]

8/4/2011 The impact of an event that results in Bulk Electric System instability or Cascading.

After the Fact

[Archive]

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.

Agreement

[Archive]

2/8/2005 3/16/2007 A contract or arrangement, either written or verbal and sometimes enforceable by law.

Altitude Correction Factor

[Archive]

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.


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http://www.nerc.com/filez/standards/Coordinate-Operations.html�


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http://www.nerc.com/filez/standards/INT_Urgent_Action.html�




http://www.nerc.com/filez/standards/Vegetation-Management.html�




Continent-wide Term

Acronym BOT

Approval Date

FERC Approval

Date Definition

Ancillary Service

[Archive]

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.)

Anti-Aliasing Filter

[Archive]

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.

Area Control Error

[Archive]

ACE 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.

Area Interchange Methodology

[Archive]

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.


[Archive]

5/2/2006 3/16/2007 The state where the Interchange Authority has received the Interchange information (initial or revised).

Automatic Generation Control

[Archive]

AGC 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.








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Continent-wide Term

Acronym BOT

Approval Date

FERC Approval

Date Definition

Available Flowgate Capability

[Archive]

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.

Available Transfer Capability

[Archive]

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.

Available Transfer Capability

[Archive]

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.










Continent-wide Term

Acronym BOT

Approval Date

FERC Approval

Date Definition

Available Transfer Capability Implementation Document

[Archive]

ATCID 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.

ATC Path

[Archive]

08/22/2008 Not approved;

Modification directed 11/24/09

Any combination of Point of Receipt and Point of Delivery for which ATC is calculated; and any Posted Path1

1 See 18 CFR 37.6(b)(1)

.









BOT Approved

Date

FERC Approved

Date Definition

Balancing Authority

[Archive]

BA 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.

Balancing Authority Area

[Archive]

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.

Base Load

[Archive]

2/8/2005 3/16/2007 The minimum amount of electric power delivered or required over a given period at a constant rate.

Blackstart Capability Plan

[Archive]

2/8/2005

Approved Retirement when EOP-005-2 becomes effective

8/5/2009

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.

Blackstart Resource

[Archive]

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










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Continent-wide Term

Acronym BOT

Approved Date

FERC Approved

Date Definition

Block Dispatch

[Archive]

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).

Bulk Electric System

[Archive]

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.

Burden

[Archive]

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.

Business Practices

[Archive]



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.

Bus-tie Breaker

[Archive]

8/4/2011 A circuit breaker that is positioned to connect two individual substation bus configurations.










http://www.nerc.com/filez/standards/Assess-Transmission-Future-Needs.html�





BOT Approved

Date

FERC Approved

Date Definition

Capacity Benefit Margin

[Archive]

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.

Capacity Benefit Margin Implementation Document

[Archive]

CBMID 11/13/2008 11/24/2009 A document that describes the implementation of a Capacity Benefit Margin methodology.

Capacity Emergency

[Archive]

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.

Cascading

[Archive]

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.












Continent-wide Term

Acronym BOT

Approved Date

FERC Approved

Date Definition

Cascading Outages

[Archive]

11/1/2006

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 pre-determined area.

Clock Hour

[Archive]

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.

Cogeneration

[Archive]

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.

Compliance Monitor

[Archive]

2/8/2005 3/16/2007 The entity that monitors, reviews, and ensures compliance of responsible entities with reliability standards.

Confirmed Interchange

[Archive]

5/2/2006 3/16/2007 The state where the Interchange Authority has verified the Arranged Interchange.

Congestion Management Report

[Archive]

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.

Consequential Load Loss

[Archive]

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.

Constrained Facility

[Archive]

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.


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Continent-wide Term

Acronym BOT

Approved Date

FERC Approved

Date Definition

Contingency

[Archive]

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.

Contingency Reserve

[Archive]

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.

Contract Path

[Archive]

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.

Control Performance Standard

[Archive]

CPS 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.

Corrective Action Plan

[Archive]

2/7/2006 3/16/2007 A list of actions and an associated timetable for implementation to remedy a specific problem.

Cranking Path

[Archive]

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.

Critical Assets

[Archive]

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.

Critical Cyber Assets

[Archive]

5/2/2006 1/18/2008 Cyber Assets essential to the reliable operation of Critical Assets.

Curtailment

[Archive]

2/8/2005 3/16/2007 A reduction in the scheduled capacity or energy delivery of an Interchange Transaction.










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Continent-wide Term

Acronym BOT

Approved Date

FERC Approved

Date Definition

Curtailment Threshold

[Archive]

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.

Cyber Assets

[Archive]

5/2/2006 1/18/2008 Programmable electronic devices and communication networks including hardware, software, and data.

Cyber Security Incident

[Archive]

5/2/2006 1/18/2008 Any malicious act or suspicious event that:

• 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.











BOT Approved

Date

FERC Approved

Date Definition

Delayed Fault Clearing

[Archive]

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.

Demand

[Archive]

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.

2. The rate at which energy is being used by the customer.

Demand-Side Management

[Archive]

DSM 2/8/2005 3/16/2007 The term for all activities or programs undertaken by Load-Serving Entity or its customers to influence the amount or timing of electricity they use.

Direct Control Load Management

[Archive]

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.

Dispatch Order

[Archive]

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.

Dispersed Load by Substations

[Archive]

2/8/2005 3/16/2007 Substation load information configured to represent a system for power flow or system dynamics modeling purposes, or both.

Distribution Factor

[Archive]

DF 2/8/2005 3/16/2007 The portion of an Interchange Transaction, typically expressed in per unit that flows across a transmission facility (Flowgate).


















Continent-wide Term

Acronym BOT

Approved Date

FERC Approved

Date Definition

Distribution Provider

[Archive]

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.

Disturbance

[Archive]

2/8/2005 3/16/2007 1. An unplanned event that produces an abnormal system condition.

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

[Archive]

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.

Disturbance Monitoring Equipment

[Archive]

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 recorders2

• 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

2 Phasor Measurement Units and any other equipment that meets the functional requirements of DMEs may qualify as DMEs.








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Continent-wide Term

Acronym BOT

Approved Date

FERC Approved

Date Definition

Dynamic Interchange Schedule or

Dynamic Schedule

[Archive]

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.

Dynamic Transfer

[Archive]

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.









BOT Approved

Date

FERC Approved

Date Definition

Economic Dispatch

[Archive]

2/8/2005 3/16/2007 The allocation of demand to individual generating units on line to effect the most economical production of electricity.

Electrical Energy

[Archive]

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).

Electronic Security Perimeter

[Archive]

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.

Element

[Archive]

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.

Emergency or

BES Emergency

[Archive]

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.

Emergency Rating

[Archive]

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.

Emergency Request for Interchange (Emergency RFI)

[Archive]

10/29/2008 12/17/2009 Request for Interchange to be initiated for Emergency or Energy Emergency conditions.


















Continent-wide Term

Acronym BOT

Approved Date

FERC Approved

Date Definition

Energy Emergency

[Archive]

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.

Equipment Rating

[Archive]

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.

Existing Transmission Commitments

[Archive]

ETC 08/22/2008 11/24/2009 Committed uses of a Transmission Service Provider’s Transmission system considered when determining ATC or AFC.











BOT Approved

Date

FERC Approved

Date Definition

Facility

[Archive]

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.)

Facility Rating

[Archive]

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.

Fault

[Archive]

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.

Fire Risk

[Archive]

2/7/2006 3/16/2007 The likelihood that a fire will ignite or spread in a particular geographic area.

Firm Demand

[Archive]

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.

Firm Transmission Service

[Archive]

2/8/2005 3/16/2007 The highest quality (priority) service offered to customers under a filed rate schedule that anticipates no planned interruption.

Flashover

[Archive]

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.

Flowgate

[Archive]

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.




















Continent-wide Term

Acronym BOT

Approved Date

FERC Approved

Date Definition

Flowgate

[Archive]

08/22/2008 11/24/2009 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

[Archive]

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).

Forced Outage

[Archive]

2/8/2005 3/16/2007 1. The removal from service availability of a generating unit, transmission line, or other facility for emergency reasons.

2. The condition in which the equipment is unavailable due to unanticipated failure.

Frequency Bias

[Archive]

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.












Continent-wide Term

Acronym BOT

Approved Date

FERC Approved

Date Definition

Frequency Bias Setting

[Archive]

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.

Frequency Deviation

[Archive]

2/8/2005 3/16/2007 A change in Interconnection frequency.

Frequency Error

[Archive]

2/8/2005 3/16/2007 The difference between the actual and scheduled frequency. (FA – FS)

Frequency Regulation

[Archive]

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.

Frequency Response

[Archive]

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.

(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).















BOT Approved

Date

FERC Approved

Date Definition

Generator Operator

[Archive]

2/8/2005 3/16/2007 The entity that operates generating unit(s) and performs the functions of supplying energy and Interconnected Operations Services.

Generator Owner

[Archive]

2/8/2005 3/16/2007 Entity that owns and maintains generating units.

Generator Shift Factor

[Archive]

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.

Generator-to-Load Distribution Factor

[Archive]

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.

Generation Capability Import Requirement

[Archive]

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.

Host Balancing Authority

[Archive]

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.

2. The Balancing Authority within whose metered boundaries a jointly owned unit is physically located.

Hourly Value

[Archive]

2/8/2005 3/16/2007 Data measured on a Clock Hour basis.



















BOT Approved

Date

FERC Approved

Date Definition

Implemented Interchange

[Archive]

5/2/2006 3/16/2007 The state where the Balancing Authority enters the Confirmed Interchange into its Area Control Error equation.

Inadvertent Interchange

[Archive]

2/8/2005 3/16/2007 The difference between the Balancing Authority’s Net Actual Interchange and Net Scheduled Interchange. (IA – IS)

Independent Power Producer

[Archive]

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.

Institute of Electrical and Electronics Engineers, Inc.

[Archive]

IEEE 2/7/2006 3/16/2007

Interchange

[Archive]

5/2/2006 3/16/2007 Energy transfers that cross Balancing Authority boundaries.

Interchange Authority

[Archive]

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.

Interchange Distribution Calculator

[Archive]

IDC 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.


















Continent-wide Term

Acronym BOT

Approved Date

FERC Approved

Date Definition

Interchange Schedule

[Archive]

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.

Interchange Transaction

[Archive]

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.

Interchange Transaction Tag

or

Tag

[Archive]

2/8/2005 3/16/2007 The details of an Interchange Transaction required for its physical implementation.

Interconnected Operations Service

[Archive]

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.

Interconnection

[Archive]

2/8/2005 3/16/2007 When capitalized, any one of the three major electric system networks in North America: Eastern, Western, and ERCOT.

Interconnection Reliability Operating Limit

[Archive]

IROL 2/8/2005 3/16/2007

Retired 12/27/2007

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.

Interconnection Reliability Operating Limit

[Archive]

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.


















Continent-wide Term

Acronym BOT

Approved Date

FERC Approved

Date Definition

Interconnection Reliability Operating Limit Tv

[Archive]

IROL Tv 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.

Intermediate Balancing Authority

[Archive]

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

Interruptible Load

or

Interruptible Demand

[Archive]

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.

Joint Control

[Archive]

2/8/2005 3/16/2007 Automatic Generation Control of jointly owned units by two or more Balancing Authorities.













BOT Approved

Date

FERC Approved

Date Definition

Limiting Element

[Archive]

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.

Load

[Archive]

2/8/2005 3/16/2007 An end-use device or customer that receives power from the electric system.

Load Shift Factor

[Archive]

LSF 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.

Load-Serving Entity

[Archive]

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.

Long-Term Transmission Planning Horizon

[Archive]

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.

Market Flow

[Archive]

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.

Misoperation

[Archive]

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.












http://www.nerc.com/filez/standards/Reliability-Coordination-Transmission-Loading-Relief.html�

http://www.nerc.com/filez/standards/Reliability-Coordination-Transmission-Loading-Relief.html�






BOT Approved

Date

FERC Approved

Date Definition

Native Load

[Archive]

2/8/2005 3/16/2007 The end-use customers that the Load-Serving Entity is obligated to serve.

Near-Term Transmission Planning Horizon

[Archive]

1/24/2011 The transmission planning period that covers Year One through five.

Net Actual Interchange

[Archive]

2/8/2005 3/16/2007 The algebraic sum of all metered interchange over all interconnections between two physically Adjacent Balancing Authority Areas.

Net Energy for Load

[Archive]

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.

Net Interchange Schedule

[Archive]

2/8/2005 3/16/2007 The algebraic sum of all Interchange Schedules with each Adjacent Balancing Authority.

Net Scheduled Interchange

[Archive]

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.

Network Integration Transmission Service

[Archive]

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.

Non-Consequential Load Loss

[Archive]

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.




http://www.nerc.com/filez/standards/Project2010-10_FAC_Order_729.html�
















Continent-wide Term

Acronym BOT

Approved Date

FERC Approved

Date Definition

Non-Firm Transmission Service

[Archive]

2/8/2005 3/16/2007 Transmission service that is reserved on an as-available basis and is subject to curtailment or interruption.

Non-Spinning Reserve

[Archive]

2/8/2005 3/16/2007 1. That generating reserve not connected to the system but capable of serving demand within a specified time.

2. Interruptible load that can be removed from the system in a specified time.

Normal Clearing

[Archive]

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.

Normal Rating

[Archive]

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.

Nuclear Plant Generator Operator

[Archive]

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.

Nuclear Plant Off-site Power Supply (Off-site Power)

[Archive]

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.










http://www.nerc.com/filez/standards/Project2009-08_Nuclear_Plant_Interface_Coordination.html�






Continent-wide Term

Acronym BOT

Approved Date

FERC Approved

Date Definition

Nuclear Plant Licensing Requirements (NPLRs)

[Archive]

5/2/2007 10/16/2008 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]

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.








Continent-wide Term

Acronym BOT

Approved Date

FERC Approved

Date Definition

Off-Peak

[Archive]

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.

On-Peak

[Archive]

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.

Open Access Same Time Information Service

[Archive]

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.

Open Access Transmission Tariff

[Archive]

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 non-discriminating service comparable to that provided by Transmission Owners to themselves.

Operating Plan

[Archive]

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.














Continent-wide Term

Acronym BOT

Approved Date

FERC Approved

Date Definition

Operating Procedure

[Archive]

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.

Operating Process

[Archive]

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 Real-time conditions. A guideline for controlling high voltage is an example of an Operating Process.

Operating Reserve

[Archive]

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.

Operating Reserve – Spinning

[Archive]

2/8/2005 3/16/2007 The portion of Operating Reserve consisting of:

• 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.












Continent-wide Term

Acronym BOT

Approved Date

FERC Approved

Date Definition

Operating Reserve – Supplemental

[Archive]

2/8/2005 3/16/2007 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

• Load fully removable from the system within the Disturbance Recovery Period following the contingency event.

Operating Voltage

[Archive]

2/7/2006 3/16/2007 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-mean-square) 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.

Operational Planning Analysis

[Archive]

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.).

Outage Transfer Distribution Factor

[Archive]

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).

Overlap Regulation Service

[Archive]

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.






http://www.nerc.com/filez/standards/IROL.html�









BOT Approved

Date

FERC Approved

Date Definition

Participation Factors

[Archive]

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.

Peak Demand

[Archive]

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).

2. The highest instantaneous demand within the Balancing Authority Area.

Performance-Reset Period

[Archive]

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.

Physical Security Perimeter

[Archive]

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.

Planning Assessment

[Archive]

8/4/2011 Documented evaluation of future Transmission system performance and Corrective Action Plans to remedy identified deficiencies.

Planning Authority

[Archive]

2/8/2005 3/16/2007 The responsible entity that coordinates and integrates transmission facility and service plans, resource plans, and protection systems.

Planning Coordinator

[Archive]

8/22/2008 11/24/2009 See Planning Authority.

Point of Delivery

[Archive]

POD 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.




















Continent-wide Term

Acronym BOT

Approved Date

FERC Approved

Date Definition

Point of Receipt

[Archive]

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.

Point to Point Transmission Service

[Archive]

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.

Postback

[Archive]



Positive adjustments to ATC or AFC as defined in Business Practices. Such Business Practices may include processing of redirects and unscheduled service.

Power Transfer Distribution Factor

[Archive]

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

Pro Forma Tariff

[Archive]

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.

Protection System

[Archive]

2/7/2006 3/17/07 Protective relays, associated communication systems, voltage and current sensing devices, station batteries and DC control circuitry.
















Continent-wide Term

Acronym BOT

Approved Date

FERC Approved

Date Definition

Protection System

[Archive]

11/19/2010 Protection System –

• Protective relays which respond to electrical quantities,

• Communications systems necessary for correct operation of protective functions

• 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.

Pseudo-Tie

[Archive]

2/8/2005 3/16/2007 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.

Purchasing-Selling Entity

[Archive]

2/8/2005 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.

Ramp Rate

or

Ramp

[Archive]

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.

Rated Electrical Operating Conditions

[Archive]

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


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http://www.nerc.com/filez/standards/Protection_System_Maintenance_Project_2007-17.html�











Continent-wide Term

Acronym BOT

Approved Date

FERC Approved

Date Definition

Rating

[Archive]

2/8/2005 3/16/2007 The operational limits of a transmission system element under a set of specified conditions.

Rated System Path Methodology

[Archive]

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.

Reactive Power

[Archive]

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).

Real Power

[Archive]

2/8/2005 3/16/2007 The portion of electricity that supplies energy to the load.

Reallocation

[Archive]

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.

Real-time

[Archive]

2/7/2006 3/16/2007 Present time as opposed to future time. (From Interconnection Reliability Operating Limits standard.)

Real-time Assessment

[Archive]

10/17/2008 An examination of existing and expected system conditions, conducted by collecting and reviewing immediately available data


















Continent-wide Term

Acronym BOT

Approved Date

FERC Approved

Date Definition

Receiving Balancing Authority

[Archive]

2/8/2005 3/16/2007 The Balancing Authority importing the Interchange.

Regional Reliability Organization

[Archive]

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.

2. A member of the North American Electric Reliability Council. The Regional Reliability Organization can serve as the Compliance Monitor.

Regional Reliability Plan

[Archive]

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.

Regulating Reserve

[Archive]

2/8/2005 3/16/2007 An amount of reserve responsive to Automatic Generation Control, which is sufficient to provide normal regulating margin.

Regulation Service

[Archive]

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.

Reliability Adjustment RFI

[Archive]

10/29/2008 12/17/2009 Request to modify an Implemented Interchange Schedule for reliability purposes.
















Continent-wide Term

Acronym BOT

Approved Date

FERC Approved

Date Definition

Reliability Coordinator

[Archive]

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.

Reliability Coordinator Area

[Archive]

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.

Reliability Coordinator Information System

[Archive]

RCIS 2/8/2005 3/16/2007 The system that Reliability Coordinators use to post messages and share operating information in real time.

Remedial Action Scheme

[Archive]

RAS 2/8/2005 3/16/2007 See “Special Protection System”

Reportable Disturbance

[Archive]

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.

Request for Interchange

[Archive]

RFI 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.
















Continent-wide Term

Acronym BOT

Approved Date

FERC Approved

Date Definition

Reserve Sharing Group

[Archive]

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.

Resource Planner

[Archive]

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.

Response Rate

[Archive]

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).

Right-of-Way (ROW)

[Archive]

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.













BOT Approved

Date

FERC Approved

Date Definition

Scenario

[Archive]

2/7/2006 3/16/2007 Possible event.

Schedule

[Archive]

2/8/2005 3/16/2007 (Verb) To set up a plan or arrangement for an Interchange Transaction.

(Noun) An Interchange Schedule.

Scheduled Frequency

[Archive]

2/8/2005 3/16/2007 60.0 Hertz, except during a time correction.

Scheduling Entity

[Archive]

2/8/2005 3/16/2007 An entity responsible for approving and implementing Interchange Schedules.

Scheduling Path

[Archive]

2/8/2005 3/16/2007 The Transmission Service arrangements reserved by the Purchasing-Selling Entity for a Transaction.

Sending Balancing Authority

[Archive]

2/8/2005 3/16/2007 The Balancing Authority exporting the Interchange.

Sink Balancing Authority

[Archive]

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.)

Source Balancing Authority

[Archive]

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.)




















Continent-wide Term

Acronym BOT

Approved Date

FERC Approved

Date Definition

Special Protection System

(Remedial Action Scheme)

[Archive]

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.

Spinning Reserve

[Archive]

2/8/2005 3/16/2007 Unloaded generation that is synchronized and ready to serve additional demand.

Stability

[Archive]

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.

Stability Limit

[Archive]

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.

Supervisory Control and Data Acquisition

[Archive]

SCADA 2/8/2005 3/16/2007 A system of remote control and telemetry used to monitor and control the transmission system.

Supplemental Regulation Service

[Archive]

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.

Surge

[Archive]

2/8/2005 3/16/2007 A transient variation of current, voltage, or power flow in an electric circuit or across an electric system.


















Continent-wide Term

Acronym BOT

Approved Date

FERC Approved

Date Definition

Sustained Outage

[Archive]

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.

System

[Archive]

2/8/2005 3/16/2007 A combination of generation, transmission, and distribution components.

System Operating Limit

[Archive]

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:

• Facility Ratings (Applicable pre- and post-Contingency equipment or facility ratings)

• Transient Stability Ratings (Applicable pre- and post-Contingency Stability Limits)

• Voltage Stability Ratings (Applicable pre- and post-Contingency Voltage Stability)

• System Voltage Limits (Applicable pre- and post-Contingency Voltage Limits)

System Operator

[Archive]

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.













BOT Approved

Date

FERC Approved

Date Definition

Telemetering

[Archive]

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.

Thermal Rating

[Archive]

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.

Tie Line

[Archive]

2/8/2005 3/16/2007 A circuit connecting two Balancing Authority Areas.

Tie Line Bias

[Archive]

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.

Time Error

[Archive]

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.

Time Error Correction

[Archive]

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.

TLR Log

[Archive]

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.


















Continent-wide Term

Acronym BOT

Approved Date

FERC Approved

Date Definition

Total Flowgate Capability

[Archive]

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.

Total Transfer Capability

[Archive]

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.

Transaction

[Archive]

2/8/2005 3/16/2007 See Interchange Transaction.

Transfer Capability

[Archive]

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.”

Transfer Distribution Factor

[Archive]

2/8/2005 3/16/2007 See Distribution Factor.

Transmission

[Archive]

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.
















Continent-wide Term

Acronym BOT

Approved Date

FERC Approved

Date Definition

Transmission Constraint

[Archive]

2/8/2005 3/16/2007 A limitation on one or more transmission elements that may be reached during normal or contingency system operations.

Transmission Customer

[Archive]

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.

2. Any of the following responsible entities: Generator Owner, Load-Serving Entity, or Purchasing-Selling Entity.

Transmission Line

[Archive]

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.

Transmission Operator

[Archive]

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.

Transmission Operator Area

[Archive]

08/22/2008 11/24/2009 The collection of Transmission assets over which the Transmission Operator is responsible for operating.

Transmission Owner

[Archive]

2/8/2005 3/16/2007 The entity that owns and maintains transmission facilities.

Transmission Planner

[Archive]

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.


















Continent-wide Term

Acronym BOT

Approved Date

FERC Approved

Date Definition

Transmission Reliability Margin

[Archive]

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.

Transmission Reliability Margin Implementation Document

[Archive]

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.

Transmission Service

[Archive]

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.

Transmission Service Provider

[Archive]

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.

Vegetation

[Archive]

2/7/2006 3/16/2007 All plant material, growing or not, living or dead.

Vegetation Inspection

[Archive]

2/7/2006 3/16/2007 The systematic examination of a transmission corridor to document vegetation conditions.

Wide Area

[Archive]

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.


















Continent-wide Term

Acronym BOT

Approved Date

FERC Approved

Date Definition

Year One

[Archive]

1/24/2011 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.






ReliabilityFirst Regional Definitions The following definitions were developed for use in ReliabilityFirst Regional Standards.

RFC Regional Term

Acronym BOT

Approved Date

FERC Approved

Date Definition

Resource Adequacy

[Archive]

08/05/2009 03/17/2011 The ability of supply-side and demand-side resources to meet the aggregate electrical demand (including losses)

Net Internal Demand

[Archive]

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

Peak Period

[Archive]

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

Year One

[Archive]

08/05/2009 03/17/2011 The planning year that begins with the upcoming annual Peak Period


http://www.nerc.com/filez/regional_standards/regional_reliability_standards_under_development.html�










NPCC Regional Definitions The following definitions were developed for use in NPCC Regional Standards.

NPCC Regional Term

Acronym BOT

Approved Date

FERC Approved

Date Definition

Current Zero Time

[Archive]

11/04/2010 The time of the final current zero on the last phase to interrupt.

Generating Plant

[Archive]

11/04/2010 One or more generators at a single physical location whereby any single contingency can affect all the generators at that location.


http://www.nerc.com/docs/standards/rrs/PRC-002-NPCC-01.pdf�






WECC Regional Definitions The following definitions were developed for use in WECC Regional Standards.

WECC Regional Term

Acronym BOT

Approved Date

FERC Approved

Date Definition

Area Control Error†

[

Archive]

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.

Automatic Generation Control†

[Archive]

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.

Automatic Time Error Correction

[Archive]

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†

[Archive]

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.

Disturbance†

[Archive]

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.


http://www.wecc.biz/Standards/Approved%20Standards/Forms/AllItems.aspx�














WECC Regional Term

Acronym BOT

Approved Date

FERC Approved

Date Definition

Extraordinary Contingency†

[Archive]

3/12/2007 6/8/2007 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†

[Archive]

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.

Generating Unit Capability†

[Archive]

3/12/2007 6/8/2007 Means the MVA nameplate rating of a generator.

Non-spinning Reserve†

[Archive]

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.

Normal Path Rating†

[Archive]

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.














WECC Regional Term

Acronym BOT

Approved Date

FERC Approved

Date Definition

Operating Reserve†

[Archive]

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.

Operating Transfer Capability Limit†

[Archive]

OTC 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.

Primary Inadvertent Interchange

[Archive]

3/26/2008 5/21/2009 The component of area (n) inadvertent interchange caused by the regulating deficiencies of the area (n).

Secondary Inadvertent Interchange

[Archive]

3/26/2008 5/21/2009 The component of area (n) inadvertent interchange caused by the regulating deficiencies of area (i).

Spinning Reserve†

[Archive]

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).

WECC Table 2†

[Archive]

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.
















WECC Regional Term

Acronym BOT

Approved Date

FERC Approved

Date Definition

Functionally Equivalent Protection System

[Archive]

FEPS 10/29/2008 4/21/2011 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.

• Each Protection System may have different components and operating characteristics.

Functionally Equivalent RAS

[Archive]

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.

• Each RAS may have different components and operating characteristics.

Security-Based Misoperation

[Archive]

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.

Dependability-Based Misoperation

[Archive]

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.

Commercial Operation

[Archive]

10/29/2008 4/21/2011 Achievement of this designation indicates that the

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.

Qualified Transfer Path Curtailment Event

[Archive]

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.


http://www.wecc.biz/Standards/Pending%20Standards/Forms/AllItems.aspx�














WECC Regional Term

Acronym BOT

Approved Date

FERC Approved

Date Definition

Relief Requirement

[Archive]

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.

Transfer Distribution Factor

[Archive]

TDF 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-006-WECC-1).]

Contributing Schedule

[Archive]

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.

Qualified Transfer Path

[Archive]

2/10/2009 3/17/2011 A transfer path designated by the WECC Operating Committee as being qualified for WECC unscheduled flow mitigation.

Qualified Controllable Device

[Archive]

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.














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.


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