Topic:"System Reliability" in M03324

III. STATEMENT OF BASIS AND PURPOSE OF BYLAWS AMENDMENTS The amendments are to Article III, sections 1 and 2 of the Bylaws, including addition of new subsections 1a, "Increase in number of trustees," and 1b, "Decrease in number of trustees...

AI summary The bylaw amendments aim to grant the NERC Board flexibility to adjust the number of independent trustees between ten and eleven, addressing increased workload on the Board of Trustees Compliance Committee (BOTCC) due to a surge in reliability standards violations since 2007. This is recommended by the NERC Nominating Committee to manage the BOTCC's growing responsibilities.

ARTICLE I Definitions Section 1 — Definitions — As used in these Bylaws of the North American Electric Reliability Corporation (hereinafter referred to as "the Corporation"), the terms set forth in this Article I shall have the meanings se...

AI summary This section defines key terms for the North American Electric Reliability Corporation (NERC) Bylaws, including 'Applicable governmental authority,' 'Board,' 'Bulk power system,' 'Commission,' and 'Electric reliability organization.' These definitions establish jurisdictional boundaries and operational scope for reliability standards enforcement across North America.

the areas of technical electric operations and reliability, legal, market, financial, and regulatory matters, and familiarity with regional system operation issues; and reflects geographic diversity.

AI summary The text outlines criteria for Board composition, emphasizing expertise in technical electric operations, reliability, legal, market, financial, and regulatory matters, along with regional system operation knowledge and geographic diversity.

ARTICLE IX Reliability Standards Section 1 ¾ Development of Reliability Standards ¾ The Corporation shall develop, implement and, in all regions in which necessary governmental approvals have been obtained or authority has been provided, e...

AI summary The Corporation must develop and enforce reliability standards for North American bulk power systems, approved by the board and made publicly available. Standards must be created through transparent processes with public input. Violations trigger sanctions via procedures allowing hearings, with penalties proportional to severity and considering remediation efforts.

ARTICLE X Agreements with Regional Entities Section 1 ¾ Delegation Agreements with Regional Entities ¾ The Corporation may, in accordance with appropriate governmental authority, enter into agreements with regional entities pursuant to whi...

AI summary The Corporation may delegate authority to regional entities to enforce reliability standards in North America, requiring board approval and compliance with policies. Agreements must meet criteria to ensure effective bulk power system reliability administration.

ARTICLE IX Reliability Standards Section 1 ¾ Development of Reliability Standards ¾ The Corporation shall develop, implement and, in all regions in which necessary governmental approvals have been obtained or authority has been provided, e...

AI summary The Corporation must develop and enforce reliability standards for North American bulk power systems, approved by the board and made publicly available. Standards must be created through transparent processes with public input. Violations trigger sanctions via procedures allowing hearings, with penalties proportional to severity and considering remediation efforts.

I. INTRODUCTION The North American Electric Reliability Corporation ("NERC") hereby submits for informational purposes its revised Reliability Standards Development Plan in accordance with Section 310 of the NERC Rules of Procedure. The Re...

AI summary NERC submits its revised Reliability Standards Development Plan for informational purposes, referencing the 2010 Development Plan as Exhibit A and its complete development record as Exhibit B, in accordance with Section 310 of the NERC Rules of Procedure.

III. BACKGROUND In 2006, NERC developed an initial version of the plan for Reliability Standards development entitled the Reliability Standards Development Plan: 2007–2009 . NERC has since updated the plan annually, and the 2010–2012 versi...

AI summary NERC's 2010–2012 Reliability Standards Development Plan updates its annual management tool for coordinating reliability standards, engaging stakeholders, and aligning with U.S. and Canadian authorities. The plan is submitted for informational purposes without requesting specific action, building on prior versions and detailing projects in three volumes.

i. General Revisions This section provides a summary of significant revisions to the Reliability Standards Development Plan: 2010–2012 relative to the 2009 plan. The 2010 Development Plan includes 37 projects, two fewer than the 39 project...

AI summary The 2010 Reliability Standards Development Plan revised the 2009 version by reducing the number of projects from 39 to 37. Seven projects completed in 2009 were removed, reflecting progress toward reliability standards. The revisions focus on updating project scope and completion status.

Projects initiated in 2006: 2006-01 System Personnel Training 2006-03 System Restoration and Blackstart 2006-07 Transfer Capabilities: ATC, TTC, CBM, and TRM 2006-09 Facility Ratings

AI summary The document lists projects initiated in 2006, including system personnel training, system restoration, blackstart capabilities, transfer capability studies (ATC, TTC, CBM, TRM), and facility ratings. These initiatives focus on grid reliability, infrastructure planning, and operational preparedness.

Projects initiated in 2008: 2008-08 EOP Violation Severity Levels Revisions Project Removed/SAR Withdrawn One project, Project 2008-05 — Credible Multiple Element Contingencies, identified in the 2009 plan, was removed from the 2010 Develo...

AI summary The 2010 Development Plan revised EOP violation severity levels, removed a project due to a withdrawn SAR, realigned another project to 2012 to support NERC-related initiatives, and added six new projects. No projects were planned for 2011.

Projects initiated in 2009: 2009-06 Facility Ratings 2009-07 Reliability of Protection Systems 2009-18 Withdraw Three Midwest ISO Waivers 1

AI summary The document lists three projects initiated in 2009: Facility Ratings, Reliability of Protection Systems, and the withdrawal of three Midwest ISO waivers. These projects pertain to grid reliability, system protection standards, and regulatory actions related to ISO waivers.

Projects anticipated commencing in 2012: 2012-02 Physical Protection In preparing the 2010 Development Plan , NERC staff reached out to stakeholders and asked for input regarding the 2009 version of the plan. Several stakeholders voiced a...

AI summary NERC's 2010 Development Plan faced stakeholder concerns about overloading concurrent projects, urging focus on high-impact reliability initiatives. The plan addressed feedback by prioritizing reliability improvements, reducing redundant standards, and creating 'Project 2010-06' to align standards with reliability outcomes. Increased interpretation requests also influenced the plan's scope.

ii. Other Modifications In conjunction with this year's effort to prepare the 2010 Development Plan, NERC staff incorporated pending items and issues in what is termed the "NERC Standards Issues Database" ("Issues Database"). The Issues Da...

AI summary NERC updated its 2010 Development Plan by incorporating issues from its 'NERC Standards Issues Database,' enhancing reliability standards through compliance monitoring, event analysis, and initiatives like Project 2010-05 System Protection. These efforts aim to address system protection and control issues critical to bulk power system reliability.

ring the balloting—have resulted in a project schedule extension of approximately six months. The projected completion date has been moved from the second quarter of 2009 to the first quarter of 2010. 2006-06 Reliability Coordination. The...

AI summary Project timelines for reliability coordination and transmission loading relief standards were extended due to NERC staff additions, increased coordination demands, and additional comment periods. Delays added six to twelve months to completion dates, with phase two and three adjustments pushing completion to 2010.

B. NERC Stakeholders Input To support the preparation of the 2010 Development Plan, NERC sought stakeholder comment during two public comment periods, which took place from May 20 through July 6, 2009 and August 28 through September 28, 20...

AI summary NERC gathered stakeholder input for its 2010 Development Plan through two public comment periods and technical committee consultations. Over 30 organizations provided feedback, with a major theme being the need for a triage of reliability standards. NERC responded by adding Project 2010-06 to address results-based reliability standards.

Reliability Standards Development Plan: 2010–2012 ("2010 Development Plan") Volume I: Summary overview of the 2009 Development Plan and identifies significant modifications to the filed 2008 Development Plan. Volume II: Details the specifi...

AI summary The 2010 Development Plan outlines a three-volume structure: Volume I compares the 2009 and 2008 plans, Volume II details specific standards projects, and Volume III summarizes anticipated regional entity activities over the 2010–2012 period.

Complete Development Record for Reliability Standards Development Plan: 2010–2012

AI summary This document marks the beginning of the development record for the Reliability Standards Development Plan spanning 2010–2012. It sets the stage for discussions and proceedings related to establishing reliability standards in the energy sector during this period.

- Under the revised pro forma Delegation Agreement, a Regional Entity that also performs (or whose affiliated entity performs) registered functions as a Registered Entity cannot monitor its own compliance (or that of its affiliate) with ap...

AI summary The revised Delegation Agreement mandates that Regional Entities cannot self-monitor compliance with Reliability Standards, requiring external oversight by NERC or another Regional Entity. It introduces coordinated monitoring for multi-region Registered Entities and adopts standardized violation terminology (Possible/Alleged/Confirmed Violation) for consistency. NERC's review criteria for compliance dispositions and board compliance committee recusal procedures are also outlined.

a. Base Delegation Agreement Initial paragraph and recitals. The initial paragraph identifies the effective date of the revised Delegation Agreement as January 1, 2011, consistent with NERC's request in this Petition. In the initial paragr...

AI summary The revised Delegation Agreement, effective January 1, 2011, aligns with NERC's petition. It updates definitions, representations, and covenants, incorporating NERC's CMEP and referencing reliability standards from FERC and NERC regulations.

d. Exhibit C to Delegation Agreement In the revised pro forma Delegation Agreement, there is only one change to the 34 Common Attributes of an acceptable Regional Entity Reliability Standards Development Procedure ("RSDP") which the Region...

AI summary Exhibit C to the Delegation Agreement revises Common Attribute 34 by removing 'Violation Severity Levels' from the Regional Entity's RSDP, aligning with NERC's updated RSDP framework approved by FERC. This change shifts compliance elements like severity levels to separate development processes, no longer integrated into RSDP standards.

f. Exhibit E to the Delegation Agreement Exhibit E, Funding, has been considerably expanded in the revised pro forma Delegation Agreement, and some provisions have been moved to Exhibit E from the body of the Delegation Agreement. In Secti...

AI summary Exhibit E to the Delegation Agreement has been expanded, detailing funded activities such as Event Analysis and Reliability Improvement, while removing Reliability Readiness Evaluation and Improvement. Budgeting provisions for the Regional Entity's business plan and reserve mechanisms are emphasized, with NERC ROP references omitted for budgeting purposes.

pro forma Delegation Agreement, and also identifies certain differences between the current and the revised NPCC Delegation Agreements due to reasons other than the changes in the pro forma template. 1. Section 1.0 of Exhibit D to the revi...

AI summary The revised NPCC Delegation Agreement outlines cross-border compliance mechanisms, implementing NERC CMEP in the U.S. portion and aligning Canadian compliance with provincial MOUs. Section 2.0 establishes a Hearing Body with structured voting rules to prevent stakeholder dominance, ensuring balanced decision-making.

4. Amendments to Section 800 – Reliability Assessment and Performance Analysis The amendments to §800 are in §807 and §808. Section 807, Analysis of Major Events, has been amended to add a new subsection (c) (with the subsequent subsection...

AI summary Amendments to Sections 807 and 808 of §800 clarify NERC's and regional entities' authority to request information from bulk power system stakeholders. This enables them to analyze major and off-normal events, assess vulnerabilities, and develop lessons learned.

have received such requests and concluded that it would be useful and appropriate to have a process for addressing such requests established in the ROP. As detailed in new §1208, the process requires: - a written request by the Registered...

AI summary The text outlines a new process for handling transfer requests under the ROP, involving written requests by Registered Entities, public comment periods, consultation between Regional Entities, NERC Board review, and FERC approval of amendments to Delegation Agreements. The process emphasizes stakeholder consultation and transparency.

to make it more consistent with the definition of and provisions applicable to Remedial Action Directives in Appendix 4C. Specifically, the first paragraph of this section has been amended as follows: Remedial actions are directives that m...

AI summary Amendments to Appendix 4B of the NERC Rules of Procedure align Remedial Action Directives with Appendix 4C, clarifying that such directives address imminent threats to bulk power system reliability. The changes define remedial actions as immediate corrective measures for alleged reliability standard violations and limit their scope to conditions posing imminent reliability risks.

2. Section 2.0 – Identification of Organizations Responsible for Complying with Reliability Standards The revisions to the first five paragraphs of §2.0 reflect the revised roles of NERC and the Regional Entities in registering entities an...

AI summary Revisions to Section 2.0 clarify NERC's expanded role in maintaining a consolidated Compliance Registry for the Bulk Power System, replacing regional registries. Regional Entities now provide data for registration decisions, and Registered Entities must notify NERC of changes. NERC will also list applicable Reliability Standards and report to FERC monthly.

e retention period specified in the Reliability Standard. However, in such cases, the Compliance Enforcement Authority will require the Registered Entity to demonstrate compliance through other means. The time period to be covered by a Com...

AI summary The text addresses controversies around compliance audit timelines and document retention periods under Reliability Standards. It clarifies that Registered Entities won't be penalized for failing to retain documents beyond specified periods but must demonstrate compliance through alternative means. New subsections (3.1.4.2 and 3.1.4.3) aim to ensure audit coverage clarity and review incomplete Mitigation Plans.

ance reporting and tracking system (thereby reporting it to NERC 20 ); NERC in turn reports the Possible Violation to the NERC BOTCC and to FERC, on a confidential basis. 21 (§5.1) - Assessment of the Possible Violation. After issuing the...

AI summary The enforcement process for reliability standard violations involves reporting to NERC, assessment by the Compliance Enforcement Authority, and issuing notices to registered entities. NERC confidentially reports possible violations to FERC and the BOTCC. The process includes evaluating evidence, determining violations, and proposing penalties if confirmed.

6. Section 6.0 – Mitigation of Violations of Reliability Standards 26

AI summary This section outlines procedures for mitigating violations of reliability standards, involving entities such as NERC and FERC, as part of a regulatory framework for ensuring grid reliability.

a. Section 6.1 – Requirement for Submission of Mitigation Plans Section 6.1 has been revised to specify that in addition to being required to submit a Mitigation Plan upon being found in violation of a Reliability Standard, a Registered En...

AI summary Section 6.1 has been revised to allow Registered Entities to submit Mitigation Plans at any time, including with a Self-Report or in response to a Notice of Possible Violation. Appendix 4C updates disclosure prohibitions and references to NERC's director of enforcement.

c. Section 6.3 – Timetable for Completion of Mitigation Plans Section 6.3 has been revised to specify that a Mitigation Plan "should encompass actions necessary to prevent a recurring violation of the Reliability Standard requirements unde...

AI summary Section 6.3 was revised to require Mitigation Plans to address actions preventing recurring violations of Reliability Standards linked to Possible, Alleged, or Confirmed Violations, ensuring compliance with reliability requirements.

f. Section 6.6 – Completion/Confirmation of Implementation of Mitigation Plans In the second paragraph of §6.6, a reference to the Compliance Enforcement Authority verifying that the Registered Entity has completed its Mitigation Plan and...

AI summary Section 6.6 was revised to clarify that the Compliance Enforcement Authority verifies completion of Mitigation Plans aligned with specific Reliability Standard requirements, not just general standards. Mitigation Plans address violations of particular Reliability Standard requirements.

BASED ON SECTION 500 AS APPROVED BY FERC ON JUNE 10, 2010 (Available on the NERC website at http://www.nerc.com/fileUploads/File/Filings/Attachments_to_Supplement_the_RDA_Filing.pdf

AI summary The text references a regulatory filing related to Section 500 approved by FERC, dated June 10, 2010, and linked to a NERC document detailing a Reliability and Demand Assessment (RDA) filing. It highlights a regulatory proceeding involving reliability standards and compliance.

III. STATEMENT OF BASIS AND PURPOSE OF THE PROPOSED REVISIONS TO THE RELIABILITY STANDARDS DEVELOPMENT PROCESS

AI summary The proposed revisions aim to enhance grid reliability and align with NERC and FERC standards. The basis includes stakeholder input and evolving grid needs, with the purpose of improving reliability standards development processes.

Principles • This section was eliminated as a separate section and the need to support reliability principles and market interface principles was added to the introductory information in the section titled, "Elements of a Reliability Stand...

AI summary The 'Principles' section was removed, and reliability and market interface principles were integrated into the 'Elements of a Reliability Standard' section's introductory information, emphasizing their importance in standard development.

Reliability Standard Definition, Characteristics, and Elements - The "definition" of a Reliability Standard was retained in the section titled, "Elements of a Reliability Standard." - The reference to the "Types of Reliability Standards" w...

AI summary The document revises terminology around reliability standards, changing 'Types of Reliability Standards' to 'Types of Reliability Requirements' to align with the Ad Hoc Results-based report. It also subdivides standard elements into mandatory, informational, and compliance categories for clarity.

Roles in the Reliability Standards Program Organization The described roles have been revised as follows: • The Board of Trustees' role description was expanded to reflect its role with respect to interpretations, definitions and variances...

AI summary Revised roles in the Reliability Standards Program Organization include expanded Board of Trustees responsibilities for regulatory approval of standards, modified Standards Committee duties to align with NERC and FERC benchmarks, and removal of the Members Representative Committee's role. The Board may decline to adopt standards, and the Standards Committee now reports directly to the Board.

Expedited Process On several occasions, it has been necessary for the Standards Committee to approve an expedited standards process to meet specific regulatory directives. The committee has been reluctant to use the "Urgent Action" process...

AI summary The Standards Committee replaced the 'Urgent Action' process with an 'Expedited Standards Development Process' to address regulatory directives or urgent reliability needs. This change allows deviations from standard procedures while maintaining ANSI accreditation requirements through unchanged follow-up steps.

PROPOSED NERC RELIABILITY STANDARD PROCESSES MANUAL ( Available on the NERC Website at [http://www.nerc.com/fileUploads/File/Filings/SPM\_ExhA\_Attachments.pdf](http://www.nerc.com/fileUploads/File/Filings/SPM_ExhA_Attachments.pdf))

AI summary The document outlines a proposed manual for NERC's reliability standard processes, available on their website. It details procedures for developing and implementing reliability standards, emphasizing coordination with regional reliability organizations and adherence to ANSI standards.

NERC RELIABILITY STANDARDS DEVELOPMENT PROCESS, VERSION 7 ( Available on the NERC Website at [http://www.nerc.com/fileUploads/File/Filings/SPM\_ExhB\_Attachments.pdf](http://www.nerc.com/fileUploads/File/Filings/SPM_ExhB_Attachments.pdf))

AI summary The document outlines the NERC Reliability Standards Development Process, Version 7, available on the NERC website. It details procedures for developing and updating reliability standards critical to the North American electric grid, involving organizations like NERC, FERC, and ANSI.

essment Attachment 14: Status Report on the Achievement of NERC's 2009 Goals and Objectives, by Program. Attachment 15: Metrics Comparing Regional Entity Operations Based on the 2010 Budgets Attachment 16: Metrics on NERC and Regional Enti...

AI summary The document lists attachments related to NERC's 2009 goals, financial metrics, administrative costs, and reliability standard enforcement. It includes status reports, financial statements, and progress updates on reliability data collection, submitted by NERC's attorney.

1. Organization of NERC's 2010 Business Plan and Budget In this filing NERC provides notice of its 2010 Business Plan and Budget. NERC's 2010 Business Plan and Budget is organized based on five specific program areas. Each of these program...

AI summary NERC's 2010 Business Plan and Budget is organized into five program areas aligned with §215 of the Federal Power Act, covering reliability standards development, compliance enforcement, training, reliability assessments, and performance analysis. These programs support statutory activities related to bulk power system reliability and compliance.

B. Regional Entity Proposed 2010 Budgets The individual Regional Entity Business Plans and Budgets are provided in Attachments 3 through 10 . The Regional Entity budgets for statutory activities that are to be funded through NERC are the b...

AI summary The document outlines the 2010 budgets for Regional Entities, funded by NERC, covering reliability standards, compliance monitoring, training, and infrastructure security. It notes that NERC’s 2010 plan excludes non-statutory activities, with funding from FPA §215 dedicated solely to statutory functions. Administrative costs for Regional Entities are also budgeted to meet delegation agreement obligations.

to AESO, but the memorandum has not yet been finalized. The AESO credit amount was allocated to the remainder of the LSEs (Balancing Authorities) in the WECC Region on the basis of NEL. 46 After allocating the appropriate portions of the N...

AI summary The text details the 2010 ERO funding requirement of $15,126,888 for Canadian end users, allocated across NERC ($3,717,270), Regional Entities ($11,348,795), and WIRAB ($60,823). Allocations consider NEL-based distributions, adjustments from the 'Expanded Policy on Allocation of Certain Compliance and Enforcement Costs,' and the AESO credit adjustment. A table and appendix provide further breakdowns.

E. Treatment of Prior Years' Budget Surpluses or Deficits/Working Capital Reserve In the 2008 Budget Order, FERC approved NERC's proposal to authorize a one-year suspension of NERC's policy of taking account of anticipated year-end budget...

AI summary FERC approved NERC's 2008 proposal to use 2007 surpluses as reserves for 2008 costs related to enforcing reliability standards. Subsequent years (2009-2010) adjusted assessments based on accumulated surpluses/deficits to meet targeted working capital reserves. This process involved balancing budgets against statutory duties and reliability compliance requirements.

1. Reliability Standards Program The Reliability Standards Program develops and maintains standards designed to ensure the reliability of the bulk power system in North America. The stakeholder Standards Committee provides oversight to the...

AI summary The Reliability Standards Program under NERC ensures bulk power system reliability through standards development, overseen by the Standards Committee. The 2010 budget includes increased FTEs and expenses for personnel, meetings, and consultants, with a focus on CIP standards and system initiatives.

3. Reliability Assessment and Performance Analysis Program The Reliability Assessment and Performance Analysis Program enables NERC to meet its responsibility as the ERO to "conduct periodic assessments of the reliability and adequacy of t...

AI summary The Reliability Assessment and Performance Analysis Program, managed by NERC, involves annual assessments of North America's bulk power system reliability, including long-term, summer, and winter reports. Special reports are prepared as needed, and NERC analyzes events and climate change impacts on reliability.

5. Situation Awareness and Infrastructure Security NERC's Situation Awareness and Infrastructure Security Program coordinates all of NERC's efforts to improve physical and cyber security for the North American bulk power system as it relat...

AI summary NERC's Situation Awareness and Infrastructure Security Program enhances physical and cyber security for the North American bulk power system through standards, compliance, risk assessments, and real-time monitoring. It oversees the ES-ISAC, established in 1999, and the ESSG created in 2008 to guide infrastructure security efforts.

4. Reliability First Reliability First has a total statutory budget for 2010 of $14,184,713, an increase of $2,750,512 over its 2009 Budget. However, Reliability First 's requested assessments, which were significantly reduced in its 2009...

AI summary Reliability First seeks a 2010 statutory budget increase of $2.75M over 2009, driven by higher assessments and staffing needs. Budget reflects $14.3M in requested assessments, increased FTEs for compliance programs, and a target Working Capital Reserve of $1.4M. Non-statutory activities are excluded.

5. SERC SERC's total statutory budget for 2010 is $10,701,683, an increase of $606,137 over its 2009 Budget. SERC plans total staffing for statutory and administrative programs of 45.5 FTEs, an increase of 2.5 FTEs over its 2009 Budget. SE...

AI summary SERC's 2010 budget increased by $606,137, with major allocations to infrastructure security and administrative services. Staffing rose to 45.5 FTEs, and the Working Capital Reserve target is $1,009,555. SERC will handle TFE processing with existing resources and may request supplemental funding if needed. No non-statutory activities are planned.

8. WECC WECC's 2010 total statutory budget is $39,508,558, an increase of $1,816,790 over its 2009 Budget. WECC plans total staffing for statutory and administrative programs of 172.5 FTEs, an increase of 32.5 FTEs over its 2009 Budget. Of...

AI summary WECC's 2010 budget increased by $1.8 million, with 32.5 additional FTEs, focusing on compliance programs like CMEP and Organization Registration. Resources for TFE processing rely on existing staff and reserves, with potential supplemental funding needed later in 2010.

IX. UPDATE ON RELIABILITY ENHANCEMENT PROGRAMS In the 2009 Budget Order , FERC stated: The Commission understands that many aspects of the implementation of the Energy Policy Act of 2005 are still in a state of evolution and that, because...

AI summary FERC acknowledged NERC's 2008 reliability enhancement filing but emphasized the need for more developed programs and funding in NERC's 2010 Business Plan. The 2009 Budget Order highlighted ongoing obligations to address cybersecurity standards and resource adequacy, requiring staged development with measurable goals.

NORTH AMERICAN ELECTRIC RELIABILITY CORPORATION

AI summary The document references the North American Electric Reliability Corporation (NERC), a regulatory body overseeing electric reliability standards. No further details or arguments are present in the provided text.

THREE-YEAR ELECTRIC RELIABILITY ORGANIZATION PERFORMANCE ASSESSMENT REPORT June 28, 2010

AI summary The document is a three-year performance assessment report for an electric reliability organization, dated June 28, 2010. It evaluates the organization's reliability performance but does not include detailed findings or specific metrics in the provided text.

I. INTRODUCTION On July 20, 2006, the Federal Energy Regulatory Commission ("FERC") issued its Order certifying the North American Electric Reliability Corporation (NERC) as the Electric Reliability Organization (ERO). 1 FERC's regulations...

AI summary The Federal Energy Regulatory Commission (FERC) certified the North American Electric Reliability Corporation (NERC) as the Electric Reliability Organization (ERO) in 2006. FERC's regulations require NERC to submit performance assessments three years post-certification and every five years thereafter, with public comment proceedings to review its performance.

II. SINCE CERTIFICATION AS THE ERO, NERC HAS ACHIEVED SUBSTANTIAL ACCOMPLISHMENTS TOWARD IMPROVING THE RELIABILITY OF THE BULK POWER SYSTEM

AI summary Since certification as the Electric Reliability Organization (ERO), the North American Electric Reliability Corporation (NERC) has made significant achievements in enhancing the reliability of the bulk power system through regulatory and operational improvements.

A. Background In the wake of the cascading outages that occurred in the Western Interconnection in July and August 1996, concerns regarding the ability of the electric industry to continue to rely exclusively on voluntary means to ensure r...

AI summary The 1996 Western Interconnection outages and the 2003 blackout prompted the U.S. Congress to enact §215 of the FPA via the Energy Policy Act of 2005, establishing mandatory reliability standards for the bulk power system. These standards, enforced by an ERO under FERC, replaced prior voluntary measures and addressed gaps in compliance mechanisms.

8 NERC members may join only one sector. NERC considers a corporation and its affiliates as a single member. That member may apply to join only one sector, which may be any single sector for which the corporation or any of its affiliates i...

AI summary The text discusses the complexity and importance of maintaining reliability standards for the North American bulk power system, emphasizing the role of NERC as the ERO in developing and enforcing mandatory reliability standards through audited self-regulation. The system's vast scale and reliance by society highlight the necessity of these standards.

B. NERC Has Developed a Comprehensive Body of Reliability Standards for the Bulk Power System Using its American National Standards Institute-accredited and Commission-approved reliability standards development procedure, embodied in Secti...

AI summary NERC has developed a comprehensive set of reliability standards for the bulk power system, approved by FERC. As of May 31, 2009, 95 continent-wide standards were approved, with 94 in effect in the U.S. and several Canadian provinces. These standards cover various areas like resource balancing, communications, and protection and controls, and are developed through an open, stakeholder-driven process.

Improvement to the Reliability of the Bulk Power System NERC and the industry have made significant progress toward accomplishing the goal of the U.S. Congress of having a comprehensive set of mandatory and enforceable reliability standard...

AI summary NERC and FERC have established mandatory reliability standards for the bulk power system, replacing voluntary compliance with enforceable requirements. The CIP standards (CIP-002 to CIP-009) aim to protect critical infrastructure, while regional entities like WECC develop additional standards. Ongoing revisions ensure evolving reliability needs are met.

Issues Identified by Stakeholders Concerning Reliability Standards 18 The complex process for establishing standards has, as expected, come with a set of challenges. NERC received significant feedback with respect to the standard-setting p...

AI summary Stakeholders highlight challenges in establishing reliability standards, emphasizing tensions over roles of NERC, FERC, and stakeholders. The bulk power system's complexity, with over 1,800 entities and international regulatory oversight, complicates standard-setting. These issues reflect both the chosen model and the system's inherent complexity.

Section 215 also authorizes FERC to order the Electric Reliability Organization to submit to the Commission a proposed reliability standard or a modification to a reliability standard that addresses a specific matter if the Commission cons...

AI summary Section 215 empowers FERC to direct ERO to propose reliability standards or modifications. FERC emphasizes industry input and Canadian participation to ensure effective, internationally aligned standards. It has expressed concerns about the standards process being slow and producing weak, least-common-denominator outcomes.

C. NERC and the Regional Entities Have Developed and Implemented a Comprehensive Organization Registration Program In order to begin monitoring and enforcing compliance with the mandatory reliability standards, it was necessary for NERC an...

AI summary NERC and Regional Entities established a program to register bulk power system entities for reliability compliance. Over 1,800 entities were registered, with 100 disputes arising, seven unresolved as of 2009. The process involved defining reliability functions, creating compliance criteria, and resolving disputes through regional and NERC-level appeals.

Improvement to the Reliability of the Bulk Power System The establishment and implementation of the Organization Registration Program has improved reliability of the bulk power system because (i) NERC and the Regional Entities now know whi...

AI summary The Organization Registration Program enhanced bulk power system reliability by clarifying reliability responsibilities for NERC and Regional Entities, ensuring entities understand their obligations, and preserving due process rights for users, owners, and operators.

Issues Identified by Stakeholders Concerning Organization Registration Stakeholder survey respondents raised issues concerning whether NERC should consider moving to a "registration by requirement" approach; consistency of registration req...

AI summary Stakeholders question NERC's registration approach, seeking a 'registration by requirement' model, consistency across regions, clarity in criteria, assessment of SME impact on reliability, and a unified process for multi-region entities. These issues are detailed in Attachment 2.

D. NERC and the Regional Entities Have Developed a Comprehensive and Effective Program for Monitoring and Enforcing Compliance with Reliability Standards Since becoming the ERO, NERC, working with the Regional Entities, has developed and i...

AI summary NERC, as the ERO, has established a comprehensive compliance program with Regional Entities through the CMEP, including eight processes like audits and self-reports. Regional Entities handle front-line tasks, while NERC provides oversight. This ensures adherence to reliability standards via procedures outlined in NERC's Rules of Procedure.

Improvement to the Reliability of the Bulk Power System The development and implementation of the NERC and Regional Entity Compliance Monitoring and Enforcement Programs has provided significant new assurances of the reliability of the bul...

AI summary The implementation of NERC and Regional Entity Compliance Monitoring and Enforcement Programs enhances bulk power system reliability through penalties, monitoring, and mitigation plans, fostering compliance cultures among stakeholders.

onsistency across all the Regional Entities. In addition, stakeholders commented that more NERC oversight and training of Regional Entity compliance audit teams could help improve the overall program. NERC established a single set of rules...

AI summary Stakeholders highlight inconsistencies in regional compliance programs due to unclear delegation agreements and legacy issues. NERC lacks mandatory performance metrics, leading to varied implementation. FERC's cautious approach in its Penalty Notice Guidance Order slowed program rollout, prioritizing comprehensiveness over evolutionary adaptation.

E. NERC Has Developed an Effective Program for Disseminating Alerts on Potential Reliability Issues to Owners, Operators and Users of the Bulk Power System Since being certified as the ERO, NERC has developed a system of industry alerts fo...

AI summary NERC, as the Electric Reliability Organization, has established a three-tier alert system (Advisories, Recommendations, Essential Actions) to communicate reliability information to bulk power system stakeholders. This program, codified in §810 of NERC's Rules of Procedure and approved by FERC, ensures targeted communication of lessons learned, recommended actions, and mandatory reliability measures.

Improvement to the Reliability of the Bulk Power System The industry alerts program has improved the reliability of the bulk power system by establishing a mechanism for dissemination of information to bulk power system owners, operators,...

AI summary The industry alerts program enhances bulk power system reliability by disseminating critical information on system events and vulnerabilities to owners, operators, and users. Initially using the Compliance Registry, it will transition to NERC Alert mailboxes and track responses to recommendations and essential actions.

F. NERC Has Analyzed and Disseminated Information on System Events Affecting Reliability NERC has established an Event Analysis and Information Exchange Program to analyze major events and other off-normal events occurring on the bulk powe...

AI summary NERC's Event Analysis Program investigates major power system events to enhance reliability, collaborating with regional entities and industry experts. It identifies root causes, monitors performance trends, and disseminates findings. Gerstein's insights on risk management and early warnings are highlighted as critical for preventing cascading outages.

Improvement to the Reliability of the Bulk Power System The Event Analysis Program has been effective in helping to improve the reliability of the bulk power system by analyzing major events occurring on the bulk power system, uncovering i...

AI summary The Event Analysis Program enhances bulk power system reliability by identifying risks and sharing insights, though confidentiality and cross-border regulatory protocols hinder full information dissemination. NERC urges FERC and Canadian authorities to expedite protocols for improved reliability and plans to expand redacted post-event analysis sharing.

Issues Identified by Stakeholders Concerning Event Analysis Noting the backlog of system events being analyzed for which reports have not been published, stakeholders suggested a need for criteria to determine events to be analyzed (in ord...

AI summary Stakeholders highlighted a backlog of unanalyzed system events, urging criteria to prioritize analyses and interim reporting. They also emphasized improving cross-border information protocols and addressing tensions between Event Analysis and Compliance Programs. NERC's ongoing reliability assessments of the bulk power system, mandated by FPA and FERC, are detailed, with a focus on emerging reliability issues.

Issues Identified by Stakeholders Concerning Reliability Assessments Commenters raised a number of concerns with the Reliability Assessment Program, including: - NERC should avoid taking policy advocacy positions in its reliability assessm...

AI summary Stakeholders raised concerns about NERC's reliability assessments, citing policy advocacy, data collection burdens, unfounded assumptions, data gaps from vertically-integrated utilities, and lack of transparency in incorporating NERC comments. They also recommended expanding Long-Term Reliability Assessments (LTRAs) beyond 10 years for better transmission planning.

H. NERC Has Developed and Provided Useful Metrics and Benchmarks for Measuring Reliability Performance Historically, collection, analysis, and dissemination of industry performance data, and analysis and dissemination of performance metric...

AI summary NERC has historically collected and disseminated reliability performance data, expanding its role as the ERO to provide independent metrics and benchmarks post-2004. Its programs, like GADS and TADS, aim to identify best practices to improve bulk power system reliability. NERC's Reliability Assessment and Performance Analysis Program oversees these efforts, focusing on generating and transmission availability data.

Improvement to the Reliability of the Bulk Power System NERC's performance metrics and benchmarking activities have helped and will continue to help to maintain and improve the reliability of the bulk power system by focusing attention on...

AI summary NERC's performance metrics and benchmarking activities enhance bulk power system reliability by identifying trends and root causes of unreliability. These data-driven initiatives enable stakeholders to address existing and emerging reliability issues through historic performance analysis.

Issues Identified by Stakeholders Concerning Performance Metrics and Benchmarking Issues raised in stakeholders' comments concerning NERC's metrics and benchmarking activities included the following: - A defined process is needed for imple...

AI summary Stakeholders emphasized the need for a defined process to implement Section 1600 of NERC's Rules of Procedure, ensuring metrics are justified for bulk power system reliability, avoiding redundant data collection, and improving dissemination of metrics to enhance benchmarking and reliability.

NERC responsible for the overall Situational Awareness Program and is a recognized CIP expert. Additionally, NERC has created and staffed the position of Manager of Critical Infrastructure Protection. NERC's CIP activities include facilita...

AI summary NERC leads critical infrastructure protection (CIP) through standard development, compliance oversight, and training. Eight CIP standards (CIP-002 to CIP-009) were approved by FERC in Order No. 706, requiring phased compliance by registered entities. Regional Entities conduct audits, and self-certification is mandated every six months starting 2008.

Improvement to the Reliability of the Bulk Power System NERC's CIP activities are improving, and will continue to improve, the reliability of the bulk power system. As the CIP standards implementation schedule is completed, the industry's...

AI summary NERC's CIP activities enhance the reliability of the bulk power system by improving compliance with standards, monitoring, and cybersecurity through ES-ISAC. Continued implementation of CIP standards and information sharing reduces risks from cyber attacks and system failures.

e the immediately preceding section of this report summarized the important role of Situation Awareness and Infrastructure Security as the NERC program responsible for CIP activities, the scope of the Situation Awareness and Infrastructure...

AI summary The Situation Awareness and Infrastructure Security Program, managed by NERC, extends beyond Critical Infrastructure Protection (CIP) to include real-time monitoring, event notifications, and interagency coordination. The ES-ISAC, coordinated by NERC, disseminates threat analyses and shares information with government agencies, including the Nuclear Regulatory Commission, to enhance bulk power system security against natural and cyber threats.

Issues Identified by Stakeholders Concerning Situation Awareness/Infrastructure Security Issues raised by stakeholder comments concerning NERC's Situation Awareness and Infrastructure Security Program included the following: - Real-time si...

AI summary Stakeholders argue that NERC's Situation Awareness program overlaps with Reliability Coordinators' roles, increases costs, and risks system reliability. They also highlight gaps in communication protocols and strong support for legacy tools like the Reliability Toolbox. NERC's responses and actions are detailed in Attachment 2.

III. NERC CONTINUES TO MEET THE CERTIFICATION CRITERIA OF 18 C.F.R. §39.3(b) A. NERC Has the Ability to Develop and Enforce, Pursuant to 18 C.F.R. §39.7, Reliability Standards that Provide for an Adequate Level of Reliability of the Bulk P...

AI summary NERC, as the certified ERO, has developed 95 continent-wide reliability standards with FERC approval, using a stakeholder-driven process. Standards are created by industry experts, subject to public comment, ballot approval, and FERC endorsement. NERC continues prioritizing new and revised standards through its three-year development plans to ensure bulk power system reliability.

f the notice of confirmed violation and penalty or sanction, or the settlement entered into by the registered entity, with FERC, in accordance with §39.7(d), (e) and (g) of the FERC's ERO regulations. NERC's rules for determining the amoun...

AI summary NERC's penalty determination process considers factors like VRF, VSL, compliance history, and self-reporting, aligning with FERC regulations and FPA requirements. It emphasizes proportionality between penalties and violation seriousness, alongside timely remediation efforts. The section also highlights NERC's commitment to due process, public comment, and balanced interests in reliability standard development.

F. NERC Has Established Rules That Provide Appropriate Steps to Gain Recognition in Canada and Mexico NERC's Certificate of Incorporation states that one of NERC's corporate purposes is "to act as the electric reliability organization for...

AI summary NERC seeks recognition as the ERO in Canada and Mexico. In Canada, provincial authorities handle electricity regulation, requiring NERC to secure agreements with provinces. Recognition has been achieved in Alberta, Manitoba, New Brunswick, and Ontario. In Mexico, CFE oversees reliability, with WECC agreements in Baja California Norte. NERC continues efforts to enforce reliability standards in remaining provinces.

Margaret Mayora, NPCC 1 BEFORE THE 3 approval and application of mandatory Standards and Criteria in the Canadian jurisdictions of 4 Ontario, Quebec, New Brunswick and Nova Scotia. 5 6 7 8 9 10 11 TABLE OF CONTENTS 12 I. INTRODUCTION 4 13...

AI summary The document outlines a request by the Northeast Power Coordinating Council (NPCC) for approval of reliability criteria in Canadian jurisdictions, including Nova Scotia. It includes exhibits listing and summarizing the approved reliability criteria.

1 ensuring that each Regional Standard serves a purpose in support of the reliability of the 2 regional bulk power system. Each Regional Reliability standard shall also be consistent 3 with all of pertinent reliability principles and crite...

AI summary The document discusses the importance of Regional Reliability Standards in supporting the reliability of the regional bulk power system. It mentions the NPCC's PRC-002-NPCC standard and outlines the directories containing reliability criteria, including design, emergency operations, and generator capabilities.

Directory 1, Design and Operation of the Bulk Power System Approved, December 1, 2009 The objective of these criteria is to provide a "design-based approach" to ensure the bulk power system is designed and operated to a level of reliabilit...

AI summary The document outlines criteria for ensuring the bulk power system's reliability through design-based approaches, emphasizing the need to withstand contingencies, prevent cascading outages, and maintain balanced resources and transmission flexibility.

Directory 3, Maintenance Criteria for Bulk Power System Protection Approved, July 11, 2008 The purpose of this Directory is to present the basic maintenance requirements for bulk power system protection systems. It is recognized that respo...

AI summary This Directory outlines basic maintenance requirements for bulk power system protection systems, acknowledging that responsible entities may impose stricter standards based on local conditions to ensure reliability and safety.

Directory 4, Bulk Power System Protection Criteria Approved, December 1, 2009 The purpose of this Directory is to provide the protection criteria, for protection of the NPCC bulk power system. It is not a design specification.

AI summary This document outlines protection criteria for the NPCC bulk power system, emphasizing that it serves as a guideline rather than a design specification. The focus is on reliability standards for bulk power system protection.

Directory 7, Special Protection Systems Approved, December 27, 2007 Provide the basic criteria for Special Protection Systems such that the Bulk Power System in NPCC Inc. member Areas is operated reliably. The documents outlines the approv...

AI summary Directory 7 establishes criteria for approving Special Protection Systems (SPS) on the NPCC Bulk Power System, categorizing them as Type 1, 2, or 3 based on operational impact. Type 1 SPSs require rigorous examination, analysis, and approvals due to their potential to significantly affect system reliability.

Directory 8, System Restoration Approved, October 21, 2008 The purpose of this Directory is to present the basic criteria with which each applicable entity must plan for and perform power system restoration following a major or a total bla...

AI summary Directory 8 establishes criteria for power system restoration after major blackouts, requiring entities to comply with restoration plans reviewed annually by the NPCC Inc. Task Force. The NPCC's regional restoration plan aggregates reviewed individual plans, ensuring coordination among operating entities.

Directory 9, Verification of Generator Gross and Net Real Power Capability Approved, December 22, 2008 This Directory presents the minimum criteria for verifying the Gross Real Power Capability and Net Real Power Capability of generators o...

AI summary This document establishes criteria for verifying generator power capabilities to ensure the accuracy of reliability assessments for the NPCC bulk power system, aligning with NERC Standard MOD-024-1. Compliance by entities ensures reliable steady-state modeling.

Directory 10, Verification of Generator Gross and Net Reactive Power Capability Approved, December 22, 2008 This Directory presents the minimum criteria for verifying the Gross Reactive Power Capability and Net Reactive Power Capability of...

AI summary This directory establishes minimum criteria for verifying the gross and net reactive power capability of generators, ensuring compliance with NERC Standard MOD-025-1. It aims to maintain accuracy in steady-state models assessing the reliability of the NPCC bulk power system, with NSPI and NPCC as key entities involved.

Directory 12, Underfrequency Load Shedding Program Requirements Approved, March 3, 2010 This Directory presents the basic criteria for the design and implementation of under frequency load shedding programs to ensure that declining frequen...

AI summary Directory 12 establishes criteria for underfrequency load shedding programs to prevent system collapse by aligning with NPCC performance requirements, ensuring frequency recovery during load-generation imbalances.

Criteria A6, Operating Reserve Criteria Approved, December 29, 2008 In the continuous operation of electric power systems, operating capacity is required to meet forecast demand, including an allowance for error, to provide protection agai...

AI summary The document outlines operating reserve criteria to ensure reliability in the NPCC region, approved in 2008. It sets minimum requirements for reserve capacity, availability, and activation, aligning with NPCC standards.

Criteria A8, Reliability Compliance Enforcement Program Approved, December 20, 2007 The NPCC Inc. Reliability Compliance and Enforcement Program (the Program) described in this document is to be used to assess and enforce compliance with N...

AI summary The NPCC Inc. Reliability Compliance and Enforcement Program (2007) establishes procedures to assess and enforce compliance with NPCC reliability criteria. Sanctions under the program do not absolve members of their obligation to comply with NPCC guidelines, and members must submit compliance plans. The program applies only to bulk power system elements classified in Document A-10.

Criteria A10, Classification of Bulk Power System Elements December 1, 2009 NPCC defines specific requirements applicable to design, operation, and protection of the bulk power system. The object of this Classification of Bulk Power System...

AI summary The document outlines NPCC's methodology for classifying bulk power system elements, emphasizing bus-based analysis, voltage class neutrality, and evaluation during system changes. It establishes criteria for inclusion/exclusion from the NPCC Bulk Power System List and defines key terms: bulk power system, local area, and significant adverse impact.

Criteria A15, Disturbance Monitoring Equipment Criteria Approved, August 23, 2007 A prompt and accurate sequence of events must be established following a disturbance to provide timely analysis and reporting of the disturbance. The importa...

AI summary This document establishes criteria for Disturbance Monitoring Equipment (DME) to ensure accurate event sequencing post-disturbance, supporting analysis and reporting. It aligns with NPCC and NERC standards (PRC-002, PRC-018) for monitoring protection equipment and validating system simulations.

NPCC Reliability Reference Directory # 1 Design and Operation of the Bulk Power System December 1, 2009

AI summary This document outlines the design and operation of the bulk power system as referenced by the Northeast Power Coordinating Council, Inc. (NPCC) in December 2009, focusing on reliability standards and practices.

Revision History Version Date Action Change Tracking (New, Errata or Revisions) Table of Contents 1.0 Introduction 1.1 Title - Design and Operation of the Bulk Power System 1.2 Directory Number 1 5 1.3 Objective 5 1.4 Effective Date – Dece...

AI summary The document outlines the 'Design and Operation of the Bulk Power System' under the NPCC Reliability Reference Directory #1, effective December 1, 2009. It includes sections on reliability standards, resource adequacy, transmission design and operating criteria, and appendices with guidelines and procedures for various aspects of power system reliability.

- 1.1 Title Design and Operation of the Bulk Power System - 1.2 Directory Number 1 - 1.3 Objective The objective of these criteria is to provide a "design-based approach" to ensure the bulk power system is designed and operated to a level...

AI summary This document outlines the design and operation criteria for the bulk power system to ensure reliability, focusing on the ability to withstand design contingencies and prevent cascading outages. It emphasizes the need for balanced resource and transmission planning to meet customer demand.

1.5 Background This Directory was developed from the NPCC A-2 criteria document - Basic Criteria for the Design and Operation of Interconnected Power Systems (May 6, 2004 version). Guidelines and Procedures for consideration in the impleme...

AI summary This section outlines the development of a Directory based on the NPCC A-2 criteria document from 2004, which establishes basic criteria for interconnected power systems. Implementation guidelines are detailed in the Appendices.

1.6.1 Functional Entities Reliability Coordinators Transmission Operators Balancing Authorities Planning Coordinators Transmission Planners Resource Planners

AI summary Section 1.6.1 lists functional entities involved in electricity system operations, including Reliability Coordinators, Transmission Operators, Balancing Authorities, Planning Coordinators, Transmission Planners, and Resource Planners. These roles reflect organizational responsibilities in grid management and reliability.

3.0 NERC ERO Reliability Standard Requirements The NERC ERO Reliability Standards containing requirements that are associated with this Directory include, but may not be limited to: - 3.1 EOP-001-0 - [Emergency Operations Planning](http://...

AI summary The document outlines NERC ERO Reliability Standards relevant to the Directory, including examples like EOP-001-0 (Emergency Operations Planning), FAC-011-2 (System Operating Limits Methodology), and MOD-010-0 (Steady-State Data for Transmission System Modeling). These standards address emergency planning, system limits, reliability coordination, and data requirements for grid modeling and simulation.

Controllable DSM - 3.12 TOP-001-1 [Reliability Responsibilities and Authorities](http://www.nerc.com/files/TOP-001-1.pdf) - 3.13 TOP-002-2 [Normal Operations Planning](http://www.nerc.com/files/TOP-002-2.pdf) - 3.14 TOP-003-0 [Planned Outa...

AI summary The document lists NERC reliability standards (TOP-001-1 to VAR-001-1) covering system performance, transmission operations, voltage control, and regional reliability assessments, emphasizing reliability responsibilities and operational planning requirements.

4.0 NPCC regional Reliability Standards Requirements None

AI summary The section on NPCC regional Reliability Standards Requirements contains no content.

5.0 NPCC Full Member, More Stringent Criteria NPCC provides a forum for coordinating the design and operations of its five Reliability Coordinator Areas. NPCC shall conduct regional and interregional studies, and assess and monitor Plannin...

AI summary The NPCC coordinates regional and interregional studies to ensure compliance with stringent criteria for the bulk power system. Reliability Coordinators, Transmission Planners, and Planning Coordinators are responsible for operating and designing their portions of the system according to these standards through committees and task forces.

5.1 General Requirements Specific system conditions may require Planning Coordinators or Reliability Coordinators to develop criteria which are more stringent than those set out herein. Any constraints imposed by these more stringent crite...

AI summary The section outlines that Planning and Reliability Coordinators may impose stricter criteria than those specified, which must be followed. However, these criteria do not apply to non-bulk power system elements or areas where instability or overloads would not endanger the bulk power system's reliability.

5.1.1 Design Criteria These design criteria will be used in the assessment of the bulk power system by each of the NPCC Transmission Planners and Planning Coordinators, and in the reliability testing at the Transmission Operator, Reliabili...

AI summary Design criteria for the bulk power system emphasize reliability testing by NPCC planners and operators, stressing system conditions through load and generation scenarios. Special Protection Systems (SPS) are to be used judiciously for contingencies, with considerations for complexity and consequences, as outlined in NPCC documents.

5.1.2 Operating Criteria Coordination among and within the Reliability Coordinator Areas of NPCC is essential to the reliability of interconnected operations. Timely information concerning system conditions shall be transmitted by the NPCC...

AI summary The text outlines operating criteria for reliability coordination within the NPCC, emphasizing bulk power system reliability, contingency management, use of special protection systems (SPS), and distinctions between normal and emergency transmission transfer capabilities to ensure inter-Reliability Coordinator Area operations remain secure and stable.

5.1.3 Data Exchange Requirements for Modeling and System Analysis It is the responsibility of NPCC and NPCC Members to protect the proprietary nature of the following information and to ensure it is used only for purposes of efficient and...

AI summary The document outlines data exchange requirements for system analysis and modeling, emphasizing NPCC's responsibility to protect proprietary information while ensuring data sharing supports reliable system operations. Reliability Coordinators and Registered Entities must provide verified data for analysis, with annual reviews and periodic verification mandated for equipment data.

5.2 Resource Adequacy – Design Criteria The probability (or risk) of disconnecting firm load due to resource deficiencies shall be, on average, not more than one day in ten years as determined by studies conducted for each Resource Plannin...

AI summary The document establishes a design criterion for resource adequacy, limiting the probability of disconnecting firm load due to resource deficiencies to no more than one day in ten years. It specifies a loss of load expectation (LOLE) of 0.1 day per year, considering factors like demand uncertainty, outages, interconnections, and transmission capabilities.

5.3 Resource Adequacy – Operating Criteria Each Balancing Authority shall have procedures in place to schedule outages and deratings of resources in such a manner that the available resources will be adequate to meet the Resource Planner's...

AI summary The text requires Balancing Authorities to schedule resource outages and deratings to meet forecasted demand and reserve requirements, referencing NPCC's Operating Reserve Criteria. It emphasizes measuring generating units' and loads' net capability for resource adequacy evaluation.

5.4 Transmission Design Criteria The portion of the bulk power system in each Planning Coordinator Area and in each Transmission Planning Area shall be designed with sufficient transmission capability to serve forecasted demand under the c...

AI summary The transmission system in Planning Coordinator and Transmission Planning Areas must be designed to handle forecasted demand, including scenarios with lost critical infrastructure. Ten-minute reserves and control mechanisms are used to adjust power flows during outages. Power transfers between areas must be considered in transmission design.

5.4.1 Stability Assessment Stability of the bulk power system shall be maintained during and following the most severe of the contingencies stated below, with due regard to reclosing . For each of the contingencies below that involve a fau...

AI summary The document outlines stability requirements for the bulk power system under severe contingencies, including fault clearing scenarios by 'system A' and 'system B' protection groups, permanent faults on generators, transmission circuits, and transformers, delayed fault clearing, and failures in circuit breakers. Specific exclusions for risk management are also noted.

5.4.2 Steady State Assessment a. Each Transmission Planner shall design its system in accordance with these criteria and its own voltage control procedures and criteria, and coordinate these with adjacent Transmission Planner Areas . Adequ...

AI summary The steady-state assessment requires transmission planners to design systems with adequate reactive power resources and controls to maintain voltage within normal pre-disturbance limits and applicable emergency limits post-contingencies. Line and equipment loadings must also adhere to these limits, emphasizing coordination with adjacent transmission areas.

5.4.3 Fault Current Assessment Each Transmission Planner and Planning Coordinator shall establish procedures and implement a system design that ensures equipment capabilities are adequate for fault current levels with all transmission and...

AI summary The section mandates that Transmission Planners and Planning Coordinators establish procedures and system designs to ensure equipment can handle fault current levels under all operating conditions, with coordination across adjacent Planning Coordinator Areas.

5.5 Transmission Operating Criteria Scheduled outages of facilities that affect inter-Reliability Coordinator Area reliability shall be coordinated sufficiently in advance of the outage to permit the affected Reliability Coordinators to ma...

AI summary The text outlines transmission operating criteria emphasizing coordination of scheduled outages, reliability notifications between Reliability Coordinators, and adjustments for protection group outages. It mandates expedited work on facilities impacting inter-Reliability Coordinator Area reliability and specifies handling of protection group outages, including assumptions about remaining protection functionality.

5.5.1 Normal Transfers Pre- contingency voltages, line and equipment loadings shall be within normal limits. Unless specific instructions describing alternate action are in effect, normal transfers shall be such that manual reclosing of a...

AI summary The section outlines requirements for maintaining bulk power system stability during contingencies, specifying fault clearing procedures, reactive power resource management, and inter-area voltage control agreements. It details scenarios such as permanent faults on generators, transmission circuits, and transformers, emphasizing stability maintenance under both normal and delayed fault clearing conditions.

5.5.2 Emergency Transfers When firm load cannot be supplied within normal limits in a Transmission Operator Area, or a portion of a Transmission Operator Area, transfers may be increased to the point where pre- contingency voltages, line a...

AI summary Emergency transfers are permitted when firm load cannot be supplied within normal limits, allowing increased transfers to emergency limits. Stability of the bulk power system must be maintained during severe contingencies, such as permanent faults or element losses, with post-contingency voltages and loadings within emergency thresholds.

5.5.3 Post Contingency Operation Immediately after the occurrence of a contingency , the status of the bulk power system must be assessed and transfer levels must be adjusted, if necessary, to prepare for the next contingency . If the read...

AI summary Post-contingency operations require immediate assessment of the bulk power system, adjustment of transfer levels, and potential use of emergency measures like voltage reduction or load shedding within 30 minutes. Pre-contingency disconnection of firm load may be necessary if other measures fail to maintain emergency limits.

5.5.4 Operation under High Risk Conditions Operating to the contingencies listed in Sections 5.5.1 and 5.5.2 is considered to provide an acceptable level of bulk power system security. Under certain unusual conditions, such as severe weath...

AI summary Operating under contingencies from Sections 5.5.1 and 5.5.2 ensures acceptable bulk power system security. However, during high-risk conditions (e.g., severe weather), temporary increases in contingency risks may require more conservative operational approaches in Transmission Operator Areas.

5.6 Extreme Contingency Assessment Extreme contingency assessment recognizes that the bulk power system can be subjected to events which exceed, in severity, the contingencies listed in Section 5.4.1. One of the objectives of extreme conti...

AI summary The section outlines extreme contingency assessment procedures for the bulk power system, focusing on evaluating severe events beyond standard contingencies. It identifies specific scenarios like loss of generating stations, transmission failures, and protection system malfunctions, emphasizing post-contingency stability, overload, and voltage collapse analysis. The goal is to ensure system resilience and address potential widespread disturbances through planning studies.

5.7 Extreme System Conditions Assessment The bulk power system can be subjected to wide range of other than normal system conditions that have low probability of occurrence. One of the objectives of extreme system conditions assessment is...

AI summary The document outlines procedures for assessing extreme system conditions on the bulk power system, including peak load scenarios and fuel shortages. It emphasizes planning studies to evaluate system robustness and dynamic performance, with responsibilities assigned to Transmission Planners and Planning Coordinators. Mitigation measures are discussed, along with a multi-step approval process for revising planning directories through NPCC and RCC.

NPCC Reliability Reference Directory # 1 Design and Operation of the Bulk Power System December 1, 2009 Revisions pertaining to the Appendices or any other portion of the document such as Links glossary terms, etc., only RCC Members will n...

AI summary The document outlines the revision process for the NPCC Reliability Reference Directory, requiring RCC Members to approve updates. It mandates triennial updates to align with NERC standards and references related NPCC documents on power system protection and emergency operations.

Appendix A - Definition of Terms Applicable emergency limits - These limits depend on the duration of the occurrence, and on the policy of the various member systems of NPCC regarding loss of life to equipment, voltage limitations, etc. Em...

AI summary Defines terms related to emergency limits, bulk power system, contingencies, and system stability in the context of power grid reliability, emphasizing definitions from NPCC and NERC frameworks.

Fault Clearing Delayed fault clearing - Fault clearing consistent with correct operation of a breaker failure protection group and its associated breakers, or of a backup protection group with an intentional time delay. High speed fault cl...

AI summary The document defines three fault-clearing types: delayed (with intentional time delays), high-speed (≤50ms), and normal (standard protection system operation). It also defines 'load' as electric power used by connected devices and introduces NPCC-specific terms like 'Firm Load' and 'Interruptible Load'.

Notes: - (a) Variously identified as Main Protection, Primary Protection, Breaker Failure Protection, Back-Up Protection, Alternate Protection, Secondary Protection, A Protection, B Protection, Group A, Group B, System 1 or System 2. - (b)...

AI summary The text defines various types of protection systems in power networks, including Main Protection, Breaker Failure Protection, and Pilot Protection. It emphasizes that pilot protection constitutes a single protection group, encompassing equipment like instrument transformers, circuit breakers, and communication facilities installed at all terminals of a power system element to ensure complete protection.

Terminal Basis One or more protection groups, as above, installed at one terminal of a power system element , typically a transmission line. Pilot Protection - A form of line protection that uses a communication channel as a means to compa...

AI summary The text defines 'Terminal Basis' as protection groups installed at power system elements, explains pilot protection using communication channels for line protection, and describes 'rating' as operational limits of system elements under specified conditions.

Reclosing - Autoreclosing The automatic closing of a circuit breaker in order to restore an element to service following automatic tripping of the circuit breaker. Autoreclosing does not include automatic closing of capacitor or reactor ci...

AI summary The text defines technical terms related to circuit breaker operations (autoreclosing, manual reclosing, synchronism-check) and explains reliability in electric systems, emphasizing adequacy and security. It details relay functions and conditions for safe system restoration post-fault.

Appendix B - Guidelines and Procedures for NPCC Area Transmission Reviews

AI summary Appendix B outlines guidelines and procedures for NPCC Area Transmission Reviews, focusing on ensuring reliability, compliance with NERC/IEEE standards, and stakeholder coordination. It emphasizes processes for evaluating transmission system performance, addressing reliability concerns, and aligning with regulatory requirements.

1.0 Introduction NPCC has established a Reliability Assessment Program to bring together work done by NPCC, Transmission Planners and Planning Coordinators relevant to the assessment of bulk power system reliability . As part of the Reliab...

AI summary The NPCC's Reliability Assessment Program involves periodic reviews of bulk power system reliability by the Task Force on System Studies (TFSS) and annual assessments by Planning Coordinators. These efforts ensure compliance with NPCC and NERC standards, with NPCC overseeing inter-area issues and Planning Coordinators handling intra-area problems.

2.0 Purpose of Area Review Presentation The purpose of the presentation associated with an Area Transmission Review is to demonstrate that the Planning Coordinators planned transmission system, based on its projection of available resource...

AI summary The Area Review Presentation aims to confirm that the Planning Coordinators' transmission system meets NPCC Basic Criteria, ensuring reliability of the NPCC Interconnected Systems. It involves reviewing Special Protection Systems and assessing risks from Dynamic Control Systems (DCS) failures, as defined by NERC standards.

Introduction - Reference the most recent Area Comprehensive Review and any subsequent Intermediate or Interim reviews as appropriate. - Describe the type and scope of this review. - For a Comprehensive Review, describe the existing and pla...

AI summary The document outlines requirements for a Comprehensive or Intermediate Review of the bulk power system, emphasizing analysis of system facilities, load models, contingency evaluations, voltage performance, and stability assessments. It references NPCC guidelines and details the scope of studies, including load flows, protection systems, and planned outages.

d) Fault Current Assessment - Discuss the methodology and assumptions used in the fault current assessment. (An Intermediate Review may refer to the discussion from the last Comprehensive Review.) - Discuss instances where fault levels exc...

AI summary The text outlines requirements for fault current assessment methodology, mitigation of equipment limitations, and changes in fault levels near other Planning Coordinator Areas. It also addresses extreme contingency assessments, including scope, selected contingencies, load flow and stability studies, and potential system changes to address severe contingencies.

Extreme System Condition Assessment - a) Discuss the scope of the analyses. - b) Discuss and/or refer to significant load flow studies showing the effect on the steady state performance of extreme system conditions as specified in Section...

AI summary The document outlines requirements for assessing extreme system conditions, including load flow and stability studies, contingency evaluations, and reviews of Special Protection Systems (SPS). It emphasizes analyzing severe system conditions, validating SPS effectiveness, and ensuring interregional coordination.

Review of Dynamic Control Systems (DCSs) For those DCSs whose failure or misoperation may have an inter-Planning Coordinator Area or interregional effect, discuss and/or refer to appropriate stability studies analyzing the consequences of...

AI summary The document outlines requirements for reviewing Dynamic Control Systems (DCSs) that could impact interregional grid stability. It mandates stability studies referencing the JWG-1 report, distinguishing between Comprehensive Reviews (all DCSs) and Intermediate Reviews (new or changed systems).

6.0 Format of Presentation - Interim Review Introduction of Interim Review Reference the most recent Comprehensive Review and any subsequent Intermediate or Interim Reviews as appropriate. Changes in Facilities (Existing and Planned) and F...

AI summary The document outlines the format for interim reviews, including updates on load forecasts, generation resources, transmission facilities, and special protection systems. It emphasizes assessing the impact on the reliability of the interconnected bulk power system.

7.0 Documentation The documentation required for a Comprehensive or Intermediate Review should be in the form of a report addressing each of the elements of the above presentation format. The report should be accompanied by the Planning Co...

AI summary The document outlines documentation requirements for Comprehensive, Intermediate, and Interim Reviews, emphasizing reports on bulk power system reliability, system changes, and supporting materials like maps, diagrams, and summaries. Interim Reviews require concise 5-page summaries assessing reliability impacts.

Appendix C - Procedure for Testing and Analysis of Extreme Contingencies

AI summary Appendix C outlines procedures for testing and analyzing extreme contingencies in power systems, ensuring reliability and compliance with regulatory standards. It emphasizes methodologies to assess risks and implement safeguards against severe disruptions.

1.0 Introduction Extreme Contingencies (ECs) are tested "as a measure of system strength", in order to identify potential patterns of weakness in the bulk power transmission system. This procedure for the testing and analysis of ECs should...

AI summary The document outlines procedures for testing Extreme Contingencies (ECs) to assess system strength and identify weaknesses in the bulk power transmission system, emphasizing their application in NPCC-wide reliability studies and multi-regional efforts.

2.0 Choosing Contingencies for Testing The ECs are defined in the NPCC Directory #1- Design and Operation of the Bulk Power System , and in the NERC Standards. Testing should focus on those ECs expected to have the greatest potential effec...

AI summary The text outlines criteria for selecting contingencies in power system reliability studies, emphasizing ECs (Equipment Contingencies) from NPCC and NERC standards. Key focus areas include major angular power shifts, reversal of power transfers, and review of prior Planning Coordinator testing to prioritize high-impact scenarios.

3.0 Modeling Assumptions The assumed generation dispatch is a major consideration in all EC testing. In general, EC testing should use a dispatch pattern considered to be highly probable for the year and load level being studied. Intra-Rel...

AI summary Modeling assumptions for EC testing emphasize using probable dispatch patterns and 75% flow duration inter-area transfers. Planning Coordinators must define load representations for reliability studies, including transient stability tests, ensuring tests are severe but not extreme.

4.0 Evaluating Individual Test Results A question in evaluating the results of a particular test run is - "Does the system "pass" or "fail" for this contingency ?" While in the final analysis this is a matter of informed engineering judgme...

AI summary The document outlines criteria for evaluating power system test results, emphasizing factors like equipment loading, voltage violations, dynamic control systems, and system stability. It stresses avoiding simplistic 'pass/fail' labels, instead requiring detailed analysis of failures, their causes, and impacts on the bulk power system.

5.0 Evaluating the Results of a Program of EC Testing The NPCC Directory #1 document - " Design and Operation of Bulk Power System ", calls for testing of Extreme Contingencies (EC) "as a measure of system strength." The results of all NPC...

AI summary The NPCC Directory #1 emphasizes testing Extreme Contingencies (EC) to assess system strength, with reliability studies guiding planners to identify systemic weaknesses rather than focusing on specific contingencies. The text stresses distinguishing between failures due to isolated contingencies and broader system vulnerabilities, while highlighting mitigation actions by member systems.

NPCC Directory #1 Appendix C of possible general system weakness. In these instances, the results should be specifically referred to the affected Planning Coordinator or Planning Coordinators for further and more detailed investigation wit...

AI summary The text outlines procedures for addressing potential system weaknesses by referring results to affected Planning Coordinators for detailed investigation, with subsequent reporting to the Northeast Power Coordinating Council (NPCC). This emphasizes coordination and accountability in grid reliability efforts.

Appendix D - Guidelines for Area Review of Resource Adequacy

AI summary Appendix D outlines guidelines for conducting an area review of resource adequacy, focusing on ensuring sufficient electricity generation and transmission capacity to meet demand. It likely addresses reliability standards, planning processes, and regulatory considerations for maintaining grid stability in Nova Scotia.

2.0 Purpose of Presentation The purpose of the presentation associated with a resource adequacy review is to show that each Planning Coordinator's proposed resources are in accordance with the NPCC Directory #1 - Design and Operation of th...

AI summary The presentation aims to demonstrate that Planning Coordinators' proposed resources comply with NPCC Directory #1's design and operation criteria for the bulk power system. The Task Force's review ensures resource adequacy but does not replace the responsibility of Planning Coordinators to assess their systems against NPCC Basic Criteria.

4.3 Introduction - 4.3.1 Reference the previous NPCC Area Review. - 4.3.2 Compare the proposed resources and load forecast covered in this NPCC review with that covered in the previous review

AI summary The introduction references the previous NPCC Area Review and outlines a comparison between the proposed resources and load forecasts in this review and those from the prior review, focusing on changes in resource planning and demand projections.

4.4 Resource Adequacy Criterion - 4.4.1 State the Planning Coordinator's resource adequacy criterion. - 4.4.2 State how the Planning Coordinator criterion is applied; e.g., load relief steps. - 4.4.3 Summarize resource requirements to meet...

AI summary The section outlines requirements for the Planning Coordinator's resource adequacy criterion, including application methods (e.g., load relief steps), resource requirements over time, interconnection values, comparisons with NPCC criteria, and discussions of resource adequacy studies since the last Area Review.

4.5 Resource Adequacy Assessment - 4.5.1 Evaluate proposed resources versus the requirement to reliably meet projected electricity demand assuming the Planning Coordinator's most likely load forecast. - 4.5.2 Evaluate proposed resources ve...

AI summary The section outlines a four-part assessment of resource adequacy, focusing on evaluating proposed resources against load forecasts, discussing reliability impacts from uncertainties, and reviewing market rule changes. It emphasizes reliability planning under different load scenarios and mechanisms to mitigate risks.

4.6 Proposed Resource Capacity Mix - 4.6.1 Discuss any reliability impacts resulting from the proposed resources fuel supply and transportation or environmental considerations. - 4.6.2 Describe available mechanisms to mitigate any potentia...

AI summary The document outlines requirements for assessing reliability impacts of resource capacity mix, including fuel supply, environmental considerations, and compliance with regulations. It mandates an Annual Interim Review detailing load forecasts, generation resources, emergency procedures, and reliability assessments based on engineering studies and joint analyses.

A. Description of Resource Reliability Model - 1.1 Load Model - 1.1.1 Description of the load model and basis of period load shapes. - 1.1.2 How load forecast uncertainty is handled in model. - 1.1.3 How the electricity demand and energy p...

AI summary The document outlines the Resource Reliability Model's approach to load forecasting, resource representation, and reliability analysis. It details handling load uncertainty, supply-side resource ratings, unavailability factors, interconnected system modeling, and reliability impacts of market rules, emphasizing accuracy in resource and demand-side management representations.

Appendix E - Guidelines for Requesting Exclusions to Sections 5.4.1 (B) and 5.5.1 (B) of NPCC Directory #1 – Design and Operation of the Bulk Power System

AI summary Appendix E outlines guidelines for requesting exclusions to Sections 5.4.1 (B) and 5.5.1 (B) of NPCC Directory #1, which govern the design and operation of the bulk power system. The document emphasizes procedural requirements for exclusion requests, involving NSPI and NPCC.

1.0 Introduction The Northeast Power Coordinating Council (NPCC) was formed to promote the reliability and efficiency of electric service of the interconnected bulk power system of the members of the NPCC by extending the coordination of t...

AI summary The Northeast Power Coordinating Council (NPCC) ensures reliability and efficiency of the interconnected bulk power system through standardized design and operation criteria. Specific contingencies, such as simultaneous faults on multi-circuit towers, are addressed with risk-based exclusion procedures requiring Reliability Coordinating Committee (RCC) approval. Directory #1 outlines these standards and exclusion processes.

2.0 Documentation The documentation supporting a request for exclusion to Sections 5.1(b) and 6.1(b) of the Basic Criteria must include the following: - 2.1 A description of the facilities involved, including geographic location, length an...

AI summary The documentation for a request to exclude Sections 5.1(b) and 6.1(b) of the Basic Criteria must detail facility descriptions, risk factors, consequences of multi-circuit contingencies, historical outage performance, and estimated contingency frequencies for planned facilities, emphasizing risk assessment and system reliability implications.

Appendix F – Procedure for Operational Planning Coordination

AI summary Appendix F outlines procedures for operational planning coordination, likely involving entities like NSPI and NSUARB. The document addresses system reliability and regulatory processes, though specific arguments or citations are not detailed in the provided text.

1.0 Introduction The Reliability Coordinators (RC) of the Northeast Power Coordinating Council, Inc. (NPCC) require access to the security data specified in this procedure in order to adequately assess the reliability of the NPCC bulk powe...

AI summary The Northeast Power Coordinating Council (NPCC) requires security data sharing to ensure bulk power system reliability, emphasizing coordination among reliability coordinators, outage scheduling, and adherence to NERC confidentiality agreements for system protection and reliability.

2.0 Load/Capacity Forecasts 2.1 Twice yearly, by May 15th and November 15th respectively, the Operations Planning Working Group (CO 12) will perform a summer and winter assessment for the next season. The methodology and format of the seas...

AI summary The document outlines procedures for seasonal load/capacity assessments by the Operations Planning Working Group (CO 12), using NPCC Document C-45 methodology. Results are reviewed by NPCC's TFCO and RCC. Weekly capacity margin reviews by RC Areas are required, with mitigation measures for deficiencies or light load conditions.

3.0 Generator Outage Coordination 3.1 Each RC Area should exchange current and expected critical generation outages.

AI summary Section 3.1 mandates that each Reliability Coordinating Committee (RC) Area must exchange information on current and anticipated critical generation outages to enhance coordination and reliability within the power system.

4.0 Transmission Outage Coordination 4.1 Advance Planning of Transmission Facility Outages NPCC Document A-2, Basic Criteria for Design and Operation of Interconnected Power Systems, requires that scheduled outages of transmission faciliti...

AI summary The section outlines requirements for advance coordination of transmission facility outages to ensure reliability between Reliability Coordinating (RC) Areas, referencing NPCC Document A-2. RCs must exchange critical outages and maintain a Facilities Notification List with interconnected neighbors.

4.2 Facilities Notification List The NPCC Facilities Notification List, Attachment D, has two components: - 1) the NPCC Transmission Facilities Notification List; and - 2) the list of NPCC Type I special protection systems . The Facilities...

AI summary The NPCC Facilities Notification List includes transmission facilities and Type I special protection systems, updated annually by RC Areas with coordination via TFCO and TFSP. Revisions are handled securely due to sensitive information, and temporary network changes may impact unlisted facilities, requiring timely RC notifications.

4.3 Notifications of Work - 4.3.1 Notification requirements should be defined in interconnected coordination agreements. The time frames identified below are the minimum notification requirements. - 4.3.2 The initiating RC will advise affe...

AI summary The section outlines requirements for notifying Reliability Coordinators (RCs) about planned and emergency outages on critical facilities. Notifications must be submitted at least two working days in advance, with prompt analysis by RC Areas. Emergency actions are permitted without prior notice, but routine outages impacting reliability must be rescheduled. Coordination agreements govern additional reporting for protection outages.

5.0 Data Providers NPCC entities are to provide the data in order to adequately assess the reliability of the NPCC bulk power system.

AI summary NPCC entities are required to provide data to evaluate the reliability of the NPCC bulk power system, ensuring accurate assessments of system performance and compliance with regulatory standards.

6.0 Specific Communications Conditions in an RC Area that may have an impact on another RC Area should be communicated in a clear and timely manner. Specific communications are conducted as follows:

AI summary The text emphasizes the importance of clear and timely communication between Reliability Coordinators (RC) when conditions in one RC Area may affect another, ensuring effective coordination and reliability.

6.1 Weekly Each Thursday a conference call will be initiated by the NPCC Staff to discuss operations expected during the seven-day period starting with the following Sunday. Operations personnel from the NPCC RC Areas will participate. In...

AI summary Weekly conference calls initiated by NPCC Staff to discuss operations, capacity margins, and deficiencies. RC Areas prepare data and review margins. Emergency calls may be recommended if deficiencies or adverse conditions are identified.

6.2 Emergency Preparedness Conference Call Whenever adverse system operating or weather conditions are expected, any RC Area may request the NPCC Staff to arrange an Emergency Preparedness Conference Call (NPCC Document C-01) to discuss op...

AI summary The document outlines a procedure for arranging Emergency Preparedness Conference Calls when adverse operating or weather conditions are anticipated. An RC Area may request NPCC Staff to coordinate discussions with operations management from NPCC RC Areas and neighboring systems to address operational details.

6.3 Daily Conference Calls Each of the NPCC Reliability Coordinator Area control rooms participate in a regularly scheduled daily conference call. The goal of this call is to alert NPCC Reliability Coordinators of any potential emerging pr...

AI summary Daily conference calls involve NPCC Reliability Coordinators to discuss credible events that could impact their ability to serve load, meet operating reserve obligations, or burden the Interconnection. The goal is to alert coordinators to emerging operational risks.

Procedure for Operational Planning Coordination – Attachment A

AI summary Attachment A outlines procedures for operational planning coordination, likely involving regulatory bodies and entities in Nova Scotia. It addresses reliability standards, planning processes, and stakeholder collaboration, with references to organizations like NSPI and NSUARB.

Load and Capacity Table Instructions and

AI summary The document outlines instructions for preparing a Load and Capacity Table, likely related to system reliability, resource planning, and regulatory compliance in Nova Scotia's energy sector. It may address methodologies for assessing generation capacity, load forecasts, and reliability metrics.

CONDITIONS FOR DISCUSSION Items of particular concern that should be discussed during a conference call include, but are not limited to, the following: - anticipated weather; - largest first and second contingencies; - operating reserve re...

AI summary The document outlines conditions for discussion during a conference call, emphasizing system reliability, operational reserves, capacity deficiencies, fuel shortages, voltage conditions, and contingency planning. Key topics include system reliability, emergency transfers, and special protection systems.

Appendix G - Procedures for Inter Reliability Coordinator Area Voltage Control

AI summary Appendix G outlines procedures for managing voltage control between inter-connected reliability coordinator areas, focusing on coordination mechanisms and operational standards to ensure grid stability and compliance with reliability protocols.

1.0 Introduction This Procedure provides general principles and guidance for effective inter-Transmission Operator Area voltage control, consistent with the NPCC, Directory #1, "Design and Operation of the Bulk Power System," and applicabl...

AI summary This procedure outlines principles for coordinated inter-Transmission Operator Area voltage control, aligning with NPCC and NERC standards. It emphasizes the necessity of coordination to prevent equipment damage, voltage collapse, and reduce losses, while acknowledging local control effectiveness and reactive power management.

2.0 Principles Each Transmission Operator develops, and operates in accordance with, its own voltage control procedures and criteria which are consistent with NPCC, Inc. Criteria and NERC Standards. Adjacent Transmission Operators should b...

AI summary The principles outline voltage control procedures for Transmission Operators, emphasizing coordination with NPCC and NERC standards. Key considerations include reactive power management, voltage regulating transformers, tie line losses, and static VAR compensators to ensure reliable grid operations.

3.0 Procedure Transmission Operators maintain normal voltage conditions, in accordance with their own individual or joint operating policies, procedures and applicable interconnection agreements. In the event the system state changes to an...

AI summary Transmission Operators are responsible for maintaining normal voltage conditions through established policies and interconnection agreements. If abnormal voltage conditions occur, the originating operator must take immediate corrective action, seeking assistance from other operators if necessary due to insufficient reactive resources.

3.1 Normal Voltage Conditions The bulk power system is operating with Normal Voltage Conditions when: - actual voltages are within applicable normal (pre- contingency ) voltage ranges; and - expected post- contingency voltages are within a...

AI summary The document outlines requirements for maintaining normal voltage conditions in the bulk power system, emphasizing pre- and post-contingency voltage ranges, reactive reserves, and coordination between Transmission Operators. It details procedures for triennial monitoring and reporting by TFCO and RCC, ensuring alignment with NPCC standards.

NPCC Regional Reliability Reference Directory # 2 Emergency Operations Task Force on Coordination of Operations Revision Review Record: October 21, 2008 Adopted by the Members of the Northeast Power Coordinating Council, Inc. this October...

AI summary The NPCC Regional Reliability Reference Directory #2 Emergency Operations was adopted by the Northeast Power Coordinating Council (NPCC) on October 21, 2008, following a recommendation by the Reliability Coordinating Committee (RCC). This action was taken in accordance with Section VIII of the NPCC's Amended and Restated Bylaws dated July 24, 2007.

1.0 Introduction - 1.1 TitleEmergency Operations - 1.2 Directory Number 2 - 1.3 Objective The purpose of this Directory is to present the basic factors to be considered in formulating plans and procedures to be followed in an emergency or...

AI summary This document outlines the objectives of the NPCC Emergency Operations Directory, focusing on minimizing service interruptions, system disturbances, and public hazards during emergencies. It emphasizes coordination among reliability coordinators, balancing authorities, and transmission operators, with an effective date of October 21, 2008.

3.0 NERC ERO Reliability Standard Requirements The NERC ERO Reliability Standards containing Requirements that are associated with this Directory include, but may not be limited to: - 3.1 BAL-005: Automatic Generation Control 3.2 COM-001:...

AI summary The document outlines NERC ERO Reliability Standards applicable to the proceeding, including requirements for automatic generation control, emergency operations planning, transmission operations, and reliability coordination. Specific standards listed include BAL-005, COM-001, EOP-001, and others, emphasizing compliance with regional and system-wide reliability protocols.

5.0 NPCC Full Member, More Stringent Criteria These Criteria are in addition, more stringent or more specific than the NERC or any Regional Reliability standard requirements

AI summary The NPCC Full Member criteria are additional, more stringent, and more specific than NERC or Regional Reliability standards. This establishes higher reliability requirements for NPCC members compared to general industry benchmarks.

5.1 General Criteria Normal Transfer Capabilities shall be observed unless there is insufficient capacity or voltage support in a Balancing Authority or Transmission Operator area , in which case Emergency Transfer Capabilities may be used...

AI summary The section outlines the use of Normal and Emergency Transfer Capabilities, specifying that Emergency ones are only to be used when there's insufficient capacity or voltage support, and must be documented in writing.

5.2 Manual Load Shedding Requirement Each Balancing Authority shall have the capability of manually shedding at least fifty percent of its area load in ten minutes or less. Manual load shedding plans shall not interrupt bulk power system e...

AI summary Section 5.2 mandates that Balancing Authorities must be capable of manually shedding at least 50% of their load within 10 minutes, without disrupting bulk power system elements. Annual reviews and voltage/loading studies by Transmission Operators are required, with compliance monitored by the NPCC Compliance Committee. Revisions to the document require RCC approval and adherence to NPCC bylaws.

Appendix A Definition of Terms1 Automatic Generation Control (AGC) — Equipment that automatically adjusts a Control Area 's generation to maintain its interchange schedule plus its share of frequency regulation. The following AGC modes are...

AI summary Appendix A defines technical terms related to power system operations, including Automatic Generation Control (AGC), bulk power systems, capacity, and emergency protocols. Terms address system reliability, generation control modes, and definitions for interchanges, interfaces, and load management, emphasizing NPCC and IEEE standards.

NPCC Specific Definitions: Firm Load — Loads that are not Interruptible Loads . Interruptible Load — Loads that are interruptible under the terms specified in a contract. - Load Shedding The process of deliberately removing (either manuall...

AI summary The text defines NPCC-specific terms related to power system reliability and operations, including load shedding, reliability, adequacy, security, and special protection systems. Key concepts include system stability, voltage reduction, and the distinction between interruptible and firm loads.

Appendix B Guideline and Procedure for Emergency Operation

AI summary Appendix B outlines guidelines and procedures for emergency operations, focusing on system reliability and response protocols. It references regulatory frameworks and operational standards relevant to Nova Scotia's energy sector.

1.0 Introduction This Appendix provides the guidelines and procedures for anticipating and operating under emergency conditions. These guidelines and procedures are intended to provide specific instructions to the System Operator during su...

AI summary This Appendix outlines guidelines for emergency operations, targeting the System Operator in NPCC Balancing Authority, Transmission Operator, and Reliability Coordinator areas. The goal is to minimize emergency impacts and ensure containment through specific procedures.

2.0 Minimizing the Impact of Events - 2.1 It is recognized that provisions are made in the design of a power system for the satisfactory performance of the system during certain faults or incidents of equipment failure. It is also recogniz...

AI summary The document outlines measures to ensure power system reliability during faults and equipment failures, emphasizing operating reserves, automatic generation control, voltage limits, and emergency protocols. It mandates adherence to NPCC criteria for voltage conditions and procedures for correcting abnormalities.

NPCC Directory D2 Emergency Operations - 3.2.5 If two or more Transmission Operators are experiencing voltage problems simultaneously, they will assist each other as above to the extent feasible. If the problem is so severe as to require t...

AI summary The NPCC Directory D2 outlines procedures for Transmission Operators to address simultaneous voltage issues, emphasizing mutual assistance and reactive power flow management. If external conditions cause voltage anomalies, operators must identify the source, communicate, and take corrective actions, including load shedding if necessary, to stabilize the system.

4.0 Actions to Contain an Emergency If preventative measures as outlined under Sections 2.0 and/or 3.0 have not been adequate, the Balancing Authority or the Transmission Operator experiencing the abnormal conditions may need to declare an...

AI summary The section outlines emergency actions by Balancing Authorities and Transmission Operators to address transmission emergencies and maintain system reliability, referencing preventative measures from earlier sections. It details scenarios where one area's operations impact another's reliability and specifies actions for frequency/ACE control issues.

NPCC Regional Reliability Reference Directory # 3 Maintenance Criteria for Bulk Power System Protection Task Force on System Protection Revision Review Record: July 11, 2008 Adopted by the Members of the Northeast Power Coordinating Counci...

AI summary The Northeast Power Coordinating Council (NPCC) adopted maintenance criteria for bulk power system protection on July 11, 2008, following a recommendation by the Reliability Coordinating Committee (RCC) under Section VIII of the NPCC Amended and Restated Bylaws.

1.6.2 Facilities These criteria shall apply to all protection of the NPCC bulk power system , including Type I special protection systems and protection required for the NPCC Automatic Underfrequency Load Shedding Program. Automatic underf...

AI summary This section outlines criteria for protecting the NPCC bulk power system, including Type I special protection systems and automatic underfrequency load shedding programs. These systems, though not located at bulk power stations, directly impact system operations during emergencies and are thus subject to regulatory oversight.

3.0 NERC Reliability Standard Requirements The NERC Reliability Standards containing Requirements that are associated with this Directory include: - 3.1 PRC-005-1 Transmission and Generation Protection System Maintenance and Testing - 3.2...

AI summary The document outlines NERC Reliability Standards requiring maintenance, testing, and documentation of transmission and generation protection systems, UFLS equipment, and special protection systems. These standards ensure grid reliability and compliance with regulatory requirements.

4.0 NPCC Regional Reliability Standard Requirements None developed at this time.

AI summary No NPCC Regional Reliability Standard Requirements have been developed at this time. The section is currently unaddressed, indicating a potential gap in regulatory compliance or planning.

5.0 NPCC Full Member, More Stringent Criteria

AI summary Section 5.0 outlines the Northeast Power Coordinating Council's (NPCC) more stringent criteria for full membership, likely related to reliability standards or regulatory compliance requirements within the Nova Scotia regulatory proceeding.

5.1 General Criteria Minimum periodic testing of each protection group shall be conducted to verify that the protection group is capable of performing its intended protection function. Such testing shall include protection assembly testing...

AI summary Mandatory periodic testing of protection groups is required to ensure their ability to perform intended protection functions. Testing includes assembly and system testing, with procedures and facilities needing to ensure proper test overlap for reliable protective equipment operation.

5.2 Protection Assembly Testing Requirements Refer to Figure 1, equipment marked as [1] The following Protection Assembly testing shall be performed on an interval not exceeding that specified in Table 1 for bulk power system protection gr...

AI summary Section 5.2 outlines testing requirements for Protection Assemblies in the bulk power system, specifying intervals based on Table 1. Equipment referenced in Figure 1 (marked [1]) must undergo these tests to ensure reliability.

5.2.1 Make visual inspections, - 5.2.2 Verify inputs and outputs, - 5.2.3 Confirm that the intended version of software is installed (microprocessor-based relays ), - 5.2.4 Verify correct protection operation, - 5.2.5 Verify the integrity...

AI summary The section outlines procedures for verifying equipment integrity and correct operation, including visual inspections, software version confirmation, protection system verification, and transformer circuitry checks. Emphasis is placed on ensuring accurate relay function and secondary quantity inputs for microprocessor-based relays.

- (1) Non-Self Monitored protection assemblies include electromechanical relays and solid state relays . - (2) Microprocessor-based protection assemblies where the principal fault-sensing and logic components include self monitoring or sel...

AI summary The document outlines testing requirements for protection assemblies and systems, including non-self monitored relays, microprocessor-based relays with self-monitoring, and DC circuit testing for protection groups. It emphasizes verifying the operation of protection equipment and ensuring system reliability.

TABLE 2 INTERVALS FOR DC CIRCUIT TEST TRIPPING Non-Monitored Monitored Note (1) DC Circuit Tripping 4 years 6 years Note (1): Trip coil and DC circuit continuity is continuously monitored to an Operator.

AI summary Table 2 outlines the intervals for DC circuit test tripping, distinguishing between non-monitored and monitored conditions. The monitored condition includes continuous monitoring of trip coil and DC circuit continuity by an operator, with intervals set at 6 years compared to 4 years for non-monitored conditions.

5.6.2 Channel Health For trip equipment which uses frequency shift keying (FSK) mode of communication, such as Power Line Carrier systems, the ability to perform its intended trip function shall be verified every twelve months. This testin...

AI summary The text outlines testing requirements for trip equipment using FSK communication, such as Power Line Carrier systems, mandating annual verification of trip functionality. Monthly signal adequacy tests and annual function checks are required for non-continuously monitored systems like on/off Power Line Carrier, while continuously monitored systems are exempt from annual testing.

5.7 Underfrequency Load Shedding and Generator Trip Testing Requirements Protection group DC circuit tests for protection required by the NPCC Automatic Underfrequency Load Shedding Program need not be performed more frequently than the pr...

AI summary The NPCC Automatic Underfrequency Load Shedding Program's DC circuit tests need not be more frequent than other protection tests on the same breaker. Proper coordination of generator underfrequency tripping is required, with relays for 20 MW+ generators calibrated at intervals not exceeding those in Table 1.

7.0 Compliance Monitoring Adherence to requirements in this Directory must be reported in a manner and form designated by the Compliance Committee. Exceptions to the requirements stipulated herein are acceptable if the exceptions are compl...

AI summary The section outlines compliance reporting requirements, exception handling, revision processes involving the Task Force on System Protection and RCC, and updates aligned with NERC standards. Revisions require NPCC Open Process review, RCC approval, and Full Member Representative final approval for revised sections.

Appendix A Definition of Terms - Bulk power system The interconnected electrical systems within northeastern North America comprising generation and transmission facilities on which faults or disturbances can have a significant adverse imp...

AI summary Defines key terms like bulk power system, element, and load, explaining their roles in the electrical grid and reliability. Terms are relevant to system reliability and infrastructure components.

NPCC Specific Definitions: Firm Load — Loads that are not Interruptible Loads . Interruptible Load — Loads that are interruptible under the terms specified in a contract. - Load Shedding the process of deliberately removing (either manuall...

AI summary The text defines key terms related to power system reliability, including Firm Load, Interruptible Load, Load Shedding, and Protection. These definitions emphasize system integrity, automatic corrective actions, and load management during abnormal conditions.

Notes: - (a) Variously identified as Main Protection , Primary Protection , Breaker Failure Protection , Back-Up Protection , Alternate Protection , Secondary Protection , A Protection , B Protection , Group A, Group B, System 1 or System...

AI summary The text outlines various terminology used to describe protection systems, including Main Protection, Primary Protection, and Breaker Failure Protection, noting their interchangeable usage. It specifies that Pilot protection is classified as a single protection group.

Element Basis One or more protection groups; including all equipment such as instrument transformers, station wiring, circuit breakers and associated trip/close modules, and communication facilities; installed at all terminals of a power s...

AI summary The text defines 'protection groups' as sets of equipment including instrument transformers, circuit breakers, and communication facilities installed at all terminals of a power system element to ensure its complete protection.

Terminal Basis One or more protection groups, as above, installed at one terminal of a power system element , typically a transmission line. Pilot Protection — a form of line protection that uses a communication channel as a means to compa...

AI summary Defines protection systems, relays, and special protection systems (SPS), noting that SPS includes actions to maintain stability through load or generation changes, excluding automatic underfrequency load shedding (UFLS) and conventionally switched devices.

Appendix B Guideline and Procedure for Maintenance of Bulk Power System Protection

AI summary This appendix outlines guidelines and procedures for maintaining bulk power system protection, focusing on reliability and coordination within Nova Scotia's regulatory framework. It addresses roles of entities like NSPI and NSUARB in ensuring system integrity.

2.1 Generator Under-frequency Tripping For generators rated less than 20 MW, consideration may be given to verifying the calibration of generator underfrequency relays at an interval not exceeding that specified in Table 1.

AI summary The text specifies that for generators rated below 20 MW, underfrequency relay calibration verification intervals should not exceed those outlined in Table 1, emphasizing maintenance protocols for reliability.

3.1 Testing of Microprocessor-Based Relays For the purposes of maintenance testing, microprocessor-based relays or Intelligent Electronic Devices (IEDs), can be viewed as being composed of four sections: - 3.1.1 Analog Input Section; - 3.1...

AI summary The document outlines the four sections of microprocessor-based relays (or IEDs) for maintenance testing: analog input, digital input/output, processor, and power supply. This categorization aids in systematic testing procedures for reliability and performance evaluation.

3.2 Analog Input Section Measurements of magnitude and angle (calculate where not available directly) of metered values should be compared with known quantities. This supposes that the device uses the same hardware for both protection and...

AI summary The section emphasizes comparing measured values with known quantities and conducting calibration tests if hardware differs between protection and metering. It stresses the necessity of phase angle measurements due to potential changes in filtering components over time, ensuring accurate system reliability.

3.3 Digital Input and Output Sections Each digital input and output that is utilized should be verified for proper functions.

AI summary The section emphasizes the necessity of verifying the proper functionality of all digital input and output systems. This verification is critical to ensuring operational reliability and compliance with regulatory standards in power system management.

3.3.1 Inputs Operation of all used physical inputs should be verified by applying the DC control voltage, and observing associated display, or the computer interface.

AI summary Verification of physical inputs requires applying DC control voltage and observing displays or computer interfaces to ensure proper operation.

3.3.2 Outputs Outputs of the IED should be verified either by: - 3.3.2.1 Asserting the output element using appropriate relay commands and observe the status of the output relay, or; - 3.3.2.2 Where such features are not available, the app...

AI summary The text outlines two methods for verifying outputs of Intelligent Electronic Devices (IEDs): using relay commands to observe output relay status, or verifying output contacts via logic settings if relay features are unavailable.

3.4 Processor Section The processor section samples the analog and digital inputs, executes the algorithm and logic, and provides the outputs. It includes program memory, non-volatile memory for settings and volatile memory for sequence of...

AI summary The processor section handles analog/digital inputs, executes algorithms, and manages memory types (program, non-volatile, volatile) for relay operations. It emphasizes self-checking and verifies downloaded settings/firmware against official copies to ensure correct relay functionality.

3.5 Power Supply Section Most microprocessor-based IEDs provide measurement of the power supply voltages and/or continuously monitor the power supply voltages, and provide a relay failure alarm if they go out of limits. Where these values...

AI summary The section discusses microprocessor-based IEDs monitoring power supply voltages, triggering relay failure alarms if voltages exceed limits. It emphasizes checking these values against specified ranges or detecting loss of DC voltage to the power supply as critical verification methods.

3.6 Integrity Testing This test is intended to verify the integrity of operation of the relay program execution and the processing of the phase voltages and current signals. Verify the correct operation of one of the three-phase protection...

AI summary This section outlines integrity testing procedures for relay programs, focusing on verifying correct operation of phase voltage and current signal processing. It emphasizes testing single-phase relays and distance relay zones (A-G, B-G, C-G) to ensure proper protection element functionality.

3.7 Multi-Processor Based IEDs Most relays are designed using a single processor; however, some relay designs use multiple processors. If the processing is divided among several processors, then tests should be conducted to include testing...

AI summary The section discusses testing requirements for multi-processor based intelligent electronic devices (IEDs), specifically relays. It emphasizes that testing must cover functions executed by each processor, with examples highlighting phase and ground element testing when multiple processors are used. Manufacturer manuals are referenced for hardware configuration verification.

NPCC Regional Reliability Reference Directory # 4 Bulk Power System Protection Criteria Task Force on System Protection Revision Review Record: December 01, 2009 Adopted by the Members of the Northeast Power Coordinating Council, Inc. Dece...

AI summary The NPCC Regional Reliability Reference Directory #4 outlines bulk power system protection criteria adopted by the Northeast Power Coordinating Council on December 1, 2009, following recommendations from the Reliability Coordinating Committee. The criteria are based on the NPCC's amended bylaws dated July 24, 2007.

1.6.2.2 Existing Facilities It is the responsibility of individual companies to assess the protection systems at existing facilities and to make modifications which are required to meet the intent of these criteria as follows. 1.6.2.2.1 Pl...

AI summary Companies must assess and modify protection systems at existing facilities to meet criteria. Upgrades to bulk power system (BPS) facilities requiring assessments if they don't meet criteria, with reporting via specified forms for TFSP review.

1.6.2.2.2 Facility Classification Upgraded to Bulk Power System . These criteria apply to all existing facilities which become classified as bulk power system . A mitigation plan shall be required to bring such a facility into compliance w...

AI summary Facilities upgraded to Bulk Power System must implement mitigation plans. If physical separation per Section 5.12 is unfeasible, owners must report reasons and assessments to TFSP using specified forms. Compliance procedures are outlined in Appendix A, Section 4.0.

1.6.2.2.3 Additions to Bulk Power System Facilities If a bulk power system element is added to an existing bulk power system facility that is recognized under Section 1.6.2.2.1, Planned Renewal or Upgrade to Existing Facilities, these crit...

AI summary The text outlines criteria for protection systems when adding new elements to existing bulk power system (BPS) facilities recognized under Section 1.6.2.2.1. It emphasizes compliance requirements for ensuring reliability and safety in BPS upgrades.

1.6.2.2.4 "In-Kind" Replacement of Bulk Power System Equipment If a bulk power system element (e.g., breaker, transformer, capacitor bank, reactor, etc.) or a protective relay is replaced "in kind" as a result of an unplanned event, then i...

AI summary The regulation permits 'in-kind' replacement of bulk power system equipment without upgrading associated protection systems if the replacement results from an unplanned event, emphasizing operational continuity and system reliability.

1.6.2.2.5 Change in Bulk Power System Facility Status When a facility was originally on the BPS list of April 2007 and has been shown to be non-BPS but later was determined to be BPS again, Section 1.6.2.2.1 would apply. When the facility...

AI summary The text outlines procedures for facilities re-entering BPS status after being removed. If a facility previously on the April 2007 BPS list is later reclassified as BPS, Section 1.6.2.2.1 applies, requiring compliance with Directory #3 within two years of reclassification.

1.6.3 Responsibility Whenever changes are anticipated in generating sources, transmission facilities, or operating conditions, Generator Owners and Transmission Owners shall review those protection system applications (i.e., settings, ac a...

AI summary Generator Owners and Transmission Owners are required to review protection system applications (settings, AC/DC supplies) whenever changes occur in generating sources, transmission facilities, or operating conditions. This ensures alignment with updated system parameters and reliability standards.

3.0 NERC ERO Reliability Standard Requirements The NERC ERO Reliability Standards containing requirements that are associated with this Directory include, but may not be limited to: - 3.1 [PRC-001](http://www.nerc.com/files/PRC-001-1.pdf)...

AI summary The document outlines NERC ERO Reliability Standards, emphasizing protection system requirements for the Bulk Power System. It specifies redundancy for fault-removal relays, prioritizing dependability, while security is key for non-fault-related relays. NPCC criteria add stricter rules for reliability.

5.3 Criteria for Security Protection systems shall be designed to isolate only the faulted element , except in those circumstances where additional elements are tripped intentionally to preserve system integrity, or where isolating additio...

AI summary The document outlines technical criteria for designing and operating protection systems in the bulk power system, emphasizing fault isolation, dependability, security measures, and current transformer specifications. Key requirements include isolating only faulted elements, ensuring thermal capabilities of protection components, monitoring communication links, and modeling short-circuit scenarios for accurate protection settings.

5.10 Circuit Breaker No single trip coil failure shall prevent both independent protection groups from performing the intended function. The design of a breaker with two trip coils shall be such that the breaker will operate if both trip c...

AI summary The circuit breaker design requires redundancy in trip coils to ensure both protection groups function even if one coil fails. Simultaneous energization of both coils must trigger breaker operation, with testing required to verify correct functionality.

5.11 Teleprotection Criteria - 5.11.1 Communication facilities required for teleprotection shall be designed to have a level of performance consistent with that required of the protection system , and shall meet the following: - 5.11.1.1 W...

AI summary The teleprotection criteria outline design requirements for communication facilities to ensure reliability. Key provisions include physical separation of protection groups, monitoring for equipment loss, independent power sources, signal testing, and restrictions on component sharing. These measures aim to prevent simultaneous failures and maintain system reliability.

5.12 Environment - 5.12.1 Each separate protection group and teleprotection protecting the same system element shall be on different non-adjacent vertical mounting assemblies or enclosures. - 5.12.2 Wiring for separate protection groups an...

AI summary The section outlines technical requirements for electrical protection systems, emphasizing physical separation of wiring, enclosures, and raceways for different protection groups and teleprotections to ensure system reliability and safety. Fire barriers are mandated in common raceways.

5.13 Grounding Criteria Station grounding is critical to the correct operation of protection systems . The design of the ground grid directly impacts proper protection system operation and the probability of false operation from fault curr...

AI summary The document outlines grounding and protection system criteria for power infrastructure, emphasizing design standards for substation ground grids, fault current management, and coordination with load shedding. It references NERC standards, pilot protection design, breaker failure protocols, and alignment with emergency operation criteria for underfrequency load shedding.

Appendix A Guideline and Procedure for Bulk Power System Protection

AI summary Appendix A outlines guidelines and procedures for bulk power system protection, emphasizing reliability, coordination, and compliance with standards like NERC. It addresses protection systems, monitoring equipment, and operational protocols to ensure grid stability and prevent cascading failures.

1.0 Introduction This Appendix provides the guidance for consideration in the implementation of the bulk power system Protection criteria stipulated in this Directory, and the procedure on reporting new and revised bulks power system prote...

AI summary This appendix outlines implementation guidance for bulk power system protection criteria and procedures for reporting new or revised bulk power system protection facilities, as stipulated in the Directory.

2.1 General Considerations In general, the function of a protection system is to limit the severity and extent of system disturbances and possible damage to system equipment. The Directory's criteria objectives can be met only if protectio...

AI summary The text discusses the critical role of protection systems in limiting system disturbances and equipment damage. It emphasizes the balance between dependability (correct operation when needed) and security (avoiding unintended operations), noting trade-offs between them. Examples include permissive vs. blocking line protection schemes and their impacts on the bulk power system.

2.2 Issues Affecting Dependability - 2.2.1 Some portions of elements may not in themselves be part of the bulk power system . Those portions do not require two protection groups . - 2.2.2 Two identical measuring relays should not be used i...

AI summary The text outlines technical requirements for ensuring dependability and security in power system protection. It addresses issues such as protection group redundancy, relay design, fault detection, and compliance with industry standards (IEEE, IEC) for protection systems. Emphasis is placed on minimizing single points of failure, avoiding simultaneous equipment failures, and ensuring reliable operation under adverse conditions.

2.5 Operating Time Adequate time margin should be provided taking into account study inaccuracies, differences in equipment, and protection operating times. In cases where clearing times are deliberately extended, consideration should be g...

AI summary The text emphasizes the need for adequate time margins in operating systems to account for study inaccuracies and equipment differences, highlighting risks to system stability, equipment damage, and customer service during extended clearing times. It also addresses design considerations for protection systems, transformers, and teleprotection to ensure reliability and mitigate disturbances.

2.12 Environment Means should be employed to maintain environmental conditions that are favorable to the correct performance of protection systems. 2.13 Grounding None. 2.14 Transmission Lines Protection For planned system conditions, line...

AI summary The text emphasizes the importance of maintaining environmental conditions for protection system performance, outlines transmission line protection requirements during power swings, and details generating station protection measures to minimize bulk power system impacts from faults and disturbances.

2.17.6.2 Relay Performance Considerations Any underfrequency relay which has been found to have drifted more than ±0.2 Hz from its set point or ±0.1 seconds from its time delay should be recalibrated and then retested in six months. If, at...

AI summary Underfrequency relays must be recalibrated and retested within six months if they drift more than ±0.2 Hz from their set point or ±0.1 seconds from their time delay. Persistent drift requires correction or replacement to ensure reliability.

2.17.6.3 Maintenance Underfrequency load shedding relays have a direct effect on the operation of the bulk power system during major emergencies . These relays should be maintained in accordance with requirements stipulated in Maintenance...

AI summary Underfrequency load shedding relays are critical for bulk power system stability during emergencies. Maintenance must follow 'Maintenance Criteria for Bulk Power System Protection' (Directory 3), even when relays are located outside bulk power system stations.

2.18 HVdc Systems Protection - 2.18.1 Converter terminals should be protected to avoid excessive equipment stresses and to minimize equipment damage and outage time. These protections are usually specific to the design of the converter sta...

AI summary Section 2.18 outlines protection requirements for HVdc systems, emphasizing converter terminal protections to prevent equipment damage and outages. Key conditions to monitor include voltage anomalies, valve failures, and harmonic distortions. Protection strategies may also involve responses to AC system disturbances, though these are not classified as HVdc-specific protections. Testing procedures must avoid compromising bulk power system element protections.

2.26 Control Cable, Wiring and Ancillary Control Devices Control cables and wiring and ancillary control devices should be highly dependable and secure. Due consideration should be given to published codes and standards, fire hazards, curr...

AI summary Control cables, wiring, and ancillary devices must be reliable and secure, with attention to fire hazards, electrical performance, mechanical strength, and environmental factors. Compliance with codes and standards for insulation, grounding, and routing is emphasized.

2.27 Environment Means should be employed to maintain environmental conditions that are favorable to the correct performance of protection systems .

AI summary Environmental conditions must be maintained to ensure the proper functioning of protection systems, which are critical for reliable power system operations. This highlights the interplay between environmental factors and grid reliability.

3.0 Guideline for Application of Remote Access to Protection System The following guideline is established for the application of remote access to protection system Intelligent Electronic Devices (IEDs), such as relays, programmable logic...

AI summary This guideline outlines requirements for remote access to protection system IEDs, including relays and PLCs, ensuring compliance with Section 5.1.3.3 of the Directory and Section 3.3.1.6 of the Special Protection System Criteria. It emphasizes the necessity of physical security measures meeting applicable standards.

3.3.6 Logging/Alarming When remote connections are used to access the relay beyond "view-only" mode, this should be alarmed and/or logged where possible.

AI summary The text mandates that remote access to relays beyond 'view-only' mode must be logged and/or alarmed to ensure security and monitoring. This requirement emphasizes the importance of tracking unauthorized or elevated access attempts to maintain system integrity.

3.3.7 Controlling Authority Approval For both local and remote communications, excluding viewing, notification and approval of the Controlling Authority should be required to access in-service protection system IEDs. Only authorized users,...

AI summary The document mandates Controlling Authority approval for accessing in-service protection system IEDs, restricts remote access to authorized users, and emphasizes disabling unused IED functions to mitigate vulnerabilities. Additional security measures include implementing VPNs, limiting public network use, callback systems, and hardware dongles for dial-up access.

4.4 TFSP Procedures - 4.4.1 The TFSP will review the material presented and develop a position statement concerning the proposed protection system . This statement will indicate one of the following: - 4.4.1.1 The need for additional infor...

AI summary The TFSP reviews proposed protection systems and issues position statements indicating acceptance, conditional acceptance, rejection, or the need for additional information. Nonconformance areas are documented in minutes, letters to owners, or referrals to the RCC. Reviews are recorded for transparency and compliance with NPCC criteria.

NPCC Regional Reliability Reference Directory # 7 Special Protection Systems Task Force on System Protection Revision Review Record December 27, 2007 Adopted by the Members of the Northeast Power Coordinating Council Inc., this December 27...

AI summary The document outlines the adoption of the NPCC Regional Reliability Reference Directory #7 Special Protection Systems by the Northeast Power Coordinating Council Inc. on December 27, 2007, following a recommendation by the Reliability Coordinating Committee and in accordance with NPCC bylaws.

b. SPS Re-classified to Type I or Type II These requirements apply to all existing SPSs which are reclassified as Type I or Type II due to system changes. A mitigation plan shall be required to bring such a SPS into compliance with these c...

AI summary This section outlines requirements for existing Special Protection Systems (SPS) reclassified as Type I or Type II due to system changes, mandating the development of a mitigation plan to ensure compliance with updated criteria.

c. In-kind Replacement of SPS Equipment If SPS equipment is replaced "in-kind" as a result of an unplanned event, then it is not required to upgrade the associated protection system to comply with these criteria.

AI summary The text states that replacing Special Protection Systems (SPS) equipment 'in-kind' following an unplanned event does not necessitate upgrading the associated protection system to meet specified criteria.

1.6.3 Classification of Special Protection Systems Special Protection Systems are sub-divided into three types. Reference can be made to the NPCC Basic Criteria for Design and Operation of Interconnected Power Systems (Document A-2) where...

AI summary The document classifies Special Protection Systems (SPS) into three types based on their impact from design, operating, and extreme contingencies. Type I and II SPS have significant adverse impacts outside local areas, while Type III does not. The NPCC's Document A-2 outlines criteria for these classifications.

2.0 Terms Defined in this Directory The following terms are defined in this Directory. Their definitions are provided in Attachment 1. Bulk Power System Contingency Fault Operating Procedures Protection Special Protection System (SPS) Tele...

AI summary This section lists technical terms defined in Attachment 1, focusing on Bulk Power System protection mechanisms including Special Protection Systems (SPS) and Teleprotection procedures. The definitions are critical for understanding contingency fault operating protocols in power system reliability frameworks.

3.0 Requirements - 3.1 The NERC ERO Reliability Standards containing Requirements that are associated with this Directory include, but may not be limited to: - 3.1.1 PRC-012-0 Special Protection System Review Procedure - 3.1.2 PRC-013-0 Sp...

AI summary The document outlines NERC ERO Reliability Standards and NPCC requirements for Special Protection Systems (SPS), emphasizing design criteria such as redundancy, security, thermal capability, and monitoring to ensure dependability and reliability of the bulk power system.

3.3.2 Current Transformer Criteria Current transformers (CTs) associated with Special Protection Systems shall have adequate steady-state and transient characteristics for their intended function. - 3.3.2.1 The output of each current trans...

AI summary Current Transformer (CT) specifications for Special Protection Systems (SPS) must ensure proper operation under fault currents, thermal/mechanical stress, and emergency conditions. Requirements include separate secondary windings for protection groups and single-point grounding.

3.3.3 Voltage Transformer and Potential Device Criteria Voltage transformers and potential devices associated with Special Protection Systems shall have adequate steady-state and transient characteristics for their intended functions. - 3....

AI summary The document outlines technical criteria for voltage transformers and potential devices in Special Protection Systems (SPS), emphasizing redundancy, reliability, and safety. Key requirements include adequate volt-ampere capacity, separate voltage sources for redundancy, grounding rules, and battery/dc supply dependability. Ferroresonance risks and continuous monitoring of dc systems are also addressed.

3.3.5 Station Service ac Supply Criteria If a Special Protection System is designed to have multiple protection groups at a single location for redundancy, there shall be two sources of station service ac supply, each capable of carrying a...

AI summary The criterion requires two independent AC power sources for Special Protection Systems with multiple protection groups to ensure redundancy and support all critical loads.

3.3.6 Circuit Breakers Criteria Where Special Protection System redundancy is achieved by use of independent protection groups tripping the same circuit breakers without overarming, each circuit breaker shall be equipped with two independe...

AI summary The criteria specify that when Special Protection System (SPS) redundancy is achieved through independent protection groups tripping the same circuit breakers without overarming, each circuit breaker must have two independent trip coils to ensure reliability and safety.

3.3.7 Teleprotection Criteria Communication facilities required for teleprotection shall be designed to have a level of performance consistent with that required of the Special Protection System , and shall meet the following: - 3.3.7.1 Wh...

AI summary The teleprotection criteria outline design standards for communication facilities, emphasizing redundancy, physical separation of equipment, monitoring, power independence, and restrictions on component sharing to ensure reliability during bulk power system disturbances.

3.3.8 Physical Separation/Environment Criteria - 3.3.8.1 In addition to the physical separation as referenced in sections 3.3.1.2 and 3.3.9.5, if a Special Protection System is designed to have multiple protection groups at a single locati...

AI summary The section outlines physical separation requirements for Special Protection Systems (SPS), mandating non-adjacent mounting assemblies for redundant protection groups and fire barriers in common raceways to ensure reliability and safety.

3.3.9 Grounding Criteria Station grounding is critical to the correct operation of Special Protection Systems . The design of the ground grid directly impacts proper Special Protection System operation and probability of false operation fr...

AI summary Substation grounding is essential for Special Protection Systems (SPS) to prevent false operations from fault currents or transients. Design procedures must include traceable methods, cable shielding considerations, and equipment grounding for all substation types (TO, GO, DP).

3.3.10 Provision for Breaker Failure Criteria Type I SPS shall include breaker failure protection for each circuit breaker whose operation is critical to the adequacy of the action taken by the SPS with due regard to the power system condi...

AI summary The document outlines requirements for Type I SPS (Special Protection System) to include breaker failure protection for critical circuit breakers, ensuring system reliability. It discusses design options to address breaker failure scenarios while considering power system conditions.

NPCC Reliability Reference Directory #7 Special Protection Systems November 28, 2007 intended function required by the Special Protection System and which takes independent action to achieve that function. This provision needs not be dupli...

AI summary The document discusses the intended function of a Special Protection System (SPS), emphasizing its ability to act independently to achieve its purpose and potential integration with conventional breaker failure schemes.

Attachment 1 Definition of Terms - Bulk power system The interconnected electrical systems within northeastern North America comprising generation and transmission facilities on which faults or disturbances can have a significant adverse i...

AI summary Attachment 1 defines key terms related to power systems, including 'bulk power system,' 'contingency,' 'fault' (permanent and transient), 'operating procedures' (automatic, normal, postcontingency), and 'protection.' These definitions emphasize system reliability, fault detection, and operational protocols for maintaining grid integrity.

Notes: - (a) Variously identified as Main Protection , Primary Protection , Breaker Failure Protection , Back-Up Protection , Alternate Protection , Secondary Protection , A Protection , B Protection , Group A, Group B, System 1 or System...

AI summary The text outlines various terminology used to describe protection systems, including Main Protection, Primary Protection, and Pilot Protection, noting that Pilot Protection is categorized as a single protection group. It highlights the interchangeable use of terms like 'Back-Up Protection' and 'Secondary Protection' in regulatory contexts.

Element Basis One or more protection groups; including all equipment such as instrument transformers, station wiring, circuit breakers and associated trip/close modules, and communication facilities; installed at all terminals of a power s...

AI summary The text defines 'protection groups' as sets of equipment including instrument transformers, circuit breakers, and communication facilities installed at all terminals of a power system element to ensure its complete protection.

Terminal Basis One or more protection groups, as above, installed at one terminal of a power system element , typically a transmission line. Pilot Protection — A form of line protection that uses a communication channel as a means to compa...

AI summary Defines terminal basis, pilot protection, and special protection systems (SPS), outlining conditions for significant adverse impact, including instability, equipment tripping, and voltage violations. References the NPCC Reliability Reference Directory #7 (2007) for SPS guidelines.

Appendix A Guidance for Consideration in SPS Design

AI summary Appendix A provides guidance for designing Special Protection Systems (SPS) in the context of regulatory proceedings. It likely outlines technical considerations, reliability standards, and coordination requirements for SPS implementation within Nova Scotia's power grid.

Introduction This Appendix provides the guidance for consideration in the implementation of the Special Protection System design criteria stipulated in Section 3.3 of this Directory. The general objective for any SPS is to perform its inte...

AI summary The document outlines design criteria for Special Protection Systems (SPS), emphasizing dependability and security. It highlights the balance between ensuring SPS operates correctly when needed and avoiding unintended operations, while stressing the need for cross-functional coordination in planning, design, and protection to maintain bulk power system reliability.

2.0 Considerations Affecting Dependability - 2.1 Redundancy is normally provided by duplication. Some aspects of duplication may be achieved by overarming, which is defined as providing for more corrective action than would be necessary if...

AI summary The document outlines redundancy and design requirements for Special Protection Systems (SPS), emphasizing minimization of simultaneous failures, reduction of common exposure risks, and compliance with industry standards (IEEE, IEC) to ensure reliability and security. It addresses hardware quality, environmental resilience, and operational safeguards.

4.0 Considerations Affecting Performance 4.1 Control Cable, Wiring and Ancillary Control Device Control cables and wiring and ancillary control devices should be highly dependable and secure. Due consideration should be given to published...

AI summary Section 4.1 emphasizes the need for reliable and secure control cables, wiring, and ancillary devices, highlighting considerations such as fire hazards, electrical parameters, mechanical strength, and environmental factors to ensure system dependability.

4.2 Environment Means should be employed to maintain environmental conditions that are favorable to the correct performance of Special Protection Systems. 5.0 Operating Time of an SPS Adequate time margin should be provided taking into acc...

AI summary The document emphasizes maintaining environmental conditions to ensure proper performance of Special Protection Systems (SPS). It outlines requirements for adequate time margins in SPS operation, considering study inaccuracies and equipment differences, and details both automatic and manual arming mechanisms for SPS based on system conditions and contingencies.

7.0 Maintenance Considerations - 7.1 Additional periodic maintenance is recommended on the following protection equipment: - . On continuously monitored analog teleprotection channels, verify signal adequacy every twelve months. - . On non...

AI summary The document outlines maintenance recommendations for protection equipment, including teleprotection systems, batteries, chargers, and circuit breakers. It emphasizes the importance of evaluating specific circumstances for additional maintenance and designing Special Protection Systems to facilitate testing and mitigate risks.

NPCC Reliability Reference Directory #7 Special Protection Systems November 28, 2007 7.5 Whenever practicable, some of the maintenance testing requirements may be met by analyzing and documenting the detailed performance of the Special Pro...

AI summary The document discusses procedures for reviewing Special Protection Systems (SPS), emphasizing the use of actual event performance data to meet maintenance testing requirements, which can reduce false operations and planned maintenance.

2.0 NPCC Review and Concurrence - 2.1 Allowing for sufficient lead time to ensure an orderly review, the entity will notify the chairman of the Task Force on Coordination of Planning (TFCP) of its proposal to install a new Special Protecti...

AI summary The NPCC process outlines steps for reviewing and concurrence of Special Protection System (SPS) installations or modifications. Task Forces evaluate potential consequences, compliance with NPCC criteria, and coordinate reviews. The process involves TFCP, TFCO, TFSS, and TFSP, with decisions based on local or inter-area/regional impacts.

NPCC Reliability Reference Directory #7 Special Protection Systems November 28, 2007 Protection System Criteria and Standards requirments listed in this document and forward a summary of their findings to TFCO, TFCP and TFSS. This summary...

AI summary The document outlines requirements for evaluating Special Protection Systems (SPS) against Bulk Power System (BPS) criteria. Findings must be submitted to TFCO, TFCP, and TFSS, detailing conformance with Document A-5 and any objections to SPS modifications or installations.

3.6 Review by TFSP The TFSP will review the material presented and develop a position statement concerning the proposed protection system. This statement will indicate one of the following: - 3.6.1 The need for additional information to en...

AI summary The TFSP will review a proposed protection system and issue a position statement indicating acceptance, conditional acceptance, rejection, or a need for additional information. Nonconformance with NPCC criteria may trigger corrective recommendations. Results will be documented in meeting minutes and letters to TO, GO, or DP.

PROCEDURE FOR NPCC REVIEW OF NEW OR MODIFIED BULK POWER SYSTEM SPECIAL PROTECTION SYSTEMS (SPS)

AI summary The document outlines the procedure for the Northeast Power Coordinating Council (NPCC) to review new or modified Bulk Power System Special Protection Systems (SPS), emphasizing grid reliability and coordination with regulatory bodies like NSUARB and FERC.

NPCC Regional Reliability Reference Directory # 8 System Restoration Task Force on Coordination of Operations Revision Review Record: October 21, 2008 Adopted by the Members of the Northeast Power Coordinating Council, Inc. this October 22...

AI summary The NPCC Regional Reliability Reference Directory #8 System Restoration was adopted by the Northeast Power Coordinating Council on October 22, 2008, following the Reliability Coordinating Committee's recommendation. It references Section VIII of the NPCC's amended bylaws dated July 24, 2007.

5.1 System Restoration Plan Requirements Each Reliability Coordinator and Transmission Operator shall develop and maintain a system restoration plan for its operating area1 that meets NERC requirements. In addition, the restoration plan sh...

AI summary Reliability Coordinators and Transmission Operators must develop system restoration plans meeting NERC requirements, including identifying basic minimum power systems, prioritizing nuclear plant power restoration, interconnection points, synchronization parameters, coordination with neighboring areas, reenergizing transmission systems, and stabilizing electrical islands.

key facilities : - 5.7.1.1 As soon as possible and no later than 15 minutes after its control room has confirmed the loss of functionality at a key facility due to the failure of critical components . Loss of functionality at a key facilit...

AI summary The text defines procedures for reporting failures at key facilities, emphasizing timely responses to loss of functionality or redundancy. Critical components include control systems, AC/DC service supplies, and Blackstart facilities. Remedial actions must be identified with completion dates.

6.0 Measures and Assessments - M1. Each Reliability Coordinator and Transmission Operator shall have a dated, documented System restoration plan developed in accordance with Section 5.1, "System Restoration Plans." - M2. Each Reliability C...

AI summary Section 6.0 outlines mandatory measures for reliability coordinators, transmission operators, and owners, including system restoration plans, documentation of critical components, maintenance programs, and testing requirements to ensure grid reliability and proper facility operation.

Table 1 - Standard Test Procedures for key facilities and associated critical components required for system restoration Table 1 - Standard Test Procedures for key facilities and associated critical components required for system restorati...

AI summary Table 1 outlines standard test procedures for key facilities and critical components required for system restoration, focusing on blackstart generating units. The test involves an annual startup test of the generating unit's blackstart capability without dependencies on the power system, with criteria for successful operation.

NPCC Specific Definitions: Firm Load — Loads that are not Interruptible Loads . Interruptible Load — Loads that are interruptible under the terms specified in a contract. Load Shedding — The process of deliberately removing (either manuall...

AI summary The text defines key terms related to power system operations, including Firm Load, Interruptible Load, Load Shedding, and the role of System Operators. These definitions emphasize maintaining system integrity through load management and coordination across interconnected systems.

Appendix B Guideline and Procedure for Blackstart and System Restoration

AI summary Appendix B outlines guidelines and procedures for blackstart and system restoration, focusing on reliability protocols and operational frameworks for power system recovery. It references regulatory entities and technical standards relevant to grid resilience.

1.0 Introduction This Appendix provides the guidelines and procedures to the Reliability Coordinator, Transmission Operator and Balancing Authority to manage system restoration events that affect the NPCC member Areas and adjoining operati...

AI summary The document outlines procedures for managing system restoration in NPCC regions, emphasizing the need for Reliability Coordinators and Transmission Operators to maintain restoration plans. It highlights the importance of preparing for blackouts by building basic power systems from key facilities and adhering to NERC and NPCC standards.

NPCC Directory D8 System Restoration technical guidelines for system operators to reconnect the Reliability Coordinator and Transmission Operator areas and provide mutual assistance in a manner that reestablishes interconnected operation i...

AI summary The text outlines technical guidelines for system operators to restore interconnected operations between Reliability Coordinator and Transmission Operator areas, emphasizing responsible and expeditious reconnection. It also mandates confidentiality for facility information to protect physical and cyber security, restricting access to a 'need to know' basis.

2.0 Minimizing the Impact of Events Within NPCC, the Reliability Coordinator and Transmission Operator restoration plans are developed in accordance with all relevant NPCC Criteria and NERC Standards and reflect the best practices of the i...

AI summary This section outlines the restoration plans developed by the Reliability Coordinator and Transmission Operator within the NPCC, following NPCC Criteria and NERC Standards. The plans prioritize establishing a basic minimum power system, providing AC supply to critical generating units, restoring load for stability, and re-establishing inter-area tie lines.

3 All member Areas in NPCC are registered as the Reliability Coordinator and Transmission Operator. Hence, only the member Areas names are shown in this column to indicate they represent both the RC and the TOP. Table 2-1 NPCC Reliability...

AI summary The table outlines the restoration priorities for the Maritimes Area, managed by the New Brunswick System Operator, as part of the NPCC Reliability Coordinator and Transmission Operator framework. It details the steps for restoring AC station service to critical facilities such as nuclear generating sites and other plants and substations.

4.0 Actions to Stabilize Remaining Electrical Islands

AI summary This section outlines measures to stabilize electrical islands—disconnected parts of the grid—following contingencies. It emphasizes reliability strategies, coordination with regional bodies, and technical solutions to prevent cascading failures and ensure continuous power delivery.

4.1 Immediate Actions to Stabilize Conditions Within Electrical Islands After a significant power system disturbance , electrical islands can result due to the separation and survival of sub-areas from the Interconnection . It is imperativ...

AI summary Following a power system disturbance, electrical islands may form, requiring immediate monitoring and stabilization actions such as reactive control device switching, generation dispatch, transmission switching, or load shedding to maintain thermal, voltage, and frequency conditions.

4.2 Requirement for Manual Generation Dispatch If the power system has been severely disrupted, economic dispatch signals may be inaccurately calculated by energy management system software or may be ineffective in their application. Conse...

AI summary In the event of severe power system disruptions, economic dispatch signals from energy management systems may become inaccurate or ineffective. This could prompt the Reliability Coordinator and Transmission Operator to request manual dispatch orders from the Balancing Authority to maintain system stability.

4.3 Tie Line Regulation The Balancing Authority should appropriately select flat frequency or tie line bias control to stabilize frequency depending on the status of their tie lines . If a Balancing Authority area is electrically isolated,...

AI summary The Balancing Authority must choose between flat frequency or tie line bias control based on tie line status. Isolated areas require flat frequency control, while connected areas may use combinations. The largest area should use flat frequency control, and smaller connected areas should use tie line bias control for optimal frequency regulation.

5.0 Assessment of Conditions Prior to Interconnecting When assistance is required from an external Reliability Coordinator or Transmission Operator area, communications between the requesting and assisting Reliability Coordinator and Trans...

AI summary The section outlines the need to assess system conditions (load, generation, reserves, etc.) and types of assistance (frequency control, tie line regulation) before interconnecting to ensure reliability and prevent separation during emergencies. It emphasizes mutual agreements between system operators for reliable assistance.

5.1 Inadvertent Synchronization of Electrical Islands Relaying and reclosing on tie lines should be assessed. While the operation of protection relaying may not be significantly impacted by the presence of an unusually sparse transmission...

AI summary The text advises assessing relaying and reclosing on tie lines, noting that while protection relaying may not be significantly impacted by sparse transmission systems, system operators should consider disabling automatic reclosing on tie lines, particularly when only one or a few low-voltage tie lines are operational.

5.2 Tie Line Regulation Prior to interconnecting, system operators within the operating areas on either side of the tie line must determine whether the areas are already interconnected to any other systems and, if so, what are the intercon...

AI summary The section outlines procedures for tie line regulation, emphasizing system operators' responsibilities to assess interconnection points, manage synchronization, establish acceptable flow deviations, and address post-contingency tie line flows. It stresses adherence to mutual assistance guidelines and readiness to delay restoration activities to maintain tie line security during contingencies.

5.3 Assessment of Reserves Prior to Synchronizing Electrical Islands Prior to synchronizing electrical islands between operating areas, an assessment of the reserves should be made such that the reserves for the new electrical island can b...

AI summary Prior to synchronizing electrical islands, reserves must be assessed to ensure adequacy, contingency recovery plans, and transmission capacity. Key considerations include evaluating contingency losses, spinning reserves, load shedding, and interconnection circuit ratings. Additional circuits are recommended post-synchronization for reliability.

5.4 Frequency Control The energy management systems of the NPCC Balancing Authorities utilize the following control mechanisms to perform interconnected regulation using Automatic Generation Control (AGC) applications:

AI summary The NPCC Balancing Authorities use Automatic Generation Control (AGC) applications within their energy management systems to perform interconnected regulation for frequency control. This mechanism ensures stable grid operation through coordinated generation adjustments.

1. Flat Tie Line Only the tie line mismatch between scheduled interchange and actual interchange flow is used to determine area control error (ACE) .

AI summary The Flat Tie Line's area control error (ACE) is determined solely by the mismatch between scheduled and actual interchange flows, highlighting its role in automatic generation control and system reliability.

2. Flat Frequency Only frequency deviation is used to determine the ACE .

AI summary The document specifies that in the context of Flat Frequency, only frequency deviation is used to determine the Area Control Error (ACE), highlighting a specific method for monitoring and controlling power system stability.

3. Tie Line Bias Both frequency deviation and tie line mismatch are used to determine the ACE . Following a major system disturbance , Balancing Authorities must determine the status of their respective Automatic Generation Control (AGC) s...

AI summary The document explains how Area Control Error (ACE) is determined using frequency deviation and tie line mismatch. It emphasizes the importance of selecting appropriate control modes (flat frequency or tie line bias) after system disturbances to stabilize frequency. Incorrect control modes can negatively impact Balancing Authority areas, with the optimal approach being flat frequency for the largest area and tie line bias for smaller connected areas.

5.6 Provision of External Restoration Service External restoration service may be provided to an adjacent blacked-out Reliability Coordinator or Transmission Operator area. When the assisting area has strong tie lines remaining with the Ea...

AI summary External restoration services must limit load restoration based on tie line capacity to adjacent areas and 5% of synchronized generator capacity in electrical islands to avoid frequency/voltage transients. Special caution is required for cold load pickup and energizing transmission lines due to potential surges.

5.7 Radially Energize and Restore a Portion of an Adjacent Area's System Situations can occur where it is desirable for an operating area to supply generating stations, substations and customer load in an adjacent operating area. In doing...

AI summary Section 5.7 addresses scenarios where an operating area may need to supply generating stations, substations, and customer load in an adjacent area. It emphasizes caution in determining system separation points and highlights the need to assess considerations before providing assistance, though the text is cut off mid-sentence.

limited to the following: - 1. Determine the current load expected to be supplied. - 2. Determine the expected peak load . - 3. Determine the generation available. - 4. Identify real or reactive restrictions (MW and / or MVAR) on the inter...

AI summary The text outlines six procedural steps for assessing power system reliability, focusing on load expectations, generation availability, and circuit restrictions. It emphasizes determining load requirements, available generation, reactive power limits, and the duration of temporary operational arrangements.

6.0 Establishing Interconnection via Inter-Area Tie Lines When two systems are to be interconnected, options may be available as to where the interconnection may take place. When these options exist, it is up to the Reliability Coordinator...

AI summary The document outlines that when interconnecting systems, the Reliability Coordinator or Transmission Operator determines the optimal location and voltage level for interconnection via inter-area tie lines, emphasizing their role in ensuring reliable system integration.

6.1 Synchronous Tie Line When synchronizing Reliability Coordinator or Transmission Operator areas, the following guidelines should be followed: Synchronize at locations where: - 1. Synchronism-check relays and / or manual synchroscopes ar...

AI summary This section outlines technical guidelines for synchronizing Reliability Coordinator and Transmission Operator areas, emphasizing voltage and frequency matching, availability of control resources, and communication protocols. It specifies voltage differences (≤3%), frequency alignment (≤20° phase angle difference), and the use of synchronism-check relays for safe synchronization.

6.2 Non-Synchronous Tie Lines Non-synchronous tie lines , such as HVdc tie lines or variable frequency transformers, can present special concerns during system restoration. The start-up of older model asynchronous HVdc tie line s must be l...

AI summary Non-synchronous tie lines, particularly HVdc systems, require careful handling during system restoration. Older HVdc lines need strong AC systems for commutation and stability, while newer models can operate with weaker systems. Transmission Operators must establish restoration criteria and assess whether non-synchronous lines can remain in service without hindering restoration.

7.0 Considerations to Remain Stable Following Interconnection Once interconnected, the increase in tie line flow(s) into an island , in response to a generation contingency within the island , is proportional to the relative amounts of gen...

AI summary The document explains how tie line flows between interconnected systems respond to generation contingencies, using load as a proxy for synchronized generation capacity. It emphasizes the importance of secure flow management on tie lines, referencing prior sections on operational considerations.

7.1 Frequency Considerations In general, once operating areas are tied together and receiving or supplying assistance, operating personnel should continue restoration efforts in a manner that prevents excessive frequency or voltage deviati...

AI summary The text outlines procedures for maintaining frequency stability during grid restoration, emphasizing a target transient frequency range of 59.5–60.5 Hz and pre-switching checks to prevent excessive frequency deviations. Operating personnel must ensure steady-state frequency alignment before introducing load or generation resources.

7.2 Voltage Considerations Operating personnel should also discuss desired voltage levels that would be sustainable during the event. The general voltage range for maximum voltage deviation while receiving assistance is 5% of nominal trans...

AI summary The text outlines guidelines for operating personnel to discuss sustainable voltage levels during events, specifying a 5% deviation from nominal transmission voltages as the general range for maximum voltage deviation when receiving assistance.

7.3 Thermal Considerations Operating personnel should be aware of three key parameters noted below. The specific amounts for each facility need to be communicated between the Interconnecting operating areas. These amounts may be revised as...

AI summary Operating personnel must monitor three key thermal parameters, which require communication between interconnecting areas and may be adjusted based on evolving system conditions.

7.3.1 Maximum Tie Line Interface Export Loading It is the maximum tie-line or interface loadings possible based on equipment ratings and operation to provide contingency coverage. Some operating area ties points consist of multiple circuit...

AI summary The section defines maximum tie-line or interface loadings based on equipment ratings and contingency coverage. It explains that interfaces with multiple parallel circuits are constrained by thermal capabilities and must not exceed normal continuous ratings or emergency ratings during contingencies.

7.3.2 Maximum Tie Line Interface Loading Rate It is the maximum loading rate of a tie line or interface as allowed by the assisting operating area. The typical maximum tie line interface loading rates may range from 15 MW per minute to 50...

AI summary The document defines the maximum tie line interface loading rate as the allowable rate of change for a tie line or interface, determined by the assisting operating area. Typical rates range from 15 MW to 50 MW per minute, depending on the tie line configuration.

7.3.3 Maximum Tie Line Interface Deviation for Step Changes in Load or Generation This is the parameter that indicates the maximum step change allowed, from a mutually agreed to schedule flow, on a tie line or interface . These deviations...

AI summary This section defines the maximum allowable step change in tie line interface flow due to load or generation changes, set as the lesser of 5% of synchronized capacity or cumulative generation loading rates. Typical deviations range from 15 MW to 100 MW, ensuring grid stability during operational adjustments.

8.0 Training and Exercises To maintain the ability of the Reliability Coordinator, Transmission Operator and Balancing Authority operating personnel to respond effectively to a power system emergency, they are certified and trained within...

AI summary The document outlines training and exercise requirements for Reliability Coordinators, Transmission Operators, and Balancing Authorities within NPCC to ensure effective emergency response. These activities, conducted in accordance with NERC standards, enhance inter-area coordination through simulations and semiannual training seminars led by the NPCC Dispatcher Training Working Group (CO-02).

Exercises may include: - 1. Simulated emergency response activities; - 2. Table top simulations; - 3. Exercise participants participating from their normal work headquarters; - 4. Minimal to zero coaching by exercise coordinators; and - 5....

AI summary The document outlines procedures for conducting system restoration exercises, emphasizing simulated emergencies, tabletop simulations, and minimal coaching. Post-exercise assessments and lessons learned are critical, with coordination led by the NPCC Inter-Control Area Restoration Coordination Working Group (CO-11) to ensure inter-area collaboration during restoration events.

Maritimes Area Restoration Overview

AI summary The document provides an overview of restoration efforts in the Maritimes area, focusing on energy system reliability and coordination. It references regulatory bodies and technical terms related to power grid management but lacks specific details on initiatives or outcomes.

Objective This restoration summary is a brief overview of how the Maritimes Area restores the power system following a complete blackout of the Maritimes Area . It does not attempt to cover details of the individual system restoration plan...

AI summary This document outlines the restoration process for the Maritimes Area's power system following a complete blackout, emphasizing it as a high-level overview rather than a detailed analysis of individual plans or all potential blackout scenarios.

Background The Maritimes Area consists of three Canadian provinces: New Brunswick (NB), Nova Scotia (NS) and Prince Edward Island (PEI), as well as a radially connected portion of the state of Maine {Northern Maine Independent System Admin...

AI summary The Maritimes Area includes New Brunswick, Nova Scotia, Prince Edward Island, and Northern Maine, interconnected via multiple transmission lines. The New Brunswick System Operator (NBSO) serves as the Reliability Coordinator, managing synchronization across the region. Grid connections exist between provinces and Maine, with no direct NS-PEI link. The 2004 peak load for the Maritimes was 6,000 MW.

Basic Plan The restoration plan assumes no assistance from adjacent Areas . Each entity within the Maritimes Area has blackstart capability and, therefore, individually establishes their power system according to their detailed switching p...

AI summary The Basic Plan outlines a self-reliant power restoration strategy for Maritime regions, relying on blackstart capabilities and synchronization coordination by NB's Reliability Coordinator. Systems initially use the 'open all breaker' method before synchronizing islands and managing load pickup.

New England Area Restoration Overview

AI summary The New England Area Restoration Overview outlines efforts to restore power reliability in the region, involving coordination between regulatory bodies and energy operators. It highlights challenges and strategies for system recovery, though specific details are not provided in the text.

Introduction This procedure addresses restoration of the bulk power system (115 kV and above) after a partial or complete system blackout. Expeditious restoration of the bulk power system depends on independent actions and interactions by...

AI summary This procedure outlines the restoration of the bulk power system (115 kV+) after a blackout, emphasizing coordination among NEPOOL Participants, Local Control Centers, and ISO New England Inc. Prioritizing off-site AC power restoration for nuclear generators and addressing technical challenges like synchronization are critical to system recovery.

A. Local Control Centers - 1. Determine the extent of the blackout within each Local Control Center and inform the ISO as soon as possible of existing generation and transmission capabilities. (The ISO will determine the extent of the blac...

AI summary The Local Control Centers are required to assess blackout extent, notify the ISO of generation/transmission capabilities, execute restoration procedures with ISO coordination, and energize 345 kV circuits and area tie lines during communication failures if prudent for system restoration.

B. ISO New England - 1. Determine the extent of the blackout throughout New England and adjacent power systems and inform all Local Control Centers of existing generation and transmission capabilities. - 2. Implement the ISO restoration pr...

AI summary ISO New England is tasked with assessing blackout severity, coordinating restoration efforts with Local Control Centers, and providing temporary dispatch assistance if needed during system outages. The procedures emphasize communication, restoration protocols, and contingency support for regional power systems.

NPCC Directory D8 System Restoration - 4. Authorize the closing of inter-Local Control Center and inter- Area transmission lines. - 5. Once inter-Local Control Center or inter- Area tie lines are energized , oversee and coordinate load pic...

AI summary The NPCC Directory D8 outlines procedures for system restoration, including closing inter-area transmission lines, managing load pickups, prioritizing power supply to generating stations, directing load shedding, and monitoring bulk power system facilities to ensure reliability during restoration.

System Restoration Guidelines The following lists guidelines regarding the technical aspects of system restoration that are provided in New England restoration procedures: - A. Restoration of Off-Site AC Power to Nuclear Generators - B. Op...

AI summary The document outlines technical guidelines for system restoration, including steps like restoring AC power to nuclear generators, managing circuit breakers, and coordinating with ISO procedures. It emphasizes the importance of these guidelines for handling blackouts and references specific procedures for the 345 kV system.

Operational Authority Structure In accordance with the Ontario Electricity Act of 1998, the Independent Electricity System Operator (IESO) is responsible for managing the reliability of the IESO controlled grid, operating a competitive mar...

AI summary The IESO manages Ontario's grid reliability, operates a competitive electricity market, and complies with NERC and NPCC requirements. It uses automated dispatch algorithms for economic operation, coordinates with transmission operators, and fulfills roles as a Reliability Coordinator and Market Operator under the Ontario Electricity Act.

Overview of System Restoration Plan for Ontario The Ontario Power System Restoration Plan (OPSRP) is structured to address what is needed to enable successful system restoration in four related subject areas: - 1. Operational; - 2. Testing...

AI summary The Ontario Power System Restoration Plan (OPSRP) outlines strategies for restoring the IESO-controlled grid after a blackout, prioritizing critical infrastructure like nuclear plants and control centers. It emphasizes flexibility, synchronization of power islands, and voltage/frequency control to ensure reliable restoration without predefined step-by-step paths.

Administration to Sustain Emergency Response Capabilities The IESO has implemented all identified opportunities for improvement identified in the various blackout investigations following the power system collapse of August, 2003. In consi...

AI summary The IESO has enhanced emergency preparedness following the 2003 blackout, requiring Ontario market participants to submit Emergency Preparedness Plans and restoration plans. The OPSRP aligns with NERC and NPCC standards, emphasizing training, testing, and large-scale exercises for system restoration.

Québec Area Restoration Overview

AI summary The document provides an overview of restoration efforts in the Quebec area, though specific details are not included in the provided text. It likely discusses strategies, challenges, and coordination mechanisms related to power system reliability and recovery in the region.

1.0 Introduction Every utility takes, in designing and operating its system, all the necessary precautions to limit contingencies leading to a blackout of the system. However, the possibility of such a shutdown still exists, and the utilit...

AI summary Utilities must implement precautions to prevent blackouts but require system restoration plans for potential shutdowns. The document notes Hydro-Québec TransÉnergie's hydroelectric-focused plan may not fully apply to thermal systems, highlighting context-specific limitations.

2.0 Objective To allow restoration of the system, safely, in the shortest possible time.

AI summary The objective is to restore the system safely and in the shortest possible time, focusing on system reliability and rapid emergency response to minimize disruptions.

3.0 Methodology The design of the restoration plan contains the following elements: - 1. Basic plan; - 2. Regular follow-up; - 3. Personnel and material required; and - 4. Testing of critical components associated with key facilities .

AI summary The restoration plan design includes four elements: basic plan development, regular follow-up procedures, personnel and material requirements, and testing of critical components at key facilities to ensure reliability and preparedness.

3.1 Basic Plan The primary priority of the basic restoration plan is the restoration of AC station service to the nuclear plant. If a blackout occurs, the configuration of the system has to be examined to identify possible restoration path...

AI summary The Basic Plan prioritizes restoring AC service to the nuclear plant during blackouts by partitioning the system into Basic Minimum Power Systems (BMPS), which are restored independently. The system operator selects a main BMPS for synchronization, allowing gradual restoration. Special cases involve synchronization with neighboring utilities under existing agreements.

3.2.1 Daily Follow-up of the System Configuration Once the restoration plan is set up, it must be constantly updated to keep track of equipment outages. Some equipment is designated as necessary for the restoration process (i.e., they are...

AI summary The restoration plan requires continuous updates to track equipment outages, identify critical components, and analyze alternate paths when necessary. Maintenance schedules are assessed annually to prevent disruptions during restoration. Key facilities and simultaneous outage scenarios are evaluated to ensure reliability.

3.2.2 System Expansion Plan The impacts of additions and modifications must be assessed and their impact on the restoration procedure thoroughly evaluated.

AI summary The text emphasizes the necessity of evaluating the impacts of system additions and modifications on restoration procedures, ensuring reliability and compliance with regulatory standards. It underscores the importance of thorough assessment to maintain system integrity during expansion planning.

3.2.3 Presentation of the Plan The total blackout of a system being an infrequent and sudden event, it is important to keep the operations staff up to date regarding the plan. A formal presentation is scheduled at least once a year with al...

AI summary The document emphasizes the importance of keeping operations staff informed about blackout prevention plans due to the rare but sudden nature of total blackouts. Annual formal presentations are mandated to ensure all relevant personnel are updated on the plan.

3.3.1 Personnel One system operator is selected to be in charge of the restoration process, and his role is clearly defined, along with the role of all other people involved in the process.

AI summary A single system operator is designated to oversee the restoration process, with clearly defined roles for this operator and all other personnel involved in the process.

Backup Team Each control center, system control center and remote control center must have a multidisciplinary backup team able to solve any problem that might occur during the process. This team includes experts in the following fields: o...

AI summary The document mandates that all control centers maintain multidisciplinary backup teams with expertise in power system analysis, protective relaying, and telecommunications. These teams must be continuously updated and accessible at all control centers to address potential operational issues.

3.3.2 Material

AI summary The section '3.3.2 Material' introduces a regulatory proceeding context involving Nova Scotia's energy sector, referencing key organizations, acronyms, and topics relevant to electricity reliability, grid operations, and regulatory oversight.

Emergency Procedures The plan must be broken down into a set of emergency procedures for each key facility . These procedures state in a short and precise way the operations that are to be performed to isolate the station (preliminary oper...

AI summary Emergency procedures must be established for key facilities to isolate stations and restore power following blackouts. Procedures are mandatory, require step-by-step application, and modifications need system operator approval. They are part of a coordinated plan dependent on prior and subsequent operations.

Blackstart Procedures: These procedures state in a short and precise way the operations to be performed, to start generating units designated as having blackstart capability and used to initiate the BMPS restoration process.

AI summary Blackstart procedures outline operations to initiate generating units with blackstart capability, essential for restoring the Bulk Power System (BMPS) following a blackout or outage.

Restoration Process Diagram: A diagram of the restoration plan, showing all the BMPSs, will assist the on-shift system operator to implement the plan in a step-by-step manner in case of computer deficiencies.

AI summary A restoration process diagram for the Bulk Power System (BMPS) is designed to guide on-shift system operators through a step-by-step implementation of the restoration plan during computer system deficiencies.

Audio Communication System: An instantaneous and efficient means for the system operator in charge to communicate with each station.

AI summary The document emphasizes the need for an instantaneous and efficient communication system enabling the system operator to coordinate with each station, highlighting the critical role of real-time audio communication in operational effectiveness.

1. Blackout Function To avoid computer overload due to the avalanche of alarms and status changes following the system shutdown, this function should be active only for a very short time and be very selective to allow posting of all the ma...

AI summary The Blackout Function must be selectively activated for a short duration to prevent computer overload from excessive alarms and status updates during system shutdowns, ensuring critical alarms are prioritized.

2. Reset Function This function allows the operation, through the remote control center, of any critical circuit breaker in order to speed up the restoration process.

AI summary The Reset Function enables remote operation of critical circuit breakers via a control center to expedite power restoration during outages, enhancing system reliability and emergency response capabilities.

3. Load Restoration Function This function permits the automatic recording of the progress of the load restoration, station by station, for each subsystem.

AI summary The Load Restoration Function enables automatic tracking of load restoration progress, station by station, for each subsystem, facilitating systematic recovery of power during outages.

4.0 Testing of Critical Components Associated With Key Facilities Testing of critical components associated with key facilities shall be performed at a frequency and for a duration that is sufficient to reasonably ensure that the critical...

AI summary Critical components at key facilities must be tested sufficiently to ensure functionality during system blackouts, with minimum requirements outlined in NPCC Document A-03, 'Emergency Operation Criteria.' Testing frequency and duration are determined to address potential power source unavailability during partial or complete outages.

5.0 Control of the Restoration Process

AI summary Section 5.0 outlines the regulatory framework for controlling the restoration process in Nova Scotia's power system, emphasizing coordination among entities and adherence to reliability standards.

5.1 Control Centers As soon as the shutdown of the system is acknowledged, all remote control center system operators and neighboring system operators are notified. Application of the emergency procedures is initiated at once. The corporat...

AI summary The document outlines emergency procedures for control centers during system shutdowns, emphasizing coordination among system operators, backup teams, and neighboring utilities. Key steps include equipment inventory, load restoration monitoring, synchronization of bulk power systems (BMPS), and resuming normal operations after restoring all load.

5.2 Individual Facility After the blackout has occurred, determine: - 1. Tripped equipment; - 2. Energized or in service equipment; - 3. Breakers which have remained closed; - 4. Unavailable equipment; - 5. Proceed with emergency procedure...

AI summary Post-blackout procedures include assessing tripped and energized equipment, identifying closed breakers, addressing unavailable equipment, initiating emergency protocols, and notifying the remote control system operator. These steps focus on rapid fault diagnosis and coordination with operational authorities.

External Power Systems-Midwest ISO Restoration Overview

AI summary Overview of the Midwest ISO's external power systems restoration processes, focusing on reliability and coordination with regional entities.

System Restoration Summary The MISO has detailed coordinated restoration plans. These are reviewed yearly with participation from the MISO member companies. MISO uses a sub-regional structure and philosophy to coordinate and plan for resto...

AI summary The Midwest ISO (MISO) employs a sub-regional structure with nine geographical/electrical sub-regions to coordinate system restoration. Plans include infrastructure details (blackstart units, synchroscope locations), critical loads, and an interconnection checklist for island stability. Annual reviews with member companies ensure flexibility in restoration responses.

External Power Systems-PJM Restoration Overview In the PJM RTO, during the initial stages of a restoration, each Load Serving Entity is responsible for restoring its own customer load with internal generation or through coordinated efforts...

AI summary The PJM RTO outlines procedures for restoring power during emergencies, emphasizing coordination between Load Serving Entities and Transmission Owners. Priority is given to neighboring entities' power requests over restoring internal loads. Pre-arranged communication plans and the PJM dispatcher's role in establishing emergency communications are highlighted.

PJM Operator Responsibilities During the Restoration Process The PJM System Operator has certain responsibilities regardless of the stage of the system restoration process. Transmission Owners will have primary responsibility of restoring...

AI summary The PJM System Operator coordinates restoration efforts, manages interchange schedules, restores the 500 kV transmission system, calculates ACE, and provides updates during system restoration. Transmission Owners handle restoration until PJM resumes authority.

Ascertain System Status After a system disturbance occurs that results in a significant loss of customer load in a widespread area, it is important to determine transmission and generation loss, equipment damage, and the extent of the serv...

AI summary After a widespread system disturbance causing significant customer load loss, assessing transmission and generation losses, equipment damage, and service interruption extent is critical to understanding the event's impact and restoring reliability.

Determine Restoration Process The purpose of this step is to develop and implement a restoration strategy. This step is performed after the status of the PJM RTO is determined.

AI summary The purpose of this step is to develop and implement a restoration strategy following the determination of the PJM RTO's status.

Disseminate Information The purpose of this step is to provide updated information of the system status to appropriate personnel. After system restoration plans are established and implemented, all participants must be apprised of system c...

AI summary This step emphasizes the importance of communicating updated system status information to relevant personnel following the establishment of system restoration plans to ensure all participants are informed of current system conditions.

Implement Restoration Procedure The purpose of this step is to direct the restart of Generation Owners internal generation and load on-line generation in planned steps while maintaining system load , scheduled frequency, voltage control an...

AI summary The procedure outlines steps to restart generation and load in planned increments while maintaining system load, frequency, voltage control, and reserves. It applies when a Transmission Owner/Generation Owner is isolated and must restart without external assistance.

Member Interconnection The purpose of this step is to provide guidelines for the Transmission Owners to interconnect and control frequency, tie line , voltage schedules, share reserves and coordinate emergency procedures. This step is perf...

AI summary The purpose of the Member Interconnection step is to establish guidelines for Transmission Owners to interconnect, manage frequency and voltage, share reserves, and coordinate emergency procedures post-restart. This occurs after Transmission Owners have restarted and seek to interconnect or have coordinated restart plans while interconnected.

PJM Assumes Frequency Control This occurs when the control of an interconnected area is too burdensome for any one Local Control Center Adopted by the Members of the Northeast Power Coordinating Council, Inc. this December 22, 2008 based o...

AI summary PJM assumes frequency control when local control centers face excessive burdens. The Northeast Power Coordinating Council (NPCC) adopted this policy on December 22, 2008, following the Reliability Coordinating Committee's (RCC) recommendation, as outlined in the NPCC's amended bylaws.

1.4 Effective Date December 22, 2008 1.5 Background This Directory was developed from the draft NPCC A-13 Verification of Generator Gross and Net Real Power Capability Criteria document whose technical content was approved by the Reliabili...

AI summary This document outlines the development of a Directory based on the NPCC A-13 draft, approved by the Reliability Coordinator Committee in 2008. It applies to Generator Owners and Transmission Operators, referencing NERC ERO reliability standards and noting that printed versions become uncontrolled.

this Directory include: - 3.1 MOD-024-1 -Verification of Generator Gross and Net Real Power Capability - 3.2 TOP-002-2 Normal Operations Planning - 3.3 FAC-008-1 Facility Ratings Methodology - 3.4 FAC-009-1 Establish and Communicate Facili...

AI summary The document outlines requirements for verifying generator real power capabilities, including documentation of declared and verified gross/net real power capability, discrepancies, and exemptions. The Transmission Operator must maintain records and establish a verification program, aligning with NPCC regional reliability standards.

5.4.3 Hydro Generators - 5.4.3.1 Hydro capability shall be determined on a generation facility or an individual generator basis. - 5.4.3.2 The Gross Real Power Capability and Net Real Power Capability shall be determined on the basis of th...

AI summary The section outlines criteria for determining hydro generator capabilities, emphasizing gross and net real power based on water availability and head. Verification methods include testing, historical data, and performance tracking during seasonal periods.

5.4.5 Intermittent Power Sources For intermittent power resources (wind, solar, tidal or geo-thermal generators) the manufacturer's data, performance tracking and operating historical data shall be used to determine generator or generation...

AI summary The document outlines procedures for determining the Gross and Net Real Power Capability of intermittent power sources (wind, solar, etc.) using manufacturer data and historical performance. It specifies verification methods for multiple-generator facilities and exemption criteria for testing based on operational records or commissioning data.

Basic Flow Chart for Verification of Generator Gross and Net Real Power Capability 1 These terms will be moved and grouped under a separate Directory when all other Directories are developed.

AI summary The document outlines a flowchart for verifying generator gross and net real power capability, noting that terminology will be reorganized into a dedicated directory once other directories are finalized. Visual aids (images) are referenced but not described in text.

Regional Reliability Reference Directory # 10 Verification of Generator Gross and Net Reactive Power Capability Task Force on Coordination of Operations Revision Review Record: December 22, 2008 Adopted by the Members of the Northeast Powe...

AI summary The document outlines the adoption of a revision review record by the Northeast Power Coordinating Council (NPCC) on December 22, 2008, based on the Reliability Coordinating Committee's (RCC) recommendation. It pertains to verifying generator gross and net reactive power capability under the Task Force on Coordination of Operations (TFCO).

5.4.2 Intermittent Power Resources For intermittent power resources (wind, tidal or geo-thermal generators) the manufacturers' or commissioning data can be used until sufficient performance tracking data is available to verify generator or...

AI summary The text outlines procedures for verifying reactive power capabilities of intermittent power resources (wind, tidal, geothermal) using manufacturer data until performance data is available. It also addresses verification for multiple generators and requirements to identify limitations affecting declared reactive power capabilities.

Basic Flow Chart for Verification of Generator Gross and Net Reactive Power Capability

AI summary The document outlines a flow chart for verifying generator gross and net reactive power capability, critical for ensuring grid reliability. It involves NSUARB and NSPI, highlighting regulatory and operational processes in Nova Scotia's power system.

NPCC Regional Reliability Reference Directory # 12 Under frequency Load Shedding Program Requirements Task Force on Coordination of Operations Revision Review Record: June 26th, 2009 March 3rd, 2010 Adopted by the Members of the Northeast...

AI summary The NPCC adopted the Under Frequency Load Shedding Program Requirements on June 26, 2009, following the Reliability Coordinating Committee's recommendation. The adoption aligns with the NPCC's amended bylaws dated July 24, 2007, addressing regional reliability and coordination of operations.

1.3 Objective This Directory presents the basic criteria for the design and implementation of under frequency load shedding programs to ensure that declining frequency is arrested and recovered in accordance with established NPCC performan...

AI summary The Directory establishes criteria for underfrequency load shedding programs to prevent system collapse by adhering to NPCC performance requirements, ensuring frequency stability through load-generation balance.

1.4 Effective Date June 26th, 2009 The effective date of this Directory also is the initial date of a six-year implementation plan for under frequency load shedding program in the portion of NPCC in the Eastern Interconnection and a two-ye...

AI summary The effective date of June 26, 2009, marks the start of a six-year implementation plan for underfrequency load shedding in the NPCC portion of the Eastern Interconnection and a two-year plan in the Québec Interconnection.

1.5 Background This Directory was developed from the automatic Under frequency Load Shedding requirements in NPCC Directory #2, Emergency Operations, and the recommendations and implementation plans provided in the study reports: 2006 Asse...

AI summary This Directory was developed based on NPCC Directory #2's Under frequency Load Shedding requirements and study reports from 2006 and 2008, approved by the Reliability Coordinating Committee on November 19, 2008.

1.6.1 Functional Entities Balancing Authorities Transmission Operators Generator Owners

AI summary The section lists three key functional entities in the energy sector: Balancing Authorities, Transmission Operators, and Generator Owners. These entities play critical roles in maintaining grid stability, transmitting electricity, and managing power generation, respectively, within the regulatory framework.

3.0 NERC ERO Reliability Standard Requirements The NERC ERO Reliability Standards containing Requirements that are associated with this Directory include, but may not be limited to: - 3.1 [EOP-003:](ftp://www.nerc.com/pub/sys/all_updl/stan...

AI summary This section outlines the NERC ERO Reliability Standard Requirements, including load shedding plans and regional UFLS programs, and specifies additional NPCC criteria for under frequency load shedding, with specific frequency thresholds and requirements for the Eastern and Québec Interconnections.

Threshold Setting Block Size Total Operating Time (1) Stage 1 59.5 Hz 28 percent 300 ms Notes:

AI summary The table outlines parameters for Stage 1, including a threshold setting of 59.5 Hz, a block size of 28 percent, and a total operating time of 300 ms. These details are likely related to grid reliability or control mechanisms.

- (1) Total operating time is the load-weighted average for all load within a Balancing Authority area, with maximum deviation for any load limited to ±50 ms. - 5.2.4 Entities with less than 25 MW of end-use load connected to its facilitie...

AI summary The text outlines requirements for Under Frequency Load Shedding (UFLS) programs, including exemptions for entities with less than 25 MW of load, aggregated UFLS programs for entities with less than 100 MW, and relay operating time specifications. It also addresses specific requirements for the Québec Interconnection, including staged load shedding and approval processes.

5.4 Generator Under frequency Protection Requirements Generators shall not be tripped for under-frequency conditions in the area above the curve in Figure 1, except as provided for in Sections 5.4.1 and 5.4.2. 5.4.1 It is recognized that,...

AI summary Generators must not be tripped for under-frequency conditions above a specified curve, except under Sections 5.4.1 and 5.4.2. Special cases require load shedding equivalent to the generation tripped, with Balancing Authority notification. Generator Owners cannot modify under-frequency trip settings for exempt generators to avoid higher frequency tripping.

5.5 UFLS Program Assessment Requirements - 5.5.1 Studies shall be performed by the associated Transmission Operator to ensure satisfactory voltage and loading conditions after automatic load shedding . - 5.5.2 The Task Force on System Stud...

AI summary Section 5.5 outlines requirements for UFLS program assessments, including studies by Transmission Operators to ensure voltage/loading conditions post-load shedding and triennial coordination by the Task Force on System Studies with NPCC Balancing Authorities. Compliance monitoring is mandated, with revisions to the NPCC Directory requiring RCC and Full Member approval.

Appendix A Definition of Terms[2](#page-89-0) - Bulk power system The interconnected electrical systems within northeastern North America comprised of system elements on which faults or disturbances can have a significant adverse impact ou...

AI summary Defines key terms such as 'Bulk power system,' 'Island,' and 'Load' within the context of electrical systems, emphasizing their technical characteristics and impacts on power reliability and distribution.

NPCC Specific Definitions: Firm Load — Loads that are not Interruptible Loads . Interruptible Load — Loads that are interruptible under the terms specified in a contract. - Load Shedding The process of deliberately removing (either manuall...

AI summary The text defines key terms related to power system operations, including Firm Load, Interruptible Load, Load Shedding, and Relay. It emphasizes system integrity through load management and notes that terminology will be reorganized into a dedicated directory. Technical definitions focus on reliability and control mechanisms.

Operating Reserve Criteria Adopted by the Mem bers of the Nor theast Power Coordinating Council March 30, 1972, based on recommendation by the Operating Pr ocedure Coordinating Committee and the System Design Coordin ating Committee, in ac...

AI summary The Operating Reserve Criteria, adopted by the Northeast Power Coordinating Council (NPCC) in 1972, outlines procedures for operating reserves, with multiple revisions and reviews over subsequent decades, reflecting ongoing updates to system reliability standards.

1.0 Purpose In the continuous operation of electric power systems, operating capacity is required to meet forecast demand, including an allowance for error, to provide protection against equipment failure which has a reasonably high probab...

AI summary This document establishes terminology and minimum requirements for operating reserve to ensure reliability in the NPCC Region, aligning with NERC standards. It emphasizes the need for operating capacity to meet demand, account for equipment failure risks, and regulate tie line power flow.

3.1 Ten-Minute Reserve Requirement The ten-minute reserve available to each Area shall at least equal its first contingency loss multiplied by the Contingency Reserve Adjustment Factor for the most recently completed quarter. Ten-minute re...

AI summary The ten-minute reserve requirement mandates that each Area maintain reserves equal to its first contingency loss multiplied by a quarterly adjustment factor. Restoration timelines are 105 minutes for reportable events and 90 minutes otherwise, with NERC Energy Emergency Alerts required if deadlines are missed. Exceptions apply during abnormal conditions per NPCC documents.

3.2 Thirty-Minute Reserve Requirement The thirty-minute reserve available to each Area shall at least equal onehalf its second contingency loss . Thirty-minute reserve shall be sustainable as specified in section 3.7 below. Each Area shall...

AI summary The thirty-minute reserve requirement mandates that each Area maintain reserves equal to half its second contingency loss, with restoration within four hours if deficient. Corrective actions are required for long-term deficiencies, except during abnormal conditions as outlined in NPCC Document C-20.

3.3 Regulating Reserve Requirement The reserve on Automatic Generation Control in each Area shall be sufficient to meet NERC control performance standards. Except during significant frequency excursions as provided in NPCC Regional Reliabi...

AI summary The reserve on Automatic Generation Control (AGC) in each Area must meet NERC control performance standards. AGC equipment must remain operational except during significant frequency excursions as outlined in NPCC's Emergency Operations guidelines.

3.4 Synchronized Reserve Requirement 100 percent of an Area 's ten-minute reserve requirement shall be synchronized reserve except as described below. An Area shall adjust its synchronized reserve requirement based on its ability to recove...

AI summary The synchronized reserve requirement mandates 100% of an Area's ten-minute reserve, adjustable based on performance in recovering from reportable events. Successful ACE recovery within 15 minutes reduces the requirement by 10% per success, while failures increase it by 20%. Adjustments are calculated monthly and applied the following month.

3.5 Com pliance with NERC Disturbance Control Standard (DCS) Areas within NPCC shall calculate and report compliance with the Disturbance Control Standard as stipulated in Document C-09, Monitoring Procedures for Operating Reserve Criteria...

AI summary NPCC areas must comply with NERC's Disturbance Control Standard (DCS) using a 15-minute recovery period, achieving 100% compliance for reportable disturbances. Non-compliance requires increasing ten-minute reserve requirements by the Contingency Reserve Adjustment Factor.

3.6 Distribution of Reserve Operating reserve available to an Area shall be distributed so as to ensure that it can be utilized without exceeding individual element ratings or transfer limitations.

AI summary The distribution of operating reserve within an Area must ensure utilization without exceeding individual element ratings or transfer limitations, emphasizing system reliability and operational constraints.

3.7 Sustainability of Reserve " Synchronized Reserve, Ten Minute Reserve and Thirty Minute Reserve acquired by an Area, if activated, shall be sustainable for at least one hour from the time of activation. Areas shall determine their susta...

AI summary The document establishes that synchronized, ten-minute, and thirty-minute reserves activated by an Area must sustain for at least one hour. Sustainability requirements are determined by Areas based on compliance with standards and their operational characteristics.

3.8 Activation Of Inter- Area Reserve When an Area acquires operating reserve from another Area , the provider of the operating reserve shall deliver an increase in energy equal to the amount of operating reserve acquired when the acquirin...

AI summary The activation of inter-area operating reserve requires the providing area to supply energy equal to the reserve acquired upon activation requests. Providers may not curtail existing energy sales to support activation unless facing their own contingency. Acquired reserves must meet sustainability criteria outlined in section 3.7.

3.9 Shared Activation Of Ten-Minute Reserve Recovery from a sudden large loss of generation can be achieved faster by jointly activating reserve in several areas. NPCC and PJM have implemented such an arrangement in order to: - more quickl...

AI summary The Shared Activation of Ten-Minute Reserve allows faster recovery from large generation losses by jointly activating reserves across areas. NPCC and PJM implemented this to improve reliability and meet NERC standards. Implementation details are outlined in NPCC documents C-12 and C-38, with specific resource eligibility requirements in section 3.10.

4.0 Procedures 4.1 Scheduling - 4.1.1 Each Area shall ensure that sufficient resources are available such that its requirements for operating reserve are met at all times. - 4.1.2 An Area shall meet its requirement for operating reserve us...

AI summary Section 4.0 outlines procedures for scheduling, requiring areas to maintain sufficient operating reserve through internal resources or external capacity, considering uncertainties like load forecast errors to ensure reliability.

4.2 Daily Operation 4.2.1 Energy associated with operating reserve may be interchanged with the understanding that it is immediately recallable. The energy associated with reserve that is utilized to meet AGC requirements to provide satisf...

AI summary The text outlines rules for managing operating reserves and ten-minute reserves in power systems, emphasizing that energy from operating reserves cannot be sold when used for AGC requirements. It details procedures for areas acquiring reserve energy, adjusting reserve requirements during contingencies, and referencing NPCC documents for emergency operations.

5.0 Responsibilities - 5.1 Each Area is responsible for observing the criteria and procedures contained herein, identifying a loss of capacity within its Area and activating operating reserve available to that Area . - 5.2 Each Area is res...

AI summary Section 5.0 outlines responsibilities for managing operating reserves and frequency response. Areas must monitor capacity and activate reserves, while the NPCC Task Force on Coordination of Operations (TFCO) and Control Performance Working Group (CO-1) oversee compliance with reliability standards and report to NERC.

1.0 Introduction The NPCC Glossary of Terms (the Glossary) originated as Appendix A to the Criteria for Review and Approval of Documents (Document A-1). It includes terms from NPCC Criteria (A), Guideline (B) and Procedure (C) Documents, a...

AI summary The NPCC Glossary of Terms originated as Appendix A to the Criteria for Review and Approval of Documents. It incorporates terms from NPCC, NERC, and IEEE sources, with definitions organized alphabetically and sub-definitions under main terms.

2.0 The Glossary Applicable emergency limits — These limits depend on the duration of the occurrence, and on the policy of the various member systems of NPCC regarding loss of life to equipment, voltage limitations, etc. Emergency limits a...

AI summary The glossary defines terms related to emergency limits, system stability, and control areas. Emergency limits allow temporary operation during outages, with voltage limits ensuring stability and preventing bulk power system disruptions. 'Area' refers to regional control areas defined by NERC, including the Maritimes. Equipment ratings and cascading outage prevention are emphasized.

A-1 (A-3, A-6, C-1) Area Control Error — The instantaneous difference between actual and net scheduled interchange , taking into account the effects of frequency bias.

AI summary Area Control Error (ACE) is defined as the instantaneous difference between actual and net scheduled interchange, considering frequency bias effects. This metric is critical for monitoring and maintaining grid stability in power systems.

NERC (C-1) Automatic Generation Control (AGC) — Equipment that automatically adjusts a Control Area 's generation to maintain its interchange schedule plus its share of frequency regulation. The following AGC modes are typically available:...

AI summary The document defines Automatic Generation Control (AGC) as equipment that adjusts a Control Area's generation to maintain its interchange schedule and frequency regulation. It outlines the Tie Line Bias Control mode, which considers both frequency and net interchange terms of Area Control Error (ACE).

Automatic Generation Control (AGC) – continued - b. Constant Frequency (Flat Frequency) Control Automatic generation control with the net interchange term of Area Control Error ignored. This Automatic Generation Control mode attempts to ma...

AI summary The text describes two Automatic Generation Control (AGC) modes: Constant Frequency Control (ignoring Area Control Error's interchange term) and Constant Net Interchange Control (ignoring frequency). Both aim to maintain either frequency or net interchange independently, highlighting operational strategies for grid stability.

NERC (A-3, C-1) Availability — A measure of time a generating unit, transmission line, or other facility is capable of providing service, whether or not it actually is in service. Typically, this measure is expressed as a percent available...

AI summary The document defines 'Availability' as a metric measuring the proportion of time a generating unit or transmission line is capable of providing service, typically expressed as a percentage. This definition is critical for assessing reliability in power systems under NERC standards.

A-2 Blackstart Capability — The ability of a generating unit or station to go from a shutdown condition to an operating condition and start delivering power without assistance from the electric system.

AI summary Defines 'Blackstart Capability' as the ability of a generating unit to transition from shutdown to operational status and deliver power without external system assistance, highlighting its critical role in grid reliability and emergency restoration.

A-10, (C-1) Bulk power system — The interconnected electrical systems within northeastern North America comprised of system elements on which faults or disturbances can have a significant adverse impact outside of the local area .

AI summary Defines the bulk power system in northeastern North America, emphasizing its interconnected nature and the potential for significant adverse impacts from faults or disturbances beyond the local area.

C-13 Capability, Operating — The maximum load carrying ability of generating equipment or other electrical apparatus under specified conditions for a given time interval.

AI summary Defines 'Operating Capability' as the maximum load-carrying capacity of generating equipment or electrical apparatus under specified conditions for a defined time interval, emphasizing technical performance parameters.

C-1 - Capacity The rated continuous load-carrying ability, expressed in megawatts (MW) or megavolt-amperes (MVA) of generation , transmission, or other electrical equipment. - Baseload Capacity Capacity used to serve an essentially constan...

AI summary The text defines various types of electrical system capacity, including baseload, firm, intermediate, net, and peaking capacity, each with specific operational characteristics and usage scenarios related to generation, transmission, and demand management.

NERC (C-1) Capacity Benefit Margin (CBM) — See under Transfer Capability. Commutation Failure — A fault in a thyristor valve group where the current transfer from one valve to the next is interrupted.

AI summary The document defines 'Capacity Benefit Margin (CBM)' as referenced under 'Transfer Capability' and describes 'Commutation Failure' as a fault in thyristor valve groups where current transfer between valves is interrupted. These terms relate to technical aspects of power system reliability and HVdc technology.

A-5, C-15 Component — refers to components of equipment or protection systems rather than elements of a power system. See Element .

AI summary The text defines 'Component' as parts of equipment or protection systems, distinguishing them from 'Element' in the context of power system terminology. This clarification is critical for regulatory proceedings involving technical specifications and system reliability standards.

A-5, B-11 Contingency — An event, usually involving the loss of one or more elements , which affects the power system at least momentarily.

AI summary A contingency is defined as an event involving the loss of one or more system elements, temporarily impacting the power system. The term emphasizes temporary disruptions rather than permanent failures.

NPCC Specific Definitions: - NPCC Emergency Criteria Contingencies The set of contingencies to be observed when operating the bulk power system under emergency conditions. (C-1, also reference Document A-2, Section 6.2, Emergency Transfers...

AI summary The document defines NPCC-specific contingencies for bulk power system operations, distinguishing between emergency and normal criteria, single/double element contingencies, and limiting contingencies. These definitions reference operational guidelines in Document A-2 and are critical for reliability coordination.

Contingency continued First Contingency Loss — The largest capacity outage including any assigned Ten-Minute Reserve which would result from the loss of a single element (A-6, C-1) Second Contingency Loss — The largest capacity outage whic...

AI summary The text defines two contingency loss scenarios: First Contingency Loss as the largest capacity outage from a single element failure, and Second Contingency Loss as the largest capacity outage after accounting for the first loss. Both are referenced to appendices A-6 and C-1.

NERC (except as indicated) Contingency Reserve Adjustment Factor — A factor used in determining the additional ten-minute reserve that each Area , not meeting the DCS requirement for a given quarter, must carry. It is calculated using the...

AI summary Defines the Contingency Reserve Adjustment Factor (CRAquarter) used to calculate additional ten-minute reserves for areas not meeting Dynamic Control Systems (DCS) requirements, based on the formula CRAquarter = 2 – (average DCS percentage for the quarter).

A-6 Control Area — An electric system or systems, bounded by interconnection metering and telemetry, capable of controlling generation to maintain its net interchange schedule with other Control Areas and contributing to frequency regulati...

AI summary A Control Area is defined as an electric system bounded by interconnection metering and telemetry, responsible for controlling generation to maintain interchange schedules with other Control Areas and contributing to interconnection frequency regulation.

A-5 Critical Components — Equipment required for continued and proper operation of a key facility in the event of a total loss of AC supply. Critical components include but are not limited to blackstart generating units, substation backup...

AI summary Defines critical components required for key facility operation during total AC supply loss, including blackstart units, backup power systems for substations, control centers, and telecommunications infrastructure.

Disturbance continued System Disturbance — An event characterized by one or more of the following phenomena: the loss of power system stability ; cascading outages of circuits; oscillations; abnormal ranges of frequency or voltage or both....

AI summary Defines system disturbance as events causing instability, cascading outages, or abnormal frequency/voltage. Economic dispatch is optimizing power delivery costs by allocating generation requirements.

B-3, C-18 (IEEE definition PE 94-1991) Element — Any electric device with terminals that may be connected to other electric devices, such as a generator, transformer, circuit, circuit breaker, or bus section. Limiting Element — The element...

AI summary The text defines 'Element' as any electric device with terminals connected to other devices, and 'Limiting Element' as an element operating at its rating or following a contingency that establishes a system limit. These definitions relate to system reliability and operational constraints in electrical systems.

NERC (slightly modified) Emergency — Any abnormal system condition that requires automatic or manual action to prevent or limit loss of transmission facilities or generation supply that could adversely affect the reliability of the electri...

AI summary The text defines an 'Emergency' in the context of electric system reliability as an abnormal condition requiring action to prevent loss of transmission facilities or generation supply, which could adversely impact system reliability.

NPCC Specific Definition: Emergency — An Emergency is considered to exist in an Area if firm load may have to be shed. (TFCO) C-38 Emergency Regional Reserve Redispatch — The regional coordination of actions to enhance reliability among Ar...

AI summary The NPCC defines 'Emergency' as a situation where firm load may need to be shed, with 'Emergency Regional Reserve Redispatch' involving regional coordination to enhance reliability during reserve deficiencies. These definitions emphasize system reliability and inter-area coordination protocols.

Fault — An electrical short circuit . Permanent Fault — A fault which prevents the affected element from being returned to service until physical actions are taken to effect repairs or to remove the cause of the fault.

AI summary The document defines 'Fault' as an electrical short circuit and 'Permanent Fault' as a fault requiring physical repairs to restore service. These definitions establish technical terminology for fault classification in power systems.

Fault Clearing - Delayed fault clearingFault clearing consistent with correct operation of a breaker failure protection group and its associated breakers, or of a backup protection group with an intentional time delay. - High speed fault c...

AI summary The text defines three fault-clearing categories: delayed (with intentional time delays for breaker failure or backup protection), high-speed (using relays with ≤50ms clearing time), and normal (standard protection system operation). IEEE C37.100-1981 is cited for high-speed relay standards, emphasizing six cycles (100ms) as the planning benchmark.

NERC (C-1) Generation Rejection — The process of deliberately removing preselected generation from a power system, or initiating HVdc power runback, in response to a contingency or an abnormal condition in order to maintain the integrity o...

AI summary The text defines 'Generation Rejection' as the deliberate removal of preselected generation from a power system or initiating HVdc power runback in response to a contingency to maintain system integrity, with the synonym 'Generator Dropping.'

A-5 Harmonic current — A periodic component of current having a frequency that is an integral multiple of that currents fundamental frequency. Harmonic currents are normally measured in amperes or in percent of the fundamental frequency cu...

AI summary Harmonic currents are periodic current components with frequencies that are integer multiples of the fundamental frequency, measured in amperes or as percentages of fundamental current. Sources include HVdc converters, Static Var Compensators (SVC), and geomagnetically induced currents (GIC).

NERC Interchange — Electric power or energy that flows from one entity to another. Actual Interchange — Metered electric power that flows from one entity to another. - Interchange Schedule An agreed-upon transaction size (megawatts), start...

AI summary The text defines key terms related to electric power interchange, including Actual Interchange, Interchange Schedule, and Scheduled Interchange. It outlines processes for scheduling and managing power flows between entities, emphasizing megawatt transactions, Control Area coordination, and wheeling agreements.

NERC (A-3, C-1) Key Facilities — Facilities required to establish a basic minimum power system following a system blackout. These facilities are essential to the restoration plan of the Control Area and include generating stations having b...

AI summary The text outlines key facilities essential for restoring a basic minimum power system post-blackout, including blackstart units, transmission elements, control centers, and telecommunications infrastructure critical for protection and control within the Control Area.

A-3 Load — The electric power used by devices connected to an electrical generating system. (IEEE Power Engineering). Also see Demand .

AI summary Defines 'Load' as electric power used by connected devices, referencing IEEE Power Engineering. Also cross-references 'Demand' for related concepts.

A-3 (C-1) Load Shedding — The process of deliberately removing (either manually or automatically) preselected customers' load from a power system in response to an abnormal condition to maintain the integrity of the system and minimize ove...

AI summary Load shedding is defined as the deliberate removal of preselected customers' load from a power system during abnormal conditions to maintain system integrity and minimize outages. The process may be manual or automatic, focusing on preserving grid stability through targeted load reduction.

A-10 Local area — An electrically confined or radial portion of the system. The geographic size and number of system elements contained will vary based on system characteristics. A local area may be relatively large geographically with rel...

AI summary The text defines 'Local area' as an electrically confined portion of the power system, varying in size and complexity. It also outlines 'Negative Shared Activation Reserve Energy,' a mechanism involving energy transfers between areas during resource losses, with specific ramp rate constraints and interchange schedule protocols.

A-6 - Operating Procedures A set of policies, practices, or system adjustments that may be automatically or manually implemented by the system operator within a specified time frame to maintain the operational integrity of the interconnect...

AI summary The document defines operating procedures for maintaining interconnected electric system integrity, including automatic systems like special protection systems (SPS) and manual procedures for pre- and post-contingency scenarios. These protocols aim to prevent overloads and address system issues through proactive and reactive measures managed by system operators.

Outage - Forced Outage The removal from service of a generating unit, transmission line, or other facility for emergency reasons or a condition in which the equipment is unavailable due to unanticipated failure. - Forced Outage Rate The ho...

AI summary The text defines key outage-related terms, including forced outages (emergency unavailability), forced outage rates (percentage of forced downtime), maintenance outages (planned work on deferrable elements), and planned outages (scheduled inspections/overhauls). These definitions focus on equipment availability and reliability metrics.

NERC (slightly modified) Power Swing — A transient change in the power flows on a system, usually of an oscillatory nature.

AI summary Defines 'Power Swing' as a transient, oscillatory change in power flows on a system, relevant to system reliability and power system stability.

A-1 Protection — The provisions for detecting power system faults or abnormal conditions and taking appropriate automatic corrective action. Protection group — A fully integrated assembly of protective relays and associated equipment that...

AI summary The text defines power system protection mechanisms, emphasizing automatic fault detection and corrective actions. It describes a 'protection group' as an integrated assembly of relays and equipment designed to handle specific system elements independently.

Rating continued - Normal Rating 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...

AI summary The text defines 'Normal Rating' and 'Emergency Rating' for electrical equipment, specifying their capacities to handle loading without compromising equipment life. Normal Rating refers to daily demand cycles, while Emergency Rating allows temporary overloading with acceptable equipment life loss.

Reclosing continued Synchronism-check — refers to the determination that acceptable voltages exist on the two sides of the breaker and the phase angle between them is within a specified limit for a specified time. C-38 Regional Reserve Def...

AI summary The text defines technical terms related to power system operations, including 'Synchronism-check' for voltage and phase angle verification, 'Regional Reserve Deficiency' for insufficient ten-minute reserves across areas, and 'Regional Reserve Sharing' for cross-area reserve coordination. These concepts address grid reliability and resource allocation.

A-6 and C-38 Regional Reserve Sharing Energy — Energy delivered to a contingent Area from assisting Areas that is converted from delivered Shared Activation Reserve Energy after the Shared Activation Reserve Energy has been delivered for 3...

AI summary The text defines 'Regional Reserve Sharing Energy' as energy transferred from assisting areas to a contingent area, converted from 'Shared Activation Reserve Energy' after 30 minutes of delivery. It specifies a 60-minute maintenance period, ramp-out at a 10-minute rate following mutual interchange schedules established via communication between areas.

B-1 and C-1 Relay — An electrical device designed to respond to input conditions in a prescribed manner and after specified conditions are met to cause contact operation or similar abrupt change in associated electric control circuits. (Al...

AI summary Defines 'relay' as an electrical device responding to input conditions and 'reliability' as the bulk electric system's performance in delivering electricity within accepted standards. Reliability is further divided into adequacy and security aspects.

Reliability-continued - Adequacy The ability of the electric system to supply the aggregate electrical demand and energy requirements of the customers at all times, taking into account scheduled and reasonably expected unscheduled outages...

AI summary Defines 'Adequacy' and 'Security' in electric systems, emphasizing supply during outages and resilience against disturbances like short circuits and element losses.

NERC (slightly modified) - Reportable Events System disturbances involving losses of load , generation or transmission facilities within NPCC Control Areas which equal or exceed the following criteria are reportable events: - (1) Actual ne...

AI summary NERC's modified criteria for reportable system disturbances in NPCC Control Areas include thresholds for interchange deviations (500 MW/Maritime 300 MW), generation/load loss (500 MW/Maritime 300 MW), and frequency deviations (0.03 Hz/Hydro-Quebec 0.5 Hz). Events outside NPCC are analyzed but not reported under NERC standards.

A-6 (also see NERC DAWG System Disturbances Reports) Reserve — In normal usage, reserve is the amount of capacity available in excess of the demand Reserve Requirement— That capability above firm system demand required to provide for regul...

AI summary The text defines 'reserve' as excess capacity over demand and 'reserve requirement' as the capability needed to manage regulation, load forecasting errors, equipment outages, and local supply adequacy in power systems.

Reserve continued - Operating Reserve The sum of ten-minute and thirty-minute reserve . (A-3, A-6, C-1) - Reserve on Automatic Generation Control (AGC) That portion of synchronized reserve which is under the command of an automatic control...

AI summary The text defines various reserve capacities in power systems, including ten-minute, thirty-minute, and synchronized reserves, along with the role of demand-side measures in resource contributions. It also introduces 'Shared Activation Reserve Energy' as energy transferred between areas under specific operational conditions.

A-1 Short Circuit — An abnormal connection (including an arc) of relatively low impedance, whether made accidentally or intentionally, between two points of different potential. Note: The term fault or short-circuit fault is used to descri...

AI summary A short circuit is defined as an abnormal low-impedance connection between two points of different potential, whether accidental or intentional. The term 'fault' or 'short-circuit fault' is used interchangeably to describe this phenomenon in regulatory contexts.

A-10, IEEE C37.100-1981 Significant adverse impact — With due regard for the maximum operating capability of the affected systems, one or more of the following conditions arising from faults or disturbances , shall be deemed as having sign...

AI summary The document defines 'significant adverse impact' in power systems, including instability, dynamic response issues, equipment tripping, and violations of emergency voltage/transmission limits. Key conditions involve uncontrollable instability, undamped oscillations, improper protection system operations, and breaches of emergency operational thresholds.

NERC (slightly modified) (C-1) Stability Limit — 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.

AI summary Defines 'Stability Limit' as the maximum power flow through a system point while maintaining stability. Contextualized within NERC's modified framework, emphasizing system-wide stability parameters in power transmission.

NERC (C-1) Static Var Compensator (SVC) — A combination of controlled shunt reactors and switched capacitor banks, used to affect the reactive power flow of the system or to regulate the system voltage.

AI summary The Static Var Compensator (SVC), comprising controlled shunt reactors and switched capacitor banks, is used to manage reactive power flow and regulate system voltage in electrical systems. This technology enhances grid stability by dynamically adjusting to system demands, ensuring efficient power transmission and preventing voltage instability.

A-5, B-3, C-5 and C-18 Supervision — see Reclosing Supervisory Control — A form of remote control comprising an arrangement for the selective control of remotely located facilities by an electrical means over one or more communications med...

AI summary The text defines 'Supervision' as related to 'Reclosing' and describes 'Supervisory Control' as a remote control method for managing facilities via communication media, highlighting technical operational aspects of grid systems.

B-1 NPCC Document A-07 NPCC Glossary of Terms July 17, 2007 Synchronize — The process of connecting two previously separated alternating current apparatuses or systems after matching frequency, voltage, phase angles, etc. (e.g., parallelin...

AI summary The text defines technical terms from the NPCC Glossary, including 'synchronize,' 'synchronous condenser,' and 'teleprotection,' emphasizing grid operations and voltage control. These definitions relate to power system reliability and communication-based protection mechanisms.

NERC A-3 (C-1) Tie Line Bias — A mode of operation under automatic generation control in which the area control error is determined by the actual net interchange minus the biased scheduled net interchange .

AI summary Tie Line Bias refers to a mode in automatic generation control where area control error (ACE) is calculated as the difference between actual net interchange and biased scheduled net interchange, influencing grid reliability and control mechanisms.

First Contingency Incremental Transfer Capoability continued - 1. For the existing or planned system configuration, and with normal (pre- contingency ) operating procedures in effect, all facility loadings are within normal ratings and all...

AI summary The text outlines system stability requirements for handling single-element contingencies, defining terms like FCITC and NITC. It emphasizes maintaining normal ratings during pre-contingency operations and emergency ratings post-contingency, ensuring power system stability through dynamic power swing absorption and automatic control systems.

NPCC Inc. Reliability Compliance and Enforcement Program Adopted by the Mem bers of the Northeas t Power Coordinating Council on mm , dd, yyyy, based on recommendation by the Reliab ility Coordinating Committee, in accordance with parag ra...

AI summary The NPCC Inc. Reliability Compliance and Enforcement Program was adopted by the Northeast Power Coordinating Council based on the Reliability Coordinating Committee's recommendation, aligning with NPCC Inc. Bylaws. The document outlines revisions dated November 2001, April 2004, January 2006, and December 2007.

1.1 Non- member Facilities A Member, through whose facilities a non-member connects with or proposes to connect with the NPCC Inc. bulk power system shall use its best efforts to assure that the arrangements for such connection are consist...

AI summary A Member must ensure non-member connections to the NPCC Inc. bulk power system comply with NPCC Inc. bylaws and criteria. This requirement emphasizes alignment with established reliability and operational standards for interconnections.

2.0 Reliability Criteria

AI summary This section outlines the reliability criteria for the power system, referencing key organizations and standards such as NERC and NPCC. It emphasizes the importance of maintaining system reliability through coordinated efforts and adherence to established protocols.

2.1 Development of Criteria The criteria utilized in assessing compliance have been developed by NPCC Inc. consistent with the North American Electric Reliability Council broad-based standards. NPCC Inc. has implemented its Open Process as...

AI summary The criteria for compliance were developed by NPCC Inc. in alignment with NERC standards, utilizing an Open Process to ensure non-discrimination and industry input in their establishment and modification.

5.1 Violations of Reliability Criteria Table 1 defines the sanctions for violations to the criteria as described in the Compliance Templates shown in Appendix A. Not all Compliance Templates require all four levels of non-compliance. Excep...

AI summary This section outlines the sanctions for violations of reliability criteria, referencing Compliance Templates in Appendix A. It clarifies that not all templates apply all four levels of non-compliance and that criteria take precedence over templates where there is an inconsistency.

Area Transmission Review Standard: The interconnected trans mission sy stems sh all be planned, designed, and constructed to reliably meet projected c ustomer electricity demand and energy requirements in ac cordance with NPC C Inc. Basic...

AI summary The document outlines standards for interconnected transmission systems, requiring planning and design to meet customer demand per NPCC Inc. guidelines (Documents A-2 and B-4). Studies must align with NPCC's criteria for transmission reviews and system operation.

Full (100%) Compliance An annual Area Transmission Review Report, including all supporting documentation in accordance with Document B-4 was submitted to TFSS and the Area's planned bulk power system meets the requirements of Document A-2....

AI summary The Area submitted an annual Area Transmission Review Report to TFSS, complying with Document B-4 and A-2 requirements. Reports for Interim/Intermediate Reviews must be submitted by year-end, while Comprehensive Reviews by April 1st of the following year.

Non-Compliance - Level 1: An Area Transmission Review was submitted, but was incomplete in meeting the requirements of Document B-4. - Level 2: An Area Transm ission Review was submitted. Ho wever, the Area 's planned bulk power system was...

AI summary The text outlines four levels of non-compliance related to the submission of an Area Transmission Review and the Bulk Power System's adherence to A-2 criteria. Levels 1-3 involve varying degrees of incomplete submissions or noncompliance, with corrective actions required. Level 4 refers to no submission and directs to the Policy on Lateness.

Underfrequency Load Shedding Standard: Each NPCC Inc. Area shall plan and im plement an Underfrequency Load Shedding Program as specified in sect ion 4.6 of the NPCC Inc. Emergency Operation Criteria (Document A-3). References: NPCC Inc. D...

AI summary The NPCC Inc. requires each Area to implement an Underfrequency Load Shedding Program as outlined in section 4.6 of its Emergency Operation Criteria (Document A-3), ensuring reliability during frequency drops.

Full (100%) Compliance The Area load-shedding program fully complies with the requirements of the NPCC Inc. Emergency Operation Criteria (Document A-3), Section 4.6.

AI summary The Area load-shedding program is confirmed to fully comply with the NPCC Inc.'s Emergency Operation Criteria (Document A-3), Section 4.6, ensuring alignment with established emergency operational standards.

Non-Compliance Level 1: Deficiencies in Area load shedding capability were reported and a plan was submitted by the Area to correct the deficiencies. Deficiencies were corrected within five (5) months of the end of the current reporting pe...

AI summary The document outlines four levels of non-compliance related to Area load shedding capability, specifying correction timelines (5–12 months) and percentage thresholds (90–100% of required load shedding). It references Document A-8 from NPCC Inc. and Section 5.2 on lateness, highlighting deficiencies in Underfrequency Load Shedding (UFLS) programs and incomplete corrective plans.

Key Facility and Critical Components List Standard: Each Area shall m aintain an inv entory of key facilities and their critical components required for th e energization of th e basic minimum power system to ensure a successful system res...

AI summary The document outlines a regulatory standard requiring each Area to maintain an inventory of key facilities and critical components essential for energizing the basic minimum power system to ensure successful system restoration, referencing Section 4.11 of the NPCC Inc. Emergency Operation Criteria (Document A-3).

Full (100%) Compliance Each Area shall provide to NPCC Inc. , on a confidential basis, t heir current key facilities and critical components list annually . The list shall identify critical components associated with the following applicab...

AI summary The document mandates that each Area submit an annual, confidential list of key facilities and critical components to NPCC Inc., including blackstart generating stations, underground transmission cables, and control center facilities, to ensure full compliance with reliability standards.

Non-Compliance Level 1: None. Level 2: A key facility and critical component list was provided but NPCC Inc. Inter-Area Restoration Coordination Working Group (CO-11) found that it did not fully support the energization of the basic minimu...

AI summary The document outlines non-compliance levels related to maintaining a current list of key facilities and critical components. Level 2 notes that the provided list did not fully support energizing the basic minimum power system, as identified by NPCC Inc.'s CO-11 working group. Level 3 highlights the Area's failure to maintain an updated list.

Bulk Power System Protection Minimum Maintenance Standard: Protection system owners shall im plement a protection sy stem maintenance and testing program that fulfills the requirements of the NPCC Maintenance Criteria for Bulk Power System...

AI summary Protection system owners must implement maintenance programs per NPCC's Document A-4, ensuring compliance with bulk power system protection standards.

Ten-Minute Operating Reserve Standard: Each CONTROL AREA shall operate its MW power resources to provide for a level of OPERATING RESERVE . Following loss of resources , a CONTROL AREA shall take appropriate steps to return its AREA CONTRO...

AI summary The Ten-Minute Operating Reserve standard requires each control area to maintain sufficient operating reserve to address resource losses and restore Area Control Error (ACE) to pre-disturbance levels, per NPCC Inc.'s Operating Reserve Criteria (Document A-6).

Full (100%) Compliance Control Area meets the Ten-Minute Reserve requirement as described in Sections 3.1 and 3.4 of A-6, except during emergency operations resulting from a capacity deficiency.

AI summary The Control Area complies with the Ten-Minute Reserve requirement as outlined in Sections 3.1 and 3.4 of A-6, except during emergency operations caused by capacity deficiencies.

Classification of Bulk Power System Elements Adopted by the Members of the Northeast Power Coordinating Council Inc., this 'HF 1, 2009 based on recommendation by the Reliability Coordinating Committee, in accordance with Section VIII of th...

AI summary The Northeast Power Coordinating Council Inc. adopted a classification of bulk power system elements based on a 2009 recommendation by the Reliability Coordinating Committee, following Section VIII of their amended bylaws dated May 18, 2006.

1.0 Introduction NPCC defines specific requirements applicable to design, operation, and protection of the bulk power system . The object of this Classification of Bulk Power System Elements (Document A-10) is to provide the methodology to...

AI summary NPCC outlines a methodology to classify bulk power system elements based on interconnected region criteria, emphasizing evaluation of elements through bus-based analysis and excluding voltage class as a determinant. The process ensures elements are added/removed from the NPCC Bulk Power System List based on specific testing and significant system changes.

2.0 Definitions NPCC Inc. Document A-10 Classification of Bulk Power System Elements Revised – December 01, 2009 Terms in italics in this document are defined in this section. Terms in bold are defined in the NPCC Glossary of Terms (Docume...

AI summary This section defines terms used in the document, with italicized terms defined here and bold terms referenced in the NPCC Glossary of Terms (Document A-7). It pertains to the classification of bulk power system elements as revised in 2009.

2.1 Bus Within this document the term bus refers to a junction with sensing or protection equipment within a substation or switching station at which the terminals of two or more elements are connected, regardless of whether circuit breake...

AI summary The document defines 'bus' in power systems as a junction with protection equipment in substations, detailing configurations where multiple physical buses may be tested as one or separate. Examples include breaker-and-a-half arrangements and references to NPCC Inc.'s 2009 document on bulk power system elements.

2.2 Uncleared Locally Within this document the phrase uncleared locally is used to denote failure of the protection including Special Protection Systems for the bus under test to initiate tripping of all associated interrupting devices reg...

AI summary The document defines 'uncleared locally' as the failure of protection systems, including Special Protection Systems (SPS), to trip interrupting devices at the bus under test. It outlines scenarios where protection at other buses may be assumed operational if they use independent DC sources, and discusses exceptions when backup protection at other buses can clear faults.

3.0 Classification of Bulk Power System Elements

AI summary This section outlines the classification of Bulk Power System (BPS) elements within Nova Scotia's regulatory framework, focusing on reliability, operational standards, and compliance with federal and regional energy reliability organizations.

3.1 Testing Conditions and Assumptions Studies conducted for the purpose of determining the elements of the bulk power system shall assume the following conditions: NPCC Inc. Document A-10 Classification of Bulk Power System Elements Revis...

AI summary The text outlines testing conditions for the bulk power system, including assumptions about power flow, load/generation patterns, protection systems, and stability tests, referencing NPCC Inc.'s document on bulk power system element classification.

3.2 Test Methodology Both transient stability and steady-state tests are used to determine the impact on system performance resulting from power system faults . Testing is based on application of a bus fault at a single voltage level that...

AI summary The methodology outlines using transient and steady-state tests to assess system performance impacts from faults, emphasizing identification of significant adverse effects beyond local areas. Specific tests address contingencies like loss of two adjacent transmission circuits, ensuring comprehensive evaluation of bulk power system reliability.

Step 1 - Transient Stability Test Simulate the transient stability condition of a three-phase fault with delayed clearing at the bus under test (step 1a). If the test results in a positive bulk power system determination, more detailed tes...

AI summary The transient stability test simulates a three-phase fault at a bus to assess bulk power system impacts. Step 1a uses a conservative 10-second fault simulation, while step 1b applies design-clearing times for more precise evaluations. The test may over-classify elements as part of the bulk power system due to its conservative nature.

3.4 Docum entation Documentation for Bulk Power System classification shall include: - 3.4.1 The rationale for the test conditions and assumptions used that are not listed above in 3.1. - 3.4.2 The criteria used in evaluating the result of...

AI summary Documentation for Bulk Power System classification requires rationale for test conditions, evaluation criteria (stability, voltage, thermal performance), and provision of detailed test results upon request.

4.0 Application and List Maintenance Each Area shall be responsible for the application of the Classification of Bulk Power System Elements as described in this document and shall submit proposed changes and supporting documentation to the...

AI summary Each Area is responsible for applying the classification of Bulk Power System elements, submitting changes to the Task Force on System Studies (TFSS). The TFSS maintains the NPCC Bulk Power System List and submits additions/removals to the Reliability Coordinating Committee (RCC) for approval.

4.1 Addition of Elements to the Bulk Power System List When application of this methodology identifies an element that was not part of the bulk power system should be classified as a bulk power system element , documentation of the analysi...

AI summary The process for classifying and adding new elements to the Bulk Power System (BPS) List involves TFSS analysis, RCC approval, and TFSP compliance planning. Once approved, all task forces and the Compliance Committee are notified, and a compliance plan must be submitted within three months.

4.2 Re moval of Elements from the Bulk Power System List When application of this methodology identifies a bulk power system element that no longer should be classified as a bulk power system element , documentation of the analysis shall b...

AI summary The process for removing elements from the NPCC Bulk Power System List involves submitting analysis to TFSS, with reclassification requiring RCC approval. Task forces including TFSS, TFCO, TFSP, and TFIST review the process, which is evaluated every four years using referenced documents.

Disturbance Monitoring Equipment Criteria Adopted by the Members of the Northeast Power Coordinating Council on August 23, 2007 based on recommendation by the Reliability Coordinating Committee, in accordance with paragraph IX, subheading...

AI summary The Northeast Power Coordinating Council (NPCC) adopted Disturbance Monitoring Equipment (DME) criteria on August 23, 2007, following a recommendation by the Reliability Coordinating Committee (RCC), in accordance with the NPCC's Amended and Restated Bylaws dated July 24, 2007.

1.0 Introduction A prompt and accurate sequence of events must be established following a disturbance to provide timely analysis and reporting of the disturbance . The importance of Disturbance Monitoring Equipment (DME) in monitoring perf...

AI summary The document emphasizes the need for accurate disturbance analysis and the role of Disturbance Monitoring Equipment (DME) in monitoring protection systems and validating simulations, aligning with NPCC criteria and NERC standards PRC-002 and PRC-018.

2.0 General The term Disturbance Monitoring Equipment (DME) is defined in the NERC Glossary, listed as Reference 1, and is repeated below for convenience: Disturbance Monitoring Equipment (DME) - Devices capable of monitoring and recording...

AI summary The document defines Disturbance Monitoring Equipment (DME) per NERC standards, outlining categories like SOE recorders, fault recorders, and DDRs. It mandates upgrades to existing DMEs under NERC PRC-018-1, requiring TOs and GOs to install DMEs for system analysis and compliance. RCs, TOs, and GOs must receive the document within 30 days of approval.

3.0 Sequence Of Event Recording - 3.1. Sequence of Event recording is the responsibility of transmission owners and generation owners. This capability can be provided as part of another device, such as a Supervisory Control And Data Acquis...

AI summary The section outlines the responsibility of transmission and generation owners for Sequence of Event (SOE) recording, specifying installation requirements at bulk power system substations and large generating units. It details the parameters to be monitored, including circuit breaker positions, protective relay tripping, and teleprotection functions.

4.0 Fault Recording - 4.1 Fault recording is the responsibility of transmission owners and generation owners. When adding or replacing a DFR at an existing BPS facility, the TO or GO should complete a notification in accordance with Docume...

AI summary The section outlines fault recording responsibilities for transmission and generation owners, specifying requirements for fault recorders, monitored elements, electrical quantities, and technical specifications like recording duration and sample rates.

5.0 Dynamic Disturbance Recording (DDR) Capability - 5.1 Where the DDR capability is deemed necessary by the Reliability Coordinator, the Reliability Coordinator shall provide guidance in setting triggers and shall monitor the performance...

AI summary The document outlines requirements for Dynamic Disturbance Recorder (DDR) deployment, including placement based on load, generation, and transmission factors, monitoring parameters (voltage, current, frequency), sampling rates (≥960 samples/sec), and triggers (e.g., frequency changes). DDRs must be distributed across major load centers, generation clusters, and transmission interfaces, with continuous recording mandated for devices installed post-2009.

6.0 Data - 6.1 Recorded disturbance data from DMEs shall be forwarded within 30 days of receipt of the request in each of the following cases: - Request from NERC Disturbance Investigation Team - Request from NPCC Disturbance Investigation...

AI summary The section outlines requirements for handling disturbance data from DMEs, including forwarding data to NERC and NPCC, archiving for three years, formatting standards, and responsibilities of TO and GO. It also specifies data retrieval periods and DME maintenance reporting.

7.0 Time Synchronization Internal clocks in DME devices shall be time synchronized to within 2 milliseconds or less of Coordinated Universal Time (UTC) scale. The time zone shall be clearly identified as either universal time zone or local...

AI summary DME devices must have internal clocks synchronized to within 2 milliseconds of Coordinated Universal Time (UTC), with a clearly identified time zone (universal or local). This ensures precise timing for grid monitoring and reliability.

8.0 Maintenance And Testing Each TO, and GO shall establish a maintenance and testing program for DME (guidance for maintenance and testing is provided in Document B-26) that includes: - Maintenance and testing intervals and their basis. -...

AI summary The document outlines requirements for TOs and GOs to establish maintenance and testing programs for DME, referencing NERC, NPCC, and IEEE standards. It emphasizes procedures, intervals, and compliance with reliability guidelines, prepared by the Task Force on System Protection.

BEFORE THE NOVA SCOTIA UTILITY AND REVIEW BOARD OF THE PROVINCE OF NOVA SCOTIA NORTH AMERICAN ELECTRIC ) RELIABILITY CORPORATION ) APPLICATION FOR APPROVAL OF RELIABILITY STANDARDS OF THE NORTH AMERICAN ELECTRIC RELIABILITY CORPORATION

AI summary The document presents an application for the approval of reliability standards by the North American Electric Reliability Corporation (NERC) before the Nova Scotia Utility and Review Board.

harged with developing mandatory and enforceable Reliability Standards, which are subject to FERC review and approval. & lt;sup>3 16 U.S.C. § 824o(f) (2006). & lt;sup>4 See Memorandum of Understanding between Nova Scotia Utility and Review...

AI summary The document discusses the implementation of NERC Reliability Standards and NPCC Regional Reliability Criteria in Nova Scotia, referencing memoranda of understanding between the Nova Scotia Utility and Review Board and NERC, as well as between Nova Scotia Power Incorporated and the Northeast Power Coordinating Council and NERC.

III. REQUEST FOR APPROVAL OF RELIABILITY STANDARDS This section provides a summary of NERC's existing Reliability Standards.

AI summary This section summarizes NERC's existing Reliability Standards, providing an overview of the current framework for ensuring electricity system reliability under regulatory review in Nova Scotia.

A. NERC Filing of All Proposed Reliability Standards NERC is filing all FERC approved Reliability Standards for approval by the NSUARB. The Reliability Standards, in the instant filing, are provided in two parts. The first part consists of...

AI summary NERC is filing FERC-approved reliability standards with the NSUARB, distinguishing between current and future effective standards. It requests approval of associated VRFs and VSLs, which determine penalties for noncompliance. NERC excludes the full developmental record due to its volume but commits to making it available upon request. It emphasizes collaboration with the NSUARB to address Canadian and provincial issues.

B. Overview of Reliability Standards NERC Reliability Standards define the requirements for reliably planning and operating the North American bulk power system. These standards are developed by industry stakeholders using a balanced, open...

AI summary NERC Reliability Standards outline requirements for the North American bulk power system's planning and operation, developed through an inclusive process by industry stakeholders. The standards cover real-time balancing, equipment limits, contingency management, vegetation control, critical infrastructure protection, and emergency planning, ensuring system reliability and safety.

C. Detailed Description of Proposed Reliability Standards The Reliability Standards presented in Exhibits C and E are grouped by topical area, as summarized below. Resource and Demand Balancing (BAL) ⎯ balancing resources and demand to mai...

AI summary The document outlines proposed reliability standards grouped into 13 topical areas, including resource balancing, cybersecurity, emergency operations, and transmission planning. It references NERC's glossary and Exhibit B, which details each standard's purpose, approval percentages, and changes. The standards aim to ensure grid reliability through coordinated operations, infrastructure protection, and compliance with NERC and FERC guidelines.

IV. BACKGROUND ON THE PROCESS FOR DEVELOPMENT OF RELIABILITY STANDARDS By way of background, NERC develops Reliability Standards in accordance with Section 300 (Reliability Standards Development) of its Rules of Procedure and the NERC Reli...

AI summary The text outlines NERC's reliability standards development process, emphasizing stakeholder participation, transparency, consensus-building, and ANSI certification. It highlights attributes ensuring fairness and due process, with standards approved by NERC and FERC.

A. Benchmarks of an Excellent Reliability Standard To translate the attributes stated above into objective measures, NERC has adopted ten benchmarks for use in the development of Reliability Standards. NERC believes these benchmarks, descr...

AI summary NERC outlines ten benchmarks for reliability standards, emphasizing applicability to specific entities, clear purpose, and performance requirements. It urges the NSUARB to consider these benchmarks when evaluating proposed standards, focusing on system reliability and compliance.

A. NERC's Experience as a Standards Developer NERC and its predecessor, the North American Electric Reliability Council, have been promoting and evaluating bulk power system reliability and developing Reliability Standards for more than 40...

AI summary NERC, established after the 1965 blackout, has developed reliability standards for North America's bulk power system for over 40 years. It was formed as a voluntary organization to ensure system reliability through operating policies and planning standards.

VI. CONCLUSION By this filing, NERC requests that the NSUARB approve the Reliability Standards and NERC Glossary of Terms used in Reliability Standards, as set out in Exhibits C and E. NERC also requests that the NSUARB approve the VRFs an...

AI summary NERC requests NSUARB approval of Reliability Standards, associated Glossary of Terms, VRFs, and VSLs (Exhibits C, E, F, G). NERC also seeks feedback from the Province of Nova Scotia on information adequacy and guidance for future filings.

List of Current Reliability Standards Current Effective Standard Effective Date of Standard1 Current Effective Standard Effective Date of Standard Current Effective Standard Effective Date of Standard BAL-001-0.1a June 18, 2007 FAC-013-1 J...

AI summary The document lists current reliability standards with their effective dates, including standards from the North American Electric Reliability Corporation (NERC) and other organizations. These standards cover various aspects of electric reliability, such as critical infrastructure protection (CIP), performance, and compliance.

Applicability: • Balancing Authorities On October 29, 2008, BAL-001-0.1a was approved by the NERC Board of Trustees. On May 13, 2009, BAL-001-0.1a was approved by the Federal Energy Regulatory Commission. Version BAL-001-0.1a resulted from...

AI summary The document outlines the approval history of the BAL-001-0.1a standard by NERC and FERC, and explains the purpose of the Disturbance Control Standard (BAL-002-0) to ensure Balancing Authorities maintain interconnection frequency during supply disruptions. It clarifies that the standard applies to loss of supply, not load.

Applicability: • Balancing Authorities On October 29, 2008, BAL-003-0.1b was approved by the NERC Board of Trustees. On May 13, 2009, BAL-003-0.1b was approved by the Federal Energy Regulatory Commission. Version BAL-003-0.1b resulted from...

AI summary The document outlines the approval history of BAL-003-0.1b by NERC and FERC, noting its derivation from BAL-003-0 via errata and interpretation changes. It also introduces BAL-004-0, which mandates Time Error Corrections to maintain Interconnection reliability.

Standard IRO-015-1 — Notifications and Information Exchange Between Reliability Coordinators: To ensure that each Reliability Coordinator's operations are coordinated such that they will not have an Adverse Reliability Impact on other Reli...

AI summary Standard IRO-015-1 mandates coordination between Reliability Coordinators to prevent adverse reliability impacts and maintain benefits from interconnected operations, ensuring system-wide reliability through effective information exchange.

Standard MOD-019-0.1 — Reporting of Interruptible Demands and Direct Control Load Management Data: To ensure that assessments and validation of past events and databases can be performed, reporting of actual demand data is needed. Forecast...

AI summary The standard emphasizes the necessity of reporting actual and forecast demand data to ensure system reliability and proper real-time operations. It highlights the importance of load information from controllable Demand-Side Management (DSM) programs for assessing past events, validating databases, and identifying system reinforcement needs.

Standard PRC-018-1 — Disturbance Monitoring Equipment Installation and Data Reporting: Ensure that Disturbance Monitoring Equipment (DME) is installed and that Disturbance data is reported in accordance with regional requirements to facili...

AI summary The requirement mandates the installation of Disturbance Monitoring Equipment (DME) and the reporting of disturbance data in accordance with regional standards to enable event analysis.

Standard VAR-002-1.1a — Generator Operation for Maintaining Network Voltage Schedules: To ensure generators provide reactive and voltage control necessary to ensure voltage levels, reactive flows, and reactive resources are maintained with...

AI summary This standard requires generators to provide reactive and voltage control to maintain voltage levels, reactive flows, and resources within applicable Facility Ratings, ensuring equipment protection and reliable Interconnection operation.

Current Reliability Standards and NERC Glossary of Terms for Approval

AI summary The document outlines the current reliability standards and the NERC Glossary of Terms for approval, detailing key terms and standards relevant to electric reliability in Nova Scotia. It emphasizes compliance with protocols and terminology governed by NERC and related regulatory bodies.

Standard BAL-001-0.1a — Real Power Balancing Control Performance

AI summary This document outlines the regulatory standard BAL-001-0.1a, focusing on real power balancing control performance. It involves entities like NERC, NSUARB, and NSPI, addressing system reliability, performance standards, and compliance with regulatory frameworks.

A. Introduction 1. Title: Real Power Balancing Control Performance 2. Number : BAL-001-0.1a 3. Purpose : To maintain Interconnection steady-state frequency within defined limits by balancing real power demand and supply in real-time. 4. Ap...

AI summary This document outlines BAL-001-0.1a, a standard aimed at maintaining interconnection steady-state frequency by balancing real power demand and supply in real-time, applicable to Balancing Authorities, effective since May 13, 2009.

B. Requirements R1. Each Balancing Authority shall operate such that, on a rolling 12-month basis, the average of the clock-minute averages of the Balancing Authority's Area Control Error (ACE) divided by 10B (B is the clock-minute average...

AI summary The section outlines requirements for Balancing Authorities to maintain control performance standards (CPS1 and CPS2) related to Area Control Error (ACE) and Frequency Bias. It includes mathematical equations for compliance and references NERC's role in setting frequency bounds.

C. Measures M1. Each Balancing Authority shall achieve, as a minimum, Requirement 1 (CPS1) compliance of 100%. CPS1 is calculated by converting a compliance ratio to a compliance percentage as follows: $$CPS1 = (2 - CF) 100\%$$ The frequen...

AI summary This section outlines the requirement for Balancing Authorities to achieve 100% CPS1 compliance, detailing the calculation of the compliance factor (CF) using metrics like ACE, Frequency Error, and Frequency Bias Settings (B) over 12 months. Formulas for clock-minute and hourly averages are provided to assess adherence to control performance standards.

1.3. Data Retention The data that supports the calculation of CPS1 and CPS2 (Appendix 1-BAL-001-0) are to be retained in electronic form for at least a one-year period. If the CPS1 and CPS2 data for a Balancing Authority Area are undergoin...

AI summary Data supporting CPS1 and CPS2 calculations must be retained electronically for at least one year, with extended retention during reviews. Balancing Authorities must maintain rolling 12-month records of ACE, Frequency Error, and Frequency Bias values.

Standard BAL-001-0.1a — Real Power Balancing Control Performance - 2.3. Level 3: The Balancing Authority Area's value of CPS1 is less than 90% but greater than or equal to 85%. - 2.4. Level 4: The Balancing Authority Area's value of CPS1 i...

AI summary The document defines performance levels for the Real Power Balancing Control Performance Standard (BAL-001-0.1a). Level 3 applies when a Balancing Authority Area's CPS1 (Control Performance Standard 1) is between 85% and 90%, while Level 4 applies when CPS1 falls below 85%.

3. Levels of Non-Compliance – CPS2 - 3.1. Level 1: The Balancing Authority Area's value of CPS2 is less than 90% but greater than or equal to 85%. - 3.2. Level 2: The Balancing Authority Area's value of CPS2 is less than 85% but greater th...

AI summary The document outlines four levels of non-compliance for CPS2 (Control Performance Standard 2), defined by the Balancing Authority Area's CPS2 value thresholds: Level 1 (85–90%), Level 2 (80–85%), Level 3 (75–80%), and Level 4 (<75%). These thresholds determine the severity of non-compliance with control performance requirements.

E. Regional Differences 1. The ERCOT Control Performance Standard 2 Waiver approved November 21, 2002.

AI summary The document references the ERCOT Control Performance Standard 2 (CPS2) waiver approved on November 21, 2002, highlighting regional regulatory considerations related to reliability standards.

Appendix 1-BAL-001-0 CPS1 and CPS2 Data CPS1 DATA Description Retention Requirements 1 A constant derived from the targeted frequency bound. This number is the same for each Balancing Authority Area in the Interconnection. Retain the valu...

AI summary This document outlines the data requirements for CPS1 and CPS2, which are control performance standards used in the bulk electric system. It details the parameters such as ACE, frequency bias, and retention requirements for data collection and analysis.

Interpretation of Requirement 1 Request: Does the WECC Automatic Time Error Control Procedure (WATEC) violate Requirement 1 of BAL-001-0?

AI summary The document raises a question about whether the WECC Automatic Time Error Control Procedure (WATEC) violates Requirement 1 of BAL-001-0, a standard related to system reliability and time synchronization in the electricity sector.

BAL-001-0 R1. Each Balancing Authority shall operate such that, on a rolling 12-month basis, the average of the clock-minute averages of the Balancing Authority's Area Control Error (ACE) divided by 10B (B is the clock-minute average of th...

AI summary The BAL-001-0 standard requires Balancing Authorities to maintain Area Control Error (ACE) within specific limits. The use of WATEC-adjusted ACE for control does not violate the standard if raw ACE is used for CPS reporting. Adopted by NERC in 2008.

Introduction 1. Title: Disturbance Control Performance 2. Number: BAL-002-0

AI summary This regulatory proceeding introduces a standard titled 'Disturbance Control Performance' with the identifier BAL-002-0, focusing on balancing authority performance metrics within the electricity sector.

3. Purpose: The purpose of the Disturbance Control Standard (DCS) is to ensure the Balancing Authority is able to utilize its Contingency Reserve to balance resources and demand and return Interconnection frequency within defined limits fo...

AI summary The Disturbance Control Standard (DCS) aims to ensure the Balancing Authority can use Contingency Reserve to balance resources and restore Interconnection frequency within limits after a Reportable Disturbance. It applies only to supply loss, excluding load loss, due to generator failures being more common than load losses.

4. Applicability: - 4.1. Balancing Authorities - 4.2. Reserve Sharing Groups (Balancing Authorities may meet the requirements of Standard 002 through participation in a Reserve Sharing Group.) - 4.3. Regional Reliability Organizations - 5....

AI summary Section 4 outlines applicability of standards to Balancing Authorities, Reserve Sharing Groups, and Regional Reliability Organizations. Section 5 sets the effective date as April 1, 2005, establishing compliance timelines for these entities.

B. Requirements - R1. Each Balancing Authority shall have access to and/or operate Contingency Reserve to respond to Disturbances. Contingency Reserve may be supplied from generation, controllable load resources, or coordinated adjustments...

AI summary The requirements outline Contingency Reserve obligations for Balancing Authorities and Reserve Sharing Groups, including minimum reserve levels, resource allocation, and compliance with Disturbance Control Standards (DCS). Entities must ensure sufficient reserves to address severe contingencies and adhere to specified policies.

1.4. Additional Compliance Information Reportable Disturbances – Reportable Disturbances are contingencies that are greater than or equal to 80% of the most severe single Contingency. A Regional Reliability Organization, sub-Regional Relia...

AI summary The section defines reportable disturbances as contingencies exceeding 80% of the most severe single contingency, outlines handling of simultaneous contingencies, and specifies evaluation procedures for multiple contingencies during recovery periods. Compliance is managed by Balancing Authorities and Reserve Sharing Groups, with potential waiver requests for inadequacies in contingency reserves.

2. Levels of Non-Compliance Each Balancing Authority or Reserve Sharing Group not meeting the DCS during a given calendar quarter shall increase its Contingency Reserve obligation for the calendar quarter (offset by one month) following th...

AI summary Non-compliant Balancing Authorities and Reserve Sharing Groups must increase Contingency Reserve obligations proportionally to their DCS non-compliance, with adjustments applied for three months. Four levels of non-compliance are defined based on average percent recovery (95–100%, 90–95%, 85–90%, and below 85%). Written documentation verifying compliance adjustments is required.

Standard BAL-002-0 — Disturbance Control Performance

AI summary This document outlines the regulatory standard BAL-002-0, which governs disturbance control performance within the electricity grid, ensuring reliability and compliance with NERC and FERC guidelines.

A. Introduction 1. Title: Frequency Response and Bias 2. Number: BAL-003-0.1b 3. Purpose: This standard provides a consistent method for calculating the Frequency Bias component of ACE. 4. Applicability: 4.1. Balancing Authorities. 5. Effe...

AI summary The BAL-003-0.1b standard establishes a method for calculating the Frequency Bias component of ACE, applicable to Balancing Authorities, effective May 13, 2009.

B. Requirements - R1. Each Balancing Authority shall review its Frequency Bias Settings by January 1 of each year and recalculate its setting to reflect any change in the Frequency Response of the Balancing Authority Area. - R1.1. The Bala...

AI summary The requirements outline annual reviews and recalculations of Frequency Bias Settings by Balancing Authorities, methods for determining these settings, reporting obligations to NERC, and specific operational guidelines for AGC, jointly owned units, and Overlap Regulation Service.

C. Measures M1. Each Balancing Authority shall perform Frequency Response surveys when called for by the Operating Committee to determine the Balancing Authority's response to Interconnection Frequency Deviations.

AI summary Measure M1 mandates that each Balancing Authority conduct Frequency Response surveys upon request by the Operating Committee to assess their response to Interconnection Frequency Deviations, ensuring compliance with reliability standards.

Interpretation of Requirement 3 Request: Does the WECC Automatic Time Error Control Procedure (WATEC) violate Requirement 3 of BAL-003-0?

AI summary The document asks whether the WECC Automatic Time Error Control Procedure (WATEC) violates Requirement 3 of BAL-003-0, focusing on regulatory compliance and system reliability standards.

Interpretation: Requirement 3 of BAL-003-0 — Frequency Response and Bias deals with Balancing Authorities using Tie-Line Frequency Bias as the normal mode of automatic generation control.

AI summary Requirement 3 of BAL-003-0 mandates that Balancing Authorities use Tie-Line Frequency Bias as the standard mode for automatic generation control, ensuring proper frequency response and bias management within the Bulk Electric System.

BAL-003-0 R3. Each Balancing Authority shall operate its Automatic Generation Control (AGC) on Tie Line Frequency Bias, unless such operation is adverse to system or Interconnection reliability. - Tie-Line Frequency Bias is one of the thre...

AI summary The document outlines BAL-003-0, requiring Balancing Authorities to use Tie-Line Frequency Bias for Automatic Generation Control unless it affects system reliability. It explains the ACE equation and notes compliance when CPS1 is measured.

Interpretation: The consensus of the Resources Subcommittee is that BAL-003-0 — Frequency Response and Bias — Requirement R2 does not conflict with BAL-003-0 Requirement R5. BAL-003-0 — Frequency Response and Bias Requirement 2 requires a...

AI summary The Resources Subcommittee concludes that BAL-003-0 Requirement R2 (frequency bias analysis) does not conflict with R5. R2 mandates Balancing Authority analysis of frequency response to set bias, allowing fixed or variable bias settings based on load and generators.

BAL-003-0 - R2. Each Balancing Authority shall establish and maintain a Frequency Bias Setting that is as close as practical to, or greater than, the Balancing Authority's Frequency Response. Frequency Bias may be calculated several ways:...

AI summary BAL-003-0 mandates Balancing Authorities to set frequency bias near or above their frequency response, using fixed or variable methods. A 1% bias floor ensures consistent control performance across multi-Balancing Authority interconnections, though ERCOT, as a single Balancing Authority, achieves equivalent control performance through its unique approach.

A. Introduction 1. Title: Time Error Correction 2. Number: BAL-004-0 3. Purpose: The purpose of this standard is to ensure that Time Error Corrections are conducted in a manner that does not adversely affect the reliability of the Intercon...

AI summary This standard (BAL-004-0) establishes requirements for conducting Time Error Corrections without compromising Interconnection reliability. It focuses on ensuring synchronization accuracy across the Bulk Electric System to maintain operational stability.

B. Requirements - R1. Only a Reliability Coordinator shall be eligible to act as Interconnection Time Monitor. A single Reliability Coordinator in each Interconnection shall be designated by the NERC Operating Committee to serve as Interco...

AI summary The document outlines requirements for the Interconnection Time Monitor, specifying that only a Reliability Coordinator can act in this role. It details procedures for monitoring Time Error, corrective actions by Balancing Authorities, and termination authority for Reliability Coordinators, referencing the NAESB Time Error Correction Procedure.

Standard BAL-004-0 — Time Error Correction

AI summary This document outlines Standard BAL-004-0, a regulatory requirement under NERC for correcting time errors in the Bulk Electric System to ensure reliability and synchronization across the grid.

3. Purpose: This standard establishes requirements for Balancing Authority Automatic Generation Control (AGC) necessary to calculate Area Control Error (ACE) and to routinely deploy the Regulating Reserve. The standard also ensures that al...

AI summary The standard establishes requirements for Balancing Authority Automatic Generation Control (AGC) to calculate Area Control Error (ACE) and deploy Regulating Reserve, ensuring all synchronized facilities are within the Balancing Area's metered boundary to achieve resource and demand balance.

B. Requirements - R1. All generation, transmission, and load operating within an Interconnection must be included within the metered boundaries of a Balancing Authority Area. - R1.1. Each Generator Operator with generation facilities opera...

AI summary The requirements mandate that all generation, transmission, and load within an Interconnection must be within a Balancing Authority Area. Balancing Authorities must maintain Regulating Reserve, ensure proper equipment for regulation service, notify Host Balancing Authorities of service unavailability, and have backup plans. ACE calculations are outlined, with asynchronous Balancing Authorities allowed alternative methods.

1. Compliance Monitoring Process

AI summary The section outlines the compliance monitoring process, likely involving regulatory oversight and adherence to standards such as CIP and FAC. It may discuss roles of entities like NSUARB and NSPI in ensuring compliance with reliability and operational protocols.

D. Compliance

AI summary The document section titled 'Compliance' outlines regulatory requirements and standards relevant to Nova Scotia's utility sector, referencing various reliability, security, and operational protocols governed by entities like NERC, FERC, and NSUARB.

1. Compliance Monitoring Process - 1.1. Each Balancing Authority shall submit a monthly summary of Inadvertent Interchange. These summaries shall not include any after-the-fact changes that were not agreed to by the Source Balancing Author...

AI summary The Compliance Monitoring Process outlines requirements for Balancing Authorities to submit monthly Inadvertent Interchange summaries, including specific data points and deadlines. Regional Reliability Organizations must prepare and report monthly summaries to NERC, while Balancing Authorities must conduct AIE Surveys upon NERC's request to assess interchange errors.

E. Regional Differences 1. MISO RTO [Inadvertent Interchange Accounting](http://www.nerc.com/docs/standards/sar/Waver_Inadvertant_Interchange_Accounting.pdf) Waiver approved by the Operating Committee on March 25, 2004. This regional diffe...

AI summary A waiver for MISO RTO's Inadvertent Interchange Accounting was approved by the Operating Committee on March 25, 2004, and later extended to include SPP effective May 1, 2006, reflecting regional differences in regulatory standards.

4. Applicability - 4.1. Reliability Coordinators. - 4.2. Balancing Authorities. - 4.3. Transmission Operators. - 4.4. Generator Operators. - 4.5. Load Serving Entities. - 5. Effective Date: January 1, 2007

AI summary Section 4 outlines the applicability of regulatory requirements to entities including Reliability Coordinators, Balancing Authorities, Transmission Operators, Generator Operators, and Load Serving Entities, with an effective date of January 1, 2007.

C. Measures - M1. Each Reliability Coordinator, Balancing Authority, Transmission Operator, Generator Operator, and Load Serving Entity shall have and provide upon request a procedure (either electronic or hard copy) as defined in Requirem...

AI summary The document outlines three measures requiring Reliability Coordinators, Balancing Authorities, and other entities to establish procedures for compliance with reliability standards, including communication protocols with FBI/RCMP for sabotage events. These measures aim to ensure operational reliability and security in the electricity sector.

2. Levels of Non-Compliance: - 2.1. Level 1: There shall be a separate Level 1 non-compliance, for every one of the following requirements that is in violation: - 2.1.1 Does not have procedures for the recognition of and for making its ope...

AI summary The document outlines four levels of non-compliance, with Level 1 and Level 3 specifying violations related to procedures for recognizing sabotage events, communicating such events, establishing contacts, and providing response guidelines. Levels 2 and 4 are not applicable.

4. Applicability: - 4.1. Within the text of Standard CIP-003-2, "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 Tr...

AI summary Section 4 defines 'Responsible Entity' under CIP-003-2, including entities like Reliability Coordinators and Balancing Authorities, and lists exemptions for nuclear-regulated facilities and certain cyber assets. The effective date depends on regulatory approvals or BOT adoption.

1. Compliance Monitoring Process

AI summary The section outlines the compliance monitoring process, likely involving regulatory oversight and adherence to standards such as CIP and FAC. It may discuss roles of entities like NSUARB and NSPI in ensuring compliance with reliability and operational protocols.

1. Compliance Monitoring Process

AI summary The section outlines the compliance monitoring process, likely involving regulatory oversight and adherence to standards such as CIP and FAC. It may discuss roles of entities like NSUARB and NSPI in ensuring compliance with reliability and operational protocols.

1. Compliance Monitoring Process

AI summary The section outlines the compliance monitoring process, likely involving regulatory oversight and adherence to standards such as CIP and FAC. It may discuss roles of entities like NSUARB and NSPI in ensuring compliance with reliability and operational protocols.

1.3. Data Retention For Measure 1 each Reliability Coordinator, Transmission Operator, Balancing Authority shall keep evidence of compliance for the previous two calendar years plus the current year. For Measure 2 each Reliability Coordina...

AI summary The section outlines data retention requirements for Reliability Coordinators, Transmission Operators, Balancing Authorities, and NERCnet User Organizations. Measures mandate retaining compliance evidence for two calendar years plus the current year, 90 days of historical data, and specific records during non-compliance investigations. The Compliance Monitor retains audit reports and compliance records.

Implementation and Responsibilities This section identifies the various roles and responsibilities related to the protection of NERCnet resources.

AI summary The section outlines roles and responsibilities for protecting NERCnet resources within the regulatory proceeding, focusing on implementation and accountability for reliability and security measures.

Elements for Consideration in Development of Emergency Plans - 1. Fuel supply and inventory An adequate fuel supply and inventory plan that recognizes reasonable delays or problems in the delivery or production of fuel. - 2. Fuel switching...

AI summary The document outlines 15 elements for developing emergency plans, focusing on fuel management, load reduction, public appeals, and coordination with government and entities. It references NERC's EOP-002-2.1 standard for capacity and energy emergencies.

C. Measures - M1. Each Reliability Coordinator and Balancing Authority shall have and provide upon request evidence that could include but is not limited to, job descriptions, signed agreements, authority letter signed by an appropriate of...

AI summary The measures outline evidence requirements for Reliability Coordinators, Balancing Authorities, and Transmission Service Providers to demonstrate compliance with emergency plans, operator logs, and NERC/EEA standards during capacity and energy emergencies.

1.1. Compliance Monitoring Responsibility Regional Reliability Organizations shall be responsible for compliance monitoring.

AI summary The document assigns compliance monitoring responsibility to Regional Reliability Organizations (RROs) within the context of regulatory proceedings, emphasizing their role in ensuring adherence to reliability standards.

2. Levels of Non-Compliance for a Reliability Coordinator: - 2.1. Level 1: Did not submit the report to NERC as required in R9.2. - 2.2. Level 2: Not applicable. - 2.3. Level 3: Not applicable. - 2.4. Level 4: There shall be a separate Lev...

AI summary The document outlines four levels of non-compliance for a Reliability Coordinator, with Level 1 involving failure to report to NERC (R9.2) and Level 4 covering violations of emergency plans, alerts, and decision-making authority (R1-R8, R9.3-9.4). Levels 2 and 3 are not applicable.

3. Levels of Non-Compliance for a Balancing Authority: - 3.1. Level 1: Not applicable. - 3.2. Level 2: Did not provide evidence that it has the responsibility and clear decision-making authority in accordance with R1. - 3.3. Level 3: Not a...

AI summary The document outlines four levels of non-compliance for a Balancing Authority, detailing specific violations related to responsibility, communication during emergencies, and implementation of emergency plans. Adopted by the Board of Trustees in 2008 and effective May 2009, Level 4 violations include failure to communicate system conditions and improper execution of emergency protocols.

Attachment 1-EOP-002-2.1 Energy Emergency Alerts

AI summary This attachment outlines the Energy Emergency Alerts framework under EOP-002-2.1, part of Nova Scotia's regulatory process for ensuring grid reliability during emergencies. It references standards for emergency operations planning and cyber security protocols relevant to critical infrastructure protection.

Introduction This Attachment provides the procedures by which a Load Serving Entity can obtain capacity and energy when it has exhausted all other options and can no longer provide its customers' expected energy requirements. NERC defines...

AI summary This document outlines procedures for Load Serving Entities (LSEs) to obtain capacity and energy during energy emergencies, as defined by NERC. The Energy Emergency Alert Procedure is triggered by a Reliability Coordinator, with alert levels detailed in Section B. Transmission Providers' obligations under FERC-approved tariffs remain unchanged.

A. General Requirements - 1. Initiation by Reliability Coordinator. An Energy Emergency Alert may be initiated only by a Reliability Coordinator at 1) the Reliability Coordinator's own request, or 2) upon the request of a Balancing Authori...

AI summary The document outlines procedures for initiating and notifying Energy Emergency Alerts by Reliability Coordinators, specifying conditions such as Load Serving Entity resource shortages or scheduling issues due to Available Transfer Capability (ATC) limitations. Notifications must be sent to Balancing Authorities, Transmission Providers, and other Reliability Coordinators via the Reliability Coordinator Information System (RCIS).

Introduction To ensure that all Reliability Coordinators clearly understand potential and actual energy emergencies in the Interconnection, NERC has established three levels of Energy Emergency Adopted by Board of Trustees: October 29, 200...

AI summary NERC has established three levels of Energy Emergency Alerts to help Reliability Coordinators communicate potential and actual energy emergencies. These alerts are emergency procedures, not daily practices, and do not replace compliance with reliability standards or power supply contracts.

1. Alert 1 — All available resources in use.

AI summary The alert indicates that all available resources are currently in use, signaling potential capacity constraints or system stress. However, the text provides no further details on the context, implications, or specific resources referenced.

Circumstances: - Balancing Authority, Reserve Sharing Group, or Load Serving Entity foresees or is experiencing conditions where all available resources are committed to meet firm load, firm transactions, and reserve commitments, and is co...

AI summary The text outlines conditions where a Balancing Authority, Reserve Sharing Group, or Load Serving Entity faces resource constraints, committing all available resources to meet firm load and reserve commitments, raising concerns about sustaining operating reserves. Non-firm wholesale energy sales have been curtailed under these circumstances.

C. Energy Emergency Alert 3 Report A Deficient Balancing Authority or Load Serving Entity declaring an Energy Emergency Alert 3 must complete the following report. Upon completion of this report, it is to be sent to the Reliability Coordin...

AI summary The document outlines procedural requirements for entities declaring an Energy Emergency Alert 3, mandating submission of a report to the Reliability Coordinator within two business days to ensure compliance with reliability standards during critical system events.

2. Levels of Non-Compliance: - 2.1. Level 1: Not applicable. - 2.2. Level 2: Not applicable. - 2.3. Level 3: Not Applicable. - 2.4. Level 4: There shall be a separate Level 4 non-compliance, for every one of the following requirements that...

AI summary The document outlines four levels of non-compliance, with Levels 1-3 being non-applicable. Level 4 specifically addresses violations related to the absence of automatic (R2) and manual (R8) load shedding plans, which are critical for system reliability and regulatory compliance.

1.1. Compliance Monitoring Responsibility NERC shall be responsible for compliance monitoring of the Regional Reliability Organizations. Regional Reliability Organizations shall be responsible for compliance monitoring of Reliability Coord...

AI summary NERC is tasked with monitoring compliance of Regional Reliability Organizations (RROs), while RROs oversee Reliability Coordinators, Balancing Authorities, Transmission Operators, Generator Operators, and Load-serving Entities. This establishes a hierarchical compliance monitoring framework within the electric reliability system.

1.4. Additional Compliance Information See Attachments: - EOP-004 Disturbance Reporting Form - Table 1 EOP-004 - 2. Levels of Non-Compliance for a Regional Reliability Organization - 2.1. Level 1: Not applicable. - 2.2. Level 2: Not applic...

AI summary The document outlines non-compliance levels for entities under EOP-004, specifying that Level 4 non-compliance applies to Regional Reliability Organizations lacking procedures for preliminary and final disturbance reports. Other entities face Level 1 non-compliance for specific reporting failures.

Attachment 1-EOP-004 NERC Disturbance Report Form

AI summary This document is an attachment to a regulatory proceeding in Nova Scotia, specifically the NERC Disturbance Report Form (EOP-004), which relates to cybersecurity and reliability standards for the electric grid.

Introduction These disturbance reporting requirements apply to all Reliability Coordinators, Balancing Authorities, Transmission Operators, Generator Operators, and Load Serving Entities, and provide a common basis for all NERC disturbance...

AI summary The document outlines NERC's disturbance reporting requirements for entities like Reliability Coordinators and Balancing Authorities. Reports must be submitted via specific forms to NERC and the U.S. Department of Energy, covering events such as bulk power transmission failures, system separations, and load shedding exceeding thresholds.

to file form OE-417 in cases where these entities will not be involved. EIA requests that it be notified of those that plan to file jointly and of those electric entities that want to file separately. Special reporting provisions exist for...

AI summary The text outlines requirements for submitting Form EIA-417 to the DOE Operations Center under specific emergency scenarios, including load loss, voltage reductions, and cyber/physical attacks. It also addresses joint filings by entities and voluntary submissions by foreign utilities handling U.S. Balancing Authority responsibilities.

Adopted by Board of Trustees: November 1, 2006 Page 11 of 13 Table 1-EOP-004-0 Summary of NERC and DOE Reporting Requirements for Major Electric System Emergencies Incident No. Incident Threshold Report Required Time 1 Uncontrolled loss of...

AI summary This document outlines the NERC and DOE reporting requirements for major electric system emergencies, detailing specific incidents, thresholds, required reports, and timeframes for submission. It includes nine types of incidents with varying thresholds and reporting schedules.

1.3. Data Retention The Transmission Operator must have its plan to reestablish its electric system available for review by the Regional Reliability Organization at all times. The Compliance Monitor shall retain any audit data for three ye...

AI summary The Transmission Operator must maintain a plan to reestablish its electric system for perpetual review by the Regional Reliability Organization. The Compliance Monitor is required to retain audit data for three years, ensuring compliance with regulatory standards.

1.4. Additional Compliance Information Self-Certification: Each Transmission Operator shall annually self-certify to the Regional Reliability Organization that the following criteria have been met: - 1.4.1 The necessary operating instructi...

AI summary Transmission Operators must annually self-certify compliance with Regional Reliability Organization (RRO) criteria, including restoration plan procedures, training documentation, blackstart unit adequacy, and cranking path availability. Changes to restoration plans must be reported to the RRO.

Elements for Consideration in Development of Restoration Plans The Restoration Plan must consider the following requirements, as applicable: - 1. Plan and procedures outlining the relationships and responsibilities of the personnel necessa...

AI summary The document outlines key elements for developing system restoration plans, emphasizing black-start capabilities, coordination with reliability coordinators, testing procedures, personnel training, and communication protocols to ensure reliable system restoration and interconnection priority.

D. Compliance - 1. Compliance Monitoring Process - 1.1. Compliance Monitoring Responsibility Regional Reliability Organization.

AI summary The compliance monitoring process is outlined, with responsibility assigned to the Regional Reliability Organization. This section establishes the entity tasked with overseeing compliance within the regulatory framework.

1.1. Compliance Monitoring Responsibility Compliance Monitor: Regional Reliability Organization.

AI summary The Regional Reliability Organization (RRO) is designated as the Compliance Monitor under the regulatory proceeding, tasked with overseeing adherence to reliability and operational standards in the electricity sector.

2. Levels of Non-Compliance - 2.1. Level 1: Startup and operation testing of each blackstart generating unit was performed, but the documentation was incomplete. - 2.2. Level 2: Not applicable. Adopted by NERC Board of Trustees: February 8...

AI summary The document outlines two levels of non-compliance. Level 1 notes incomplete documentation for blackstart generating unit testing, while Level 2 is not applicable. The standards were adopted by the NERC Board of Trustees in 2005.

Standard EOP-009-0— Documentation of Blackstart Generating Unit Test Results - 2.3. Level 3: Startup and operation testing of a blackstart generating unit was only partially performed. - 2.4. Level 4: Startup and operation testing of each...

AI summary The document highlights deficiencies in blackstart generating unit testing under EOP-009-0, noting partial completion of Level 3 tests and absence of Level 4 tests.

1. Compliance Monitoring Process

AI summary The section outlines the compliance monitoring process, likely involving regulatory oversight and adherence to standards such as CIP and FAC. It may discuss roles of entities like NSUARB and NSPI in ensuring compliance with reliability and operational protocols.

1.3. Data Retention Evidence of the assessment of the reliability impacts of new facilities and their connections on the interconnected transmission systems: Three years.

AI summary The document specifies a three-year data retention period for evidence assessing the reliability impacts of new facilities and their connections on interconnected transmission systems.

2. Levels of Non-Compliance - 2.1. Level 1: Assessments of the impacts of new facilities were provided, but were incomplete in one or more requirements of Reliability Standard FAC-002_R1. - 2.2. Level 2: Not applicable. - 2.3. Level 3: Not...

AI summary The document outlines four levels of non-compliance related to assessments of new facilities under Reliability Standard FAC-002_R1. Level 1 involves incomplete assessments, while Level 4 indicates no assessments were provided. Levels 2 and 3 are not applicable in this context.

tions and training, as defined by the Transmission Owner, to perform their duties. - R1.4. Each Transmission Owner shall develop mitigation measures to achieve sufficient clearances for the protection of the transmission facilities when it...

AI summary The requirements outline vegetation management practices for Transmission Owners, including mitigation measures for clearances, immediate communication of threats, and annual plans considering environmental factors and regulatory permissions.

C. Measures - M1. The Transmission Owner has a documented TVMP, as identified in Requirement 1. - M1.1. The Transmission Owner has documentation that the Transmission Owner performed the vegetation inspections as identified in Requirement...

AI summary The document outlines compliance measures for vegetation management, documentation requirements, and reporting obligations under transmission and reliability standards. It specifies that the Transmission Owner must maintain documented processes for vegetation inspections, clearances, personnel qualifications, and outage reporting to the RRO and NERC.

1.4. Additional Compliance Information The Transmission Owner shall demonstrate compliance through self-certification submitted to the compliance monitor (RRO) annually that it meets the requirements of NERC Reliability Standard FAC-003-1....

AI summary The Transmission Owner must annually self-certify compliance with NERC FAC-003-1 to the RRO. The RRO will conduct onsite audits every five years and may perform field audits of ROW vegetation as needed to verify compliance with the reliability standard.

2.2. Level 2: - 2.2.1. The TVMP was incomplete in two of the requirements specified in any subpart of Requirement 1, or; - 2.2.2. The Transmission Owner was unable to certify during its annual selfcertification that it fully implemented it...

AI summary The subsections outline scenarios where the Transmission Vegetation Management Plan (TVMP) or the Transmission Owner's compliance with annual requirements may be deficient, including incomplete plan requirements, failure to self-certify implementation, or reporting a Category 2 vegetation-related outage.

2.3. Level 3: - 2.3.1. The Transmission Owner reported one Category 1 or multiple Category 2 transmission vegetation-related outages in a calendar year, or; - 2.3.2. The Transmission Owner did not maintain a set of clearances (Clearance 2)...

AI summary Level 3 criteria include transmission vegetation-related outages, failure to maintain required clearances, and incomplete Transmission Vegetation Management Plans (TVMP). These conditions relate to infrastructure planning and system reliability requirements.

2.4. Level 4: - 2.4.1. The Transmission Owner reported more than one Category 1 transmission vegetation-related outage in a calendar year, or; - 2.4.2. The TVMP was incomplete in four or more of the requirements specified in any subpart of...

AI summary Level 4 criteria include multiple vegetation-related outages or incomplete TVMP requirements, indicating non-compliance with transmission vegetation management standards.

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

AI summary The document outlines the methodology for establishing System Operating Limits (SOLs) for the planning horizon under FAC-010-2.1, aligning with NERC and FERC standards. It emphasizes compliance with reliability criteria, interconnection rules, and communication protocols for SOLs and Interconnection Reliability Operating Limits (IROLs).

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 det...

AI summary The document outlines the methodology for determining System Operating Limits (SOLs) in the planning of the Bulk Electric System (BES), ensuring reliability through established procedures. It is identified as FAC-010-2.1, focusing on standardized approaches for SOL determination.

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...

AI summary The Planning Authority must establish a documented SOL Methodology for developing System Operating Limits (SOLs) within its area, ensuring alignment with Facility Ratings and Bulk Electric System (BES) performance under contingencies like faults, outages, and stability constraints. Requirements emphasize transient, dynamic, and voltage stability, as well as prevention of cascading failures.

Standard FAC-010-2 — System Operating Limits Methodology for the Planning Horizon - M1. The Planning Authority's SOL Methodology shall address all of the items listed in Requirement 1 through Requirement 3. - M2. The Planning Authority sha...

AI summary The Planning Authority's System Operating Limits (SOL) Methodology must address specified requirements, provide evidence of methodology issuance, and respond to technical comments within 45 days. Compliance with these procedural mandates ensures adherence to regulatory standards for planning horizon SOL methodologies.

1. Compliance Monitoring Process

AI summary The section outlines the compliance monitoring process, likely involving regulatory oversight and adherence to standards such as CIP and FAC. It may discuss roles of entities like NSUARB and NSPI in ensuring compliance with reliability and operational protocols.

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...

AI summary Defines Level 1 non-compliance for Western Interconnection if SOL Methodology lacks a statement on not exceeding Facility Ratings, pending VSLs from WECC.

Standard FAC-010-2 — System Operating Limits Methodology for the Planning Horizon - 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 addre...

AI summary The document outlines non-compliance levels for the System Operating Limits (SOL) Methodology, including failure to address required elements, missing contingency evaluations, and incomplete distribution. Levels 2-4 detail specific deficiencies in the methodology's scope and implementation, adopted by the Board of Trustees in 2009.

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...

AI summary This section outlines the violation severity levels related to the Planning Authority's adherence to SOL Methodology requirements. It categorizes violations into lower, moderate, high, and severe levels based on the extent to which the methodology addresses specific requirements.

Standard FAC-010-2 — System Operating Limits Methodology for the Planning Horizon 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...

AI summary The text discusses the System Operating Limits Methodology for the Planning Horizon under Standard FAC-010-2, outlining response timeframes for the Planning Authority to address technical comments on its SOL Methodology, with different requirements based on severity levels.

- 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...

AI summary The text outlines the Interconnection-wide Regional Difference applicable in the Western Interconnection, detailing specific multiple Facility Contingencies that must be evaluated when establishing System Operating Limits (SOLs). It includes various fault scenarios and conditions under which certain contingencies may be excluded or considered.

ie 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...

AI summary The document outlines the establishment of System Operating Limits (SOLs) to ensure system performance during multiple facility contingencies. It emphasizes maintaining stability, preventing cascading failures, and allowing for controlled interruptions or adjustments to maintain system security.

R 1 No l ica b le t a p p Co T he Re l ia b i l i d ina ha ty to or r s a do d S O L M ho do log te t cu m en e y S O fo in de lop ing Ls r u se ve i h in i Re l ia b i l i Co d ina t ts ty to or r w Ar bu i do d dr t t t a ea es n o es s...

AI summary The text discusses the reliability standards and system operating limits in the context of transmission vegetation management and facility ratings methodology, referencing various regulatory frameworks and standards such as NERC, FAC-008-1, and SOLS.

br>e y l l bu f he ire d i ies t tw t t t a o o re q u en fo A N D ha in r a c ng e ho do log he ha d t t m e y, c ng e ho do log i de d t to m e wa s p ro up y v 3 0 len da da f he te t ca r y s a r f fe f ive he ha t t e c ne ss o c ng e...

AI summary The text appears to be a fragmented and corrupted version of a document discussing reliability standards, system operating limits, and facility ratings methodology, including references to the North American Electric Reliability Corporation (NERC), the Western Electricity Coordinating Council (WECC), and the Federal Energy Regulatory Commission (FERC).

- 1. The following Interconnection-wide Regional Difference shall be applicable in the Western Interconnection: - 1.1. As governed by the requirements of R3.3, starting with all Facilities in service, shall require the evaluation of the fo...

AI summary The text outlines specific interconnection-wide regional difference requirements for the Western Interconnection, detailing various facility contingencies that must be evaluated when establishing system operating limits (SOLs), including fault conditions, circuit failures, and protection system responses.

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...

AI summary The text outlines requirements for System Operating Limits (SOLs) to ensure system performance during multiple facility contingencies, including maintaining thermal, frequency, and voltage limits, preventing cascading failures, and ensuring stability. It also mentions adjustments based on system performance and design.

2. Levels of Non-Compliance - 2.1. Level 1: Not applicable. - 2.2. Level 2: Not all requested Transfer Capabilities were provided in accordance with their respective schedules. - 2.3. Level 3: Transfer Capabilities were not developed consi...

AI summary The document outlines four levels of non-compliance related to Transfer Capabilities. Level 2 involves partial non-delivery on schedule, Level 3 refers to methodology inconsistencies, and Level 4 indicates complete failure to deliver. Level 1 is not applicable, emphasizing structured compliance tiers for transfer capability adherence.

R 1 T he S O Ls fo he t re a re r , Co Re l ia b i l i d ina Ar bu ty to t or r ea , fro bu les ha 1 % to t t 2 5 % m p s n u f he S O Ls inc is t te t o se a re on s n i h he Re l ia b i l i Co d ina 's t t ty to or r w S O L M ho do log...

AI summary The text discusses violation severity levels related to System Operating Limits (SOLs) and Interconnection Reliability Operating Limits (IROLS), indicating different percentages of violations and their implications for reliability and compliance.

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 reliabili...

AI summary The document outlines four levels of non-compliance based on the number of occurrences of failing to distribute information to reliability entities as per R1. Levels escalate from one occurrence (Level 1) to four or more occurrences or lack of evidence (Level 4).

B. Requirements - R1. Prior to the expiration of the reliability assessment period defined in the Timing Table, Column B, the Balancing Authority and Transmission Service Provider shall respond to a request from an Interchange Authority to...

AI summary The requirements outline procedures for transitioning Arranged Interchange to Confirmed Interchange, including evaluations by Balancing Authorities on energy profile, ramp capability, and scheduling paths, and confirmations by Transmission Service Providers regarding transmission service arrangements and system limits.

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 request from an Interchange Auth...

AI summary The Balancing Authority and Transmission Service Provider must provide evidence of responding to requests from an Interchange Authority regarding transitioning Arranged Interchange to Confirmed Interchange within the reliability assessment period defined in the Timing Table, Column B.

1.4. Additional Compliance Information The Balancing Authority and Transmission Service Provider shall demonstrate compliance to the Compliance Monitor within the first year that this standard becomes effective or the first year the entity...

AI summary The Balancing Authority and Transmission Service Provider must self-certify compliance with reliability standards initially, followed by audits and spot checks. Complaints must be addressed within 60 days, with data and logs provided for inspection. Compliance is verified through audits, spot checks, and complaint evaluations.

Standard INT-006-2 — Response to Interchange Authority - 2.3. Level 3: Three occurrences1 of not responding to the Interchange Authority as described in R1. - 2.4. Level 4: Four or more occurrences 1 of not responding to the Interchange Au...

AI summary The text outlines Level 3 and Level 4 violations under Standard INT-006-2, detailing non-response to the Interchange Authority. Level 3 involves three occurrences, while Level 4 includes four or more occurrences or lack of evidence, referencing R1.

A B C D If Actual Arranged Interchange (RFI) is Submitted IA Makes Initial Distribution of Arranged Interchange BA and TSP Conduct Reliability Assessments IA Verifies Reliability Data Complete IA Compiles and Distributes Status BA Prepares...

AI summary The document outlines timelines for interchange confirmation and reliability assessments in Nova Scotia's regulatory process. It specifies response time thresholds for entities like IA (Interchange Authority), BA (Balancing Authority), and TSP (Transmission Service Provider) to ensure reliability before implementing arranged interchange, referencing standard INT-007-1.

B. Requirements - R1. The Interchange Authority shall verify that Arranged Interchange is balanced and valid prior to transitioning Arranged Interchange to Confirmed Interchange by verifying the following: - R1.1. Source Balancing Authorit...

AI summary The Interchange Authority must verify Arranged Interchange balance, NERC registry compliance, parameter definitions, and approval from Balancing Authorities and Transmission Service Providers before confirming interchange. Requirements include megawatt equality, entity registry checks, and reliability assessments.

D. Compliance - 1. Compliance Monitoring Process - 1.1. Compliance Monitoring Responsibility Regional Reliability Organization. 1.2. Compliance Monitoring Period and Reset Time Frame The Performance-Reset Period shall be twelve months from...

AI summary The compliance monitoring process assigns responsibility to the Regional Reliability Organization. The Performance-Reset Period is defined as twelve months from the last noncompliance to R1, establishing a timeframe for resetting compliance status.

2. Levels of Non-Compliance: for a Regional Reliability Organization: - 2.1. Level 1: Not applicable - 2.2. Level 2: Not applicable - 2.3. Level 3: Not applicable - 2.4. Level 4: Does not have evidence it established one or more Reliabilit...

AI summary The document outlines non-compliance Level 4 for a Regional Reliability Organization, noting the absence of evidence that Reliability Coordinators were established to assess transmission reliability and coordinate emergency operations as required.

3. Levels of Non-Compliance for a Reliability Coordinator: - 3.1. Level 1: Not applicable. - 3.2. Level 2: Not applicable. - 3.3. Level 3: Not applicable . - 3.4. Level 4: There shall be a separate Level 4 non-compliance for every one of t...

AI summary The document outlines non-compliance levels for Reliability Coordinators and other entities, with Level 4 detailing specific violations such as lacking authority, formal agreements, and adherence to NERC standards. Similar structures apply to Transmission Operators and Balancing Authorities.

2. Levels of Non-Compliance for a Reliability Coordinator - 2.1. Level 1: Not applicable. - 2.2. Level 2: Did not confirm that the network used for data exchange to other Reliability Coordinators is secure as specified in R3. - 2.3. Level...

AI summary The document outlines four levels of non-compliance for a Reliability Coordinator, detailing violations related to data security, reliability coordination tasks, communication facilities, and monitoring procedures. Each level corresponds to specific regulatory requirements (e.g., R3, R7, R9).

1.1. Compliance Monitoring Responsibility Regional Reliability Organizations shall be responsible for compliance monitoring.

AI summary The document assigns compliance monitoring responsibility to Regional Reliability Organizations (RROs) within the context of regulatory proceedings, emphasizing their role in ensuring adherence to reliability standards.

2. Levels of Non-Compliance 2.1. Level 1: System studies were not conducted for one day in a calendar month and/or the action plans were not developed to maintain transmission loading within acceptable limits for potential interface and ot...

AI summary The document outlines four levels of non-compliance based on missed system studies and inadequate action plans to maintain transmission loading within acceptable limits for IROL violations. Levels escalate with increasing days of missed studies (1–4 days, 4–5 days, etc.).

3. Levels of Non-Compliance for a Reliability Coordinator: - 3.1. Level 1: Not applicable. - 3.2. Level 2: Did not make Interchange Transaction information available to all other Reliability Coordinators in the Interconnection. (Requiremen...

AI summary The document outlines non-compliance levels for Reliability Coordinators, detailing violations related to information sharing, coordination with Balancing Authorities, and adherence to standards like DCS, CPS, and SOL. Levels 2–4 escalate from minor to severe infractions, including failure to address GMD events, delay in emergency actions, and inadequate monitoring.

4. Levels of Non-Compliance for a Transmission Service Provider - 4.1. Level 1: Not applicable. - 4.2. Level 2: Not applicable. - 4.3. Level 3: Not applicable. - 4.4. Level 4: There shall be a separate Level 4 non-compliance, for every one...

AI summary Level 4 non-compliance applies to transmission service providers violating specific operational requirements, including failing to use the most limiting parameter when limits differ and not adhering to System Operating Limits (SOLs) or Interconnection Reliability Operating Limits (IROLs) as defined in filed tariffs and regional processes.

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) requirem...

AI summary The document outlines four violation severity levels (Lower, Moderate, High, Severe) for reliability violations in the Eastern and Western Interconnections. Conditions include non-compliance with Interconnection-wide procedures, improper congestion management, and failure to follow mitigation protocols by Reliability Coordinators and Balancing Authorities.

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 contai...

AI summary The document discusses regional differences in congestion management under PJM/MISO and SPP waivers, including retirement upon field test completion. SPP's regional difference impacts Balancing Authorities in its market, requiring studies on external flowgates and designation of Coordinated Flowgates (CF).

Transmission Loading Relief Procedure — Eastern Interconnection

AI summary This document outlines the Transmission Loading Relief Procedure for the Eastern Interconnection, addressing regulatory processes and compliance with standards such as FAC-014-2 and TOP-007-0. It involves entities like NSUARB and NSPI, focusing on system reliability and transmission operations within the Eastern Interconnection framework.

Purpose This standard defines procedures for curtailment and reloading of Interchange Transactions to relieve overloads on transmission facilities modeled in the Interchange Distribution Calculator.

AI summary This standard establishes procedures for managing Interchange Transactions through curtailment and reloading to alleviate overloads on transmission facilities, as modeled by the Interchange Distribution Calculator. The focus is on ensuring reliable transmission operations by mitigating congestion risks.

Applicability This standard only applies to the Eastern Interconnection. - 1. Transmission Loading Relief (TLR) Procedure - 1.1. Initiation only by Reliability Coordinator. A Reliability Coordinator shall be the only entity authorized to i...

AI summary The standard applies to the Eastern Interconnection, detailing the Transmission Loading Relief (TLR) Procedure initiated by Reliability Coordinators to mitigate System Operating Limit (SOL) and Interconnection Reliability Operating Limit (IROL) violations. TLR is not effective as a sole tool for existing IROL violations, with alternatives like redispatch and load shedding recommended.

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....

AI summary TLR Level 1 requires Reliability Coordinators to notify others via RCIS if a secure transmission system faces potential SOL or IROL violations due to contingencies. Affected coordinators must verify Interchange Transactions 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: - The transmission system is se...

AI summary The document outlines TLR (Transmission Load Relief) levels 2 through 5a, detailing conditions for activating each level to prevent SOL (System Operating Limit) or IROL (Interconnection Reliability Operating Limit) violations. Measures include curtailing non-firm transmission services, reconfiguring transmission, and reallocating service priorities.

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 enter...

AI summary The section outlines TLR Level 5b, requiring the Reliability Coordinator to curtail interchange transactions via firm transmission service to prevent SOL or IROL violations under specific conditions, referencing 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...

AI summary The Reliability Coordinator must curtail interchange transactions using firm transmission service at TLR Levels 5a and 5b to manage system reliability, either by enabling additional transactions after non-firm service curtailment or mitigating SOL/IROL violations post-reconfiguration attempts.

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. - One or more...

AI summary TLR Level 6 emergency procedures are triggered when transmission facilities exceed or risk exceeding their System Operating Limits (SOL) or Interconnection Reliability Operating Limits (IROL). The Reliability Coordinator must direct Balancing Authorities and Transmission Operators to redispatch generation, reconfigure transmission, or reduce load to stabilize the Bulk Electric System (BES) until conditions are resolved.

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...

AI summary The Reliability Coordinator must notify all Interconnection Reliability Coordinators via RCIS when SOL or IROL violations are resolved, allowing Interchange Transactions to resume. High-priority transactions are restored first upon system reliability restoration.

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 se...

AI summary The document outlines appendices for the Transmission Loading Relief Standard, noting that certain sections were moved to NAESB TLR business practices. Appendices A, C, E, and F are included, covering transaction management, IDC reallocation processes, and interchange transaction considerations. The Board of Trustees approved the document on April 15, 2009.

Appendix C. Sample NERC Transmission Loading Relief Procedure Log

AI summary Appendix C provides a sample log for NERC's Transmission Loading Relief Procedure, though no specific details or data are included in the provided text. The log's purpose and structure are indicated, but substantive content is absent.

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 Leve...

AI summary This document outlines the NERC Transmission Loading Relief (TLR) procedure log, detailing steps taken during incidents involving transmission overloads, including notifications, halting transactions, curtailing services, and implementing emergency procedures. It includes various levels of TLR actions, flowgate ratings, and associated reliability coordinator conditions.

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...

AI summary Appendix E outlines the IDC's reallocation process, including algorithmic handling of reloading principles, reporting requirements, and status display. The IDC interacts with the Tag Authority and posts data to the NERC TLR website, referencing attachments and a NERC specification for E-Tag systems.

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 al...

AI summary The IDC process involves the Reliability Coordinator running reports, entering maximum loading values, and distributing reports to Balancing Authorities and Transmission Operators. Tags for Interchange Transactions must be submitted by deadlines, with consequences for late submissions.

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 NER...

AI summary The document outlines three statuses for Reloading/Reallocation Interchange Transactions: HOLD (pending evaluation), CURTAILED (restricted due to curtailment thresholds), and PROCEED (allowed to flow). The IDC determines status, with Balancing Authorities updating E-Tag adjustments. Transactions above curtailment thresholds are restricted, while those below are unrestricted but subject to reliability standards.

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 "Constr...

AI summary The document outlines prioritization rules for reallocating and reloading interchange transactions using the Constrained Path Method (CPM). Lower-priority transactions are curtailed pro-rata to enable higher-priority ones, with Firm Point-to-Point Transmission Service taking precedence over Non-firm services. E-Tags must be submitted by specific deadlines for reallocation consideration.

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 loadin...

AI summary The Reliability Coordinator calculates net flow changes on constrained facilities, manages Interchange Transactions, and uses TLR levels to avoid SOL/IROL violations. Procedures include simultaneous curtailment/reallocation, prioritizing higher-priority transmission, and reloading transactions promptly to prevent recurrence of violations.

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 pur...

AI summary The IDC automatically reminds Reliability Coordinators via alarms at 00:25 each hour to re-issue TLR Level 2 or higher from the previous hour. This ensures timely reallocation of halted interchange transactions and availability of tags for submission before reallocation deadlines if upgraded to TLR Level 3a or 5a.

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 p...

AI summary The IDC assists Reliability Coordinators in calculating MW relief for constrained facilities during TLR levels 3a and 5a by analyzing Point-to-Point Transactions and Balancing Authority flows. This data helps determine relief/reloading amounts for constrained facilities, prioritizing higher-priority Transmission Service.

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 Coordinator...

AI summary When TLR Levels 1 or 0 are issued, constrained facilities are no longer under SOL/IROL violations, allowing interchange transactions. The IDC provides details on previously halted transactions in TLR reports for reliability coordinators.

Appendix F. Considerations for Interchange Transactions Using Firm Point-to-Point Transmission Service The following cases explain the circumstances under which an Interchange Transaction using Firm Pointto-Point Transmission Service will...

AI summary Appendix F outlines scenarios allowing Interchange Transactions using Firm Point-to-Point Transmission Service to proceed during TLR 3b, though specific cases are not detailed in the provided text.

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...

AI summary Case 1 outlines procedures for handling Interchange Transactions during TLR 3b. The IDC examines transactions, prioritizes Firm Point-to-Point services, issues ADJUST Lists, and manages curtailments or holds for Non-firm services. Transactions submitted after 00:25 are delayed, while mitigation of SOL/IROL violations allows rescheduling at 02:00.

B. Requirements - R1. The Reliability Coordinator shall have Operating Procedures, Processes, or Plans in place for activities that require notification, exchange of information or coordination of actions with one or more other Reliability...

AI summary The requirements outline procedures for Reliability Coordinators to ensure interconnection reliability through communication protocols, outage management, voltage control, and coordinated action plans. Procedures must be agreed upon, distributed, and periodically reviewed, with specific focus on addressing energy shortages, unplanned outages, and adverse reliability impacts.

C. Measures - M1. The Reliability Coordinator's System Operators shall have available for Real-time use, the latest approved version of Operating Procedures, Processes, or Plans that require notifications, information exchange or the coord...

AI summary The document outlines measures requiring Reliability Coordinators to maintain up-to-date operating procedures for real-time use, ensure agreement and distribution among coordinators, include version control, and conduct reviews within three years. These measures aim to standardize coordination, communication, and reliability management across systems.

1. Compliance Monitoring Process

AI summary The section outlines the compliance monitoring process, likely involving regulatory oversight and adherence to standards such as CIP and FAC. It may discuss roles of entities like NSUARB and NSPI in ensuring compliance with reliability and operational protocols.

1.4. Additional Compliance Information The Reliability Coordinator shall demonstrate compliance through self-certification submitted to its Compliance Monitor annually. The Compliance Monitor shall also use a scheduled on-site review at le...

AI summary The Reliability Coordinator must comply via annual self-certification and periodic on-site reviews by the Compliance Monitor. Investigations into complaints must occur within 30 days of discovery and conclude within 45 days. Documents related to interconnection reliability procedures and their distribution must be available for audit or inspection.

2. Levels of Non-Compliance - 2.1. Level 1: There shall be a level one non-compliance if either of the following conditions is present: - 2.1.1 The latest versions of Operating Procedures, Processes, or Plans (identified through self-certi...

AI summary The document outlines four levels of non-compliance related to reliability standards, specifying conditions for each level. Level 1 requires version control and distribution lists for operating procedures, while higher levels address distribution failures, unavailability, and omission of required topics, with Level 4 being non-applicable. Reliability Standard IRO-014 R1 is referenced as a critical benchmark.

2. Levels of Non-Compliance - 2.1. Level 1: Did not participate in agreed upon (at least weekly) conference calls and other communication forums with adjacent Reliability Coordinators. - 2.2. Level 2: Did not notify other Reliability Coord...

AI summary The document outlines four levels of non-compliance related to reliability coordination, ranging from failure to participate in communication forums to causing adverse reliability impacts due to notification lapses. Each level specifies actions and consequences, emphasizing adherence to operating procedures and information sharing.

1.4. Additional Compliance Information The Reliability Coordinator shall demonstrate compliance through self-certification submitted to its Compliance Monitor annually. The Compliance Monitor shall use a scheduled on-site review at least o...

AI summary The Reliability Coordinator must submit annual self-certifications to its Compliance Monitor, which conducts on-site reviews every three years and investigates complaints within 45 days. The Compliance Monitor must verify coordination with other Reliability Coordinators to address interconnection issues during audits or investigations.

2. Levels of Non-Compliance - 2.1. Level 1: Dynamics data was provided, but was incomplete in one of the four areas identified in Reliability Standard MOD-013-0_R1. - 2.2. Level 2: Not Applicable. - 2.3. Level 3: Dynamics data was provided...

AI summary The document outlines four levels of non-compliance based on the completeness of dynamics data relative to Reliability Standard MOD-013-0_R1. Level 1 involves incomplete data in one area, Level 3 in two or more areas, Level 4 lacks data entirely, while Level 2 is not applicable.

2. Levels of Non-Compliance - 2.1. Level 1: Information for Reliability Standard MOD-018-0 item R1.1 or R1.2 was not provided. - 2.2. Level 2: Information for Reliability Standards MOD-018-0 items R1.1 and R1.2 was not provided. - 2.3. Lev...

AI summary The document outlines four levels of non-compliance related to Reliability Standard MOD-018-0. Levels 1 and 2 involve missing information for specific items (R1.1 and R1.2), while Levels 3 and 4 are not applicable. This categorization addresses gaps in reporting requirements under the standard.

D. Compliance - 1. Compliance Monitoring Process - 1.1. Compliance Monitoring Responsibility Each Regional Reliability Organization.

AI summary The compliance monitoring process assigns responsibility to each Regional Reliability Organization (RRO) for ensuring adherence to regulatory standards within the Nova Scotia Utility and Review Board (NSUARB) proceedings. This structure emphasizes the role of RROs in maintaining system reliability and regulatory compliance.

Standard MOD-020-0 — Providing Interruptible Demands and DCLM Data - 2.3. Level 3: Not applicable. - 2.4. Level 4: Interruptible Demands and DCLM data were not provided to Reliability Coordinators, Balancing Authorities, and Transmission O...

AI summary The document outlines Standard MOD-020-0, which addresses the provision of Interruptible Demands and DCLM data. Level 3 is not applicable, while Level 4 indicates that such data were not provided to Reliability Coordinators, Balancing Authorities, and Transmission Operators, potentially impacting system reliability and compliance.

2. Levels of Non-Compliance for a Reliability Coordinator - 2.1. Level 1: Not applicable. - 2.2. Level 2: Not applicable. - 2.3. Level 3: Not applicable. - 2.4. Level 4: There shall be a separate Level 4 non-compliance, for every one of th...

AI summary The document outlines Level 4 non-compliance criteria for Reliability Coordinators, requiring specific training, understanding of regional operations, and knowledge of Balancing Authorities and operators. These requirements were adopted by the Board of Trustees in 2006.

2. Levels of Non-Compliance for Generator Operators: - 2.1. Level 1: Not applicable. - 2.2. Level 2 : Not applicable. - 2.3. Level 3: Not applicable. - 2.4. Level 4: Failed to provide evidence of coordination when installing new protective...

AI summary The document outlines non-compliance levels for generator operators, with Level 4 specifically noting a failure to provide evidence of coordination during protective system installations and changes with the Transmission Operator and Host Balancing Authority as required by R3.1.

3. Levels of Non-Compliance for Transmission Operators: - 3.1. Level 1: Not applicable. - 3.2. Level 2 : Not applicable. - 3.3. Level 3: Not applicable. - 3.4. Level 4: There shall be a separate Level 4 non-compliance, for every one of the...

AI summary The document outlines non-compliance levels for transmission operators, with Level 4 specifically addressing failures to coordinate protective system installations with neighboring operators and Balancing Authorities, as well as inadequate monitoring of Special Protection Systems. These violations trigger Level 4 non-compliance under rules R3.2 and R6.

4. Levels of Non-Compliance for Balancing Authorities: - 4.1. Level 1: Not applicable. - 4.2. Level 2 : Not applicable. - 4.3. Level 3: Not applicable. - 4.4. Level 4: Did not monitor the status of each Special Protection System, or did no...

AI summary The document outlines non-compliance levels for Balancing Authorities, with Level 4 requiring monitoring of Special Protection Systems (SPS) and notifying Transmission Operators and Balancing Authorities of changes as per R6. Higher levels involve more severe non-compliance actions.

2. Levels of Non-Compliance for Transmission Owners and Distribution Providers that own a Transmission Protection System: - 2.1. Level 1: Documentation of Misoperations is complete according to PRC-004 R1, but documentation of Corrective A...

AI summary The document outlines four levels of non-compliance for transmission owners and distribution providers regarding their transmission protection systems. Levels range from incomplete documentation of corrective actions (Level 1) to no documentation or analysis of misoperations (Level 4), with references to PRC-004 R1 and the Regional Reliability Organization's requirements.

3. Levels of Non-Compliance for Generator Owners - 3.1. Level 1: Documentation of Misoperations is complete according to PRC-004 R2, but documentation of Corrective Action Plans is incomplete. - 3.2. Level 2: Documentation of Misoperations...

AI summary The document outlines four levels of non-compliance for generator owners, focusing on documentation of misoperations and corrective action plans under PRC-004 R2 and R3. Levels escalate from incomplete documentation to no analysis or reporting, impacting system reliability and regulatory adherence.

Standard PRC-004-1 — Analysis and Mitigation of Transmission and Generation Protection System Misoperations

AI summary This document outlines the requirements for analyzing and mitigating misoperations in transmission and generation protection systems under NERC's PRC-004-1 standard. It emphasizes the importance of reliability coordination, incident response, and compliance with facility ratings and operating limits to prevent grid disruptions.

2. Levels of Non-Compliance - 2.1. Level 1: Analysis of UFLS program performance following an actual underfrequency event below the UFLS set point(s) was incomplete in one or more elements in Reliability Standard PRC-009-0_R1. - 2.2. Level...

AI summary The document outlines non-compliance levels with reliability standards, specifically highlighting incomplete analysis of UFLS program performance under PRC-009-0_R1 (Level 1) and absence of analysis (Level 4), indicating gaps in adherence to underfrequency load shedding requirements.

Standard PRC-016-0.1 — Special Protection System Misoperations

AI summary This regulatory proceeding addresses Standard PRC-016-0.1, focusing on preventing misoperations of Special Protection Systems (SPS) to ensure grid reliability. Nova Scotia Utility and Review Board (NSUARB) and Nova Scotia Power Incorporated (NSPI) are key entities involved in enforcing compliance with protection reliability coordination standards.

4. Applicability - 4.1. Transmission Owner. - 4.2. Generator Owner. - 5. Effective Dates: Phased in over four years after BOT adoption: Requirements 1 and 2: - − 50% compliant two years after initial issuance of regional requirements per R...

AI summary The document outlines compliance requirements for Transmission and Generator Owners under PRC-002, phased over four years post-BOT adoption. Compliance milestones include 50% adherence after two years, 75% after three, and full compliance after four years for Requirements 1-2, with earlier deadlines for Requirements 3-6 tied to DME installation timelines.

Standard PRC-018-1 — Disturbance Monitoring Equipment Installation and Data Reporting - R3.3. Installation location. - R3.4. Operational status. - R3.5. Date last tested. - R3.6. Monitored elements, such as transmission circuit, bus sectio...

AI summary The standard outlines requirements for installing Disturbance Monitoring Equipment (DME), including location, operational status, and data recording. It mandates data archiving for three years and maintenance programs for DMEs as per Regional Reliability Organization (RRO) standards.

2. Levels of Non-Compliance for a Balancing Authority: - 2.1. Level 1: Not applicable. - 2.2. Level 2: Not applicable. - 2.3. Level 3: Not applicable. - 2.4. Level 4: There shall be a separate Level 4 non-compliance, for every one of the f...

AI summary The document outlines non-compliance levels for a Balancing Authority, with Level 4 specifically addressing violations of reliability directives by Reliability Coordinators/Transmission Operators and failure to provide emergency assistance as required by R6.

3. Levels of Non-Compliance for a Transmission Operator - 3.1. Level 1: Not applicable. - 3.2. Level 2: Not applicable. - 3.3. Level 3: Not applicable. - 3.4. Level 4: There shall be a separate Level 4 non-compliance, for every one of the...

AI summary The document outlines Level 4 non-compliance for Transmission Operators, detailing specific violations such as lack of documented authority, failure to act during emergencies, non-compliance with reliability directives, and improper removal of Bulk Electric System facilities. These violations trigger formal non-compliance actions.

4. Levels of Non-Compliance for a Generator Operator: Effective Date: January 1, 2007 - 4.1. Level 1: Not applicable. - 4.2. Level 2: Not applicable. - 4.3. Level 3: Not applicable. - 4.4. Level 4: There shall be a separate Level 4 non-com...

AI summary The document outlines four levels of non-compliance for generator operators, with Level 4 detailing specific violations including failure to follow reliability directives, refusing emergency assistance, and improperly removing Bulk Electric System (BES) facilities from service. Effective January 1, 2007, these levels define consequences for non-adherence to reliability and operational standards.

3. Levels of Non-Compliance for Transmission Operators - 3.1. Level 1: Did not use uniform line identifiers when referring to transmission facilities of an interconnected network as specified in R18. - 3.2. Level 2: Not applicable. - 3.3....

AI summary The document outlines four levels of non-compliance for transmission operators, detailing specific violations such as failure to use uniform line identifiers, update studies, maintain current-day plans, and notify Balancing Authorities. These levels reference regulatory requirements (R1, R5, R6, R10, R11, R16) related to system reliability and operational standards.

4. Levels of Non-Compliance for Generator Operators: - 4.1. Level 1: Did not use uniform line identifiers when referring to transmission facilities of an interconnected network as specified in R18. - 4.2. Level 2: Not applicable. - 4.3. Le...

AI summary The document outlines four levels of non-compliance for generator operators, with Level 1 requiring uniform line identifiers for transmission facilities and Level 4 addressing violations in capability verification, notifications to authorities, and output forecasting. Levels 2 and 3 are not applicable.

Standard TOP-002-2a — Normal Operations Planning 5.2. Level 2: Not applicable. 5.3. Level 3: Not applicable. 5.4. Level 4: Not applicable.

AI summary The document states that Levels 2, 3, and 4 of Standard TOP-002-2a — Normal Operations Planning are not applicable. No further details or rationale are provided in the text.

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 requirem...

AI summary The requirement allows flexibility in conducting reviews or studies, which may be computer-based or manual, to ensure the Transmission Operator remains sensitive to ongoing or emerging issues. No specific method is mandated.

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?"

AI summary The question seeks clarification on whether 'to determine SOLs' in Requirement R11 refers to establishing system operating limits or identifying potential violations. This hinges on interpreting the term 'determine' within the context of regulatory standards like FAC-014-2, which emphasizes establishing and communicating SOLs.

A. Introduction 1. Title: Planned Outage Coordination 2. Number: TOP-003-0 3. Purpose: Scheduled generator and transmission outages that may affect the reliability of interconnected operations must be planned and coordinated among Balancin...

AI summary The document outlines the need for coordinated planning of scheduled generator and transmission outages to maintain reliability among Balancing Authorities, Transmission Operators, and Reliability Coordinators under TOP-003-0.

4. Applicability - 4.1. Generator Operators. - 4.2. Transmission Operators. - 4.3. Balancing Authorities. - 4.4. Reliability Coordinators. 5. Effective Date: April 1, 2005

AI summary Section 4 outlines the applicability of regulations to Generator Operators, Transmission Operators, Balancing Authorities, and Reliability Coordinators. The effective date is set for April 1, 2005, indicating when these requirements become enforceable.

B. Requirements - R1. Generator Operators and Transmission Operators shall provide planned outage information. - R1.1. Each Generator Operator shall provide outage information daily to its Transmission Operator for scheduled generator outa...

AI summary The requirements outline obligations for Generator Operators, Transmission Operators, and Balancing Authorities to report and coordinate scheduled outages exceeding specific thresholds (50 MW, 100 kV) to prevent System Operating Limit (SOL) or Interconnection Reliability Operating Limit (IROL) violations. Outage information must be submitted by 12:00 CST/PST, with Reliability Coordinators resolving scheduling conflicts.

C. Measures M1. Evidence that the Generator Operator, Transmission Operator, Balancing Authority, and Reliability Coordinator reported and coordinated scheduled outage information as indicated in the requirements above. Adopted by NERC Boa...

AI summary The measure requires Generator Operator, Transmission Operator, Balancing Authority, and Reliability Coordinator to report and coordinate scheduled outage information as per NERC standards, adopted by the NERC Board of Trustees on February 8, 2005.

1. Compliance Monitoring Process Each Regional Reliability Organization shall conduct a review every three years to ensure that each responsible entity has a process in place to provide planned generator and/or bulk transmission outage inf...

AI summary The document outlines a three-year compliance review process by Regional Reliability Organizations (RROs) to ensure entities provide outage information to Reliability Coordinators and neighboring operators. Investigations may be initiated by RROs or NERC upon complaints, with notifications required within 60 days. Investigation methods are determined by NERC/RRO.

1.1. Compliance Monitoring Responsibility A Reliability Coordinator makes a request for an outage to "not be taken" because of a reliability impact on the grid and the outage is still taken. The Reliability Coordinator must provide all its...

AI summary Reliability Coordinators must document and report outages with reliability impacts within three business days to the Regional Reliability Organization (RRO), which then reports compliance and violations to NERC via its Compliance Reporting process.

2. Levels of Non-Compliance - 2.1. Level 1: Each entity responsible for reporting information under Requirements R1 and R3 has a process in place to provide information to their Reliability Coordinator but does not have a process in place...

AI summary The document outlines four levels of non-compliance, with Level 1 highlighting missing processes for sharing information with neighboring Balancing Authorities and Transmission Operators, and Level 4 addressing failures in outage information exchange or adherence to Reliability Coordinator directives.

Standard TOP-004-2 — Transmission Operations - 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 restore operations to respect proven reliable...

AI summary The text outlines Level 4 non-compliance under TOP-004-2 for two violations: failure to restore operations within 30 minutes as per R4 and absence of formal policies on three topics from R6.1 to R6.4. These requirements ensure adherence to reliable power system limits and proper procedural frameworks.

Attachment 1 — TOP-005-1.1

AI summary Attachment 1 — TOP-005-1.1 relates to operational reliability information standards under the Nova Scotia Utility and Review Board (NSUARB) regulatory proceeding. It involves compliance with NERC and FERC standards, including CIP and TOP-005-1.1 requirements for reporting system operating limits and reliability data.

Electric System Reliability Data This Attachment lists the types of data that Reliability Coordinators, Balancing Authorities, and Transmission Operators are expected to provide, and are expected to share with each other. - 1. The followin...

AI summary This document outlines the data requirements for Reliability Coordinators, Balancing Authorities, and Transmission Operators, specifying real-time updates on transmission status, generator output, operating reserves, interchange schedules, and area control error. It emphasizes shared operational information critical to maintaining electric system reliability.

Standard TOP-005-1.1 — Operational Reliability Information - 2.5. New facilities in place. - 2.6. New or degraded special protection systems. - 2.7. Emergency operating procedures in effect. - 2.8. Severe weather, fire, or earthquake. - 2....

AI summary The document outlines factors affecting operational reliability, including new facilities, special protection systems, emergency procedures, and events like severe weather or sabotage. It was approved by the Board of Trustees on October 29, 2008.

2. Levels of Non-Compliance for Reliability Coordinators: - 2.1. Level 1: Not applicable. - 2.2. Level 2: Not applicable. - 2.3. Level 3: Not applicable. - 2.4. Level 4: There shall be a separate Level 4 non-compliance, for every one of th...

AI summary The document outlines non-compliance levels for reliability coordinators, focusing on Level 4 violations. These include failing to monitor operational items, lacking specified information, not communicating deviations to operators, and not monitoring system frequency. The Board of Trustees adopted these standards in 2006 with an effective date of 2007.

4. Levels of Non-Compliance for Transmission Operators and Balancing Authorities: - 4.1. Level 1: Not applicable. - 4.2. Level 2: Not applicable. - 4.3. Level 3: Not applicable. - 4.4. Level 4: There shall be a separate Level 4 non-complia...

AI summary Level 4 non-compliance involves specific violations, including failure to inform Reliability Coordinators, monitor required items, track system frequency, and address operating deviations. These breaches require corrective actions and adherence to reliability standards.

Standard TOP-007-0 — Reporting SOL and IROL Violations

AI summary The document outlines the regulatory requirements for reporting violations of System Operating Limits (SOL) and Interconnection Reliability Operating Limits (IROL) under Standard TOP-007-0. It emphasizes the role of the Nova Scotia Utility and Review Board (NSUARB) and Nova Scotia Power Incorporated (NSPI) in ensuring compliance with reliability standards set by the North American Electric Reliability Corporation (NERC).

A. Introduction 1. Title: Reporting System Operating Limit (SOL) and Interconnection Reliability Operating Limit (IROL) Violations 2. Number: TOP-007-0

AI summary The document introduces a regulatory standard (TOP-007-0) requiring the reporting of violations related to System Operating Limits (SOL) and Interconnection Reliability Operating Limits (IROL).

3. Purpose: This standard ensures SOL and IROL violations are being reported to the Reliability Coordinator so that the Reliability Coordinator may evaluate actions being taken and direct additional corrective actions as needed.

AI summary This standard mandates the reporting of System Operating Limit (SOL) and Interconnection Reliability Operating Limit (IROL) violations to the Reliability Coordinator, enabling evaluation of corrective actions and ensuring reliability in the electricity grid.

B. Requirements - R1. A Transmission Operator shall inform its Reliability Coordinator when an IROL or SOL has been exceeded and the actions being taken to return the system to within limits. - R2. Following a Contingency or other event th...

AI summary Transmission Operators must notify Reliability Coordinators of IROL/SOL violations and take corrective actions within 30 minutes, including load shedding if necessary. Reliability Coordinators must evaluate and direct actions to resolve violations if initial measures are insufficient.

C. Measures - M1. Evidence that the Transmission Operator informed the Reliability Coordinator when an IROL or SOL was exceeded and the actions taken to return the system to within limits. - M2. Evidence that the Transmission Operator retu...

AI summary The measures require evidence that the Transmission Operator notified the Reliability Coordinator when IROL or SOL limits were exceeded, returned the system to compliance within 30 minutes, and that the Reliability Coordinator evaluated corrective actions. These focus on system reliability and operational compliance under regulatory standards.

1. Compliance Monitoring Process

AI summary The section outlines the compliance monitoring process, likely involving regulatory oversight and adherence to standards such as CIP and FAC. It may discuss roles of entities like NSUARB and NSPI in ensuring compliance with reliability and operational protocols.

1.1. Compliance Monitoring Responsibility The Reliability Coordinator shall report any IROL violation exceeding 30 minutes to the Regional Reliability Organization and NERC within 72 hours. Each Regional Reliability Organization shall repo...

AI summary The Reliability Coordinator must report IROL violations exceeding 30 minutes to the RRO and NERC within 72 hours. RROs must report these violations to NERC via their compliance process. SOL violations that become IROL violations due to system changes also require reporting. Adopted by NERC in 2005.

2. Levels of Non-Compliance - 2.1. The Transmission Operator did not inform the Reliability Coordinator of an IROL or an SOL that has become an IROL because of changed system conditions, and the actions they are taking to return the system...

AI summary The document outlines three levels of non-compliance related to transmission operations and reliability coordination. It highlights failures in communication and corrective actions by the Transmission Operator and Reliability Coordinator, leading to violations of system operating limits.

Table 1-TOP-007-0 IROL and SOL Reporting Levels of Non-Compliance Percentage by which IROL or SOL that has become an IROL is exceeded Limit exceeded for more than 30 minutes, up to 35 minutes. Limit exceeded for more than 35 minutes, up to...

AI summary The table outlines the levels of non-compliance based on the percentage by which IROL or SOL limits are exceeded, with different time intervals and corresponding compliance levels. This is relevant to reliability standards in the electricity grid.

2. Levels of Non-Compliance for Transmission Operator - 2.1. Level 1: Not applicable. - 2.2. Level 2: Disconnected an overloaded facility as specified in R3 but did not notify its Reliability Coordinator and all neighboring Transmission Op...

AI summary The document outlines four levels of non-compliance for a Transmission Operator, detailing specific violations related to handling overloaded facilities, notifying reliability coordinators, and mitigating system operating limit (SOL) and interconnection reliability operating limit (IROL) violations. Level 4 includes multiple violations, such as failing to use analysis tools to determine SOL causes or mitigate violations.

Table I. Transmission System Standards – Normal and Emergency Conditions Category Contingencies Syst System Limits or Impacts caregory Initiating Event(s) and Contingency Element(s) System Stable and both Thermal and Voltage Limits within...

AI summary This table outlines transmission system standards for normal and emergency conditions, detailing system stability, loss of demand, curtailed firm transfers, and cascading outages under various contingency categories. It includes system limits, impacts, and conditions under which the system remains stable.

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 p...

AI summary The Planning Authority and Transmission Planner must annually assess their portion of the interconnected transmission system to ensure it can meet projected customer demands and Firm Transmission Services under Category B contingencies. Assessments must cover near-term (years 1-5) and long-term (years 6-10) horizons, supported by studies/simulations accepted by Regional Reliability Organizations.

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...

AI summary The Planning Authority and Transmission Planner must maintain valid assessment and corrective plans per Reliability Standards TPL-002-0_R1 and TPL-002-0_R2, and document results of reliability assessments as required by TPL-002-0_R3.

Version History Version Date Action Change Tracking 0 April 1, 2005 Effective Date New 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 Ame...

AI summary The text provides a version history of a document, including dates, actions, and changes made to the document. It also includes a table outlining different categories of contingencies, system limits, and impacts, such as loss of demand, curtailed firm transfers, and cascading outages.

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-...

AI summary NERC received interpretation requests from Midwest ISO and Ameren regarding identical requirements (R1.3.2 and R1.3.12) in TPL-002-0 and TPL-003-0. These requirements pertain to transmission planning and reliability standards, with the requests seeking clarification on their application.

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 pe...

AI summary TPL-002-0 mandates that Planning Authority and Transmission Planner assessments must include studies/simulations addressing system performance under single contingencies (Category B of Table 1), with approval from Regional Reliability Organizations (RROs). Requirements include analyzing critical system conditions, study years, and planned outages of bulk electric equipment.

TPL-003-0: [To be valid, the Planning Authority and Transmission Planner assessments shall:] - R1.3 Be supported by a current or past study and/or system simulation testing that addresses each of the following categories, showing system pe...

AI summary The Planning Authority and Transmission Planner assessments must be supported by studies or simulations addressing multiple contingencies (Category C of Table 1), including critical system conditions, planned outages of bulk electric equipment, and acceptable approval from Regional Reliability Organizations.

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 wit...

AI summary Ameren seeks clarification on the definition of 'critical system conditions' in TPL-002-0 and TPL-003-0 R1.3.2, specifically whether compliance requires modeling multiple contingent generating unit outages as part of generation dispatch scenarios.

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...

AI summary MISO requests clarification on whether TPL-002-0 and TPL-003-0 require specific dispatch methods beyond those representing firm demand and transmission service commitments in contingency modeling. It also asks if probabilistically based dispatch patterns, including generation deficiency scenarios, should be analyzed under Category B contingency conditions.

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 wi...

AI summary The NERC Planning Committee interpreted TPL-002-0 and TPL-003-0 R1.3.2, clarifying that Planning Coordinators (PCs) have discretion in selecting critical system conditions for modeling. The PC's role includes providing methodologies to Transmission Planners. FERC Order 693 replaced the RRO as Compliance Monitor with the RE, requiring REs to coordinate compliance across regions.

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 specif...

AI summary Ameren seeks clarification on interpreting TPL-002-0 and TPL-003-0 Requirement R1.3.12, specifically whether planned outages must be considered in contingency definitions for Categories B and C. They ask if the system must be operated during planned outages with performance requirements from 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...

AI summary MISO requests clarification on whether 'planned outages' in TPL-002-0 and TPL-003-0 R1.3.12 include unscheduled potential outages or only known/scheduled ones. It also asks if system planning must account for Category C3 n-2 events even if the initial event is a planned base condition, and whether this aligns with NERC's original interpretation.

The following interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.12 was developed by the NERC Planning Committee on March 13, 2008: This provision was not previously interpreted by NERC since its approval by FERC and other regulato...

AI summary The NERC Planning Committee interpreted TPL-002-0 and TPL-003-0 Requirement R1.3.12 on March 13, 2008, clarifying that planned outages (including maintenance) of bulk electric equipment must be included in studies at demand levels requiring such outages. Planned outages are not considered 'contingencies' under NERC standards, necessitating system adjustments in compliance assessments.

1. Compliance Monitoring Process

AI summary The section outlines the compliance monitoring process, likely involving regulatory oversight and adherence to standards such as CIP and FAC. It may discuss roles of entities like NSUARB and NSPI in ensuring compliance with reliability and operational protocols.

Standard TPL-004-0 — System Performance Following Extreme BES Events

AI summary This regulatory proceeding addresses the reliability of the Bulk Electric System (BES) during extreme events, focusing on compliance with Transmission Planning Standard TPL-004-0. The standard outlines requirements for ensuring grid performance and resilience under extreme conditions.

Standard VAR-002-1.1a — Generator Operation for Maintaining Network Voltage Schedules

AI summary This regulatory standard, VAR-002-1.1a, outlines generator operational requirements to maintain network voltage schedules. It is part of Nova Scotia's regulatory framework governed by the NSUARB and involves NSPI as the primary utility. The standard aligns with broader system reliability and voltage regulation objectives.

1. Compliance Monitoring Process

AI summary The section outlines the compliance monitoring process, likely involving regulatory oversight and adherence to standards such as CIP and FAC. It may discuss roles of entities like NSUARB and NSPI in ensuring compliance with reliability and operational protocols.

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...

AI summary The document requests a formal interpretation of NERC's VAR-002-1 standard regarding generator AVR operation modes. It highlights conflicting interpretations: some argue constant power factor/Mvar modes comply with R1/R2, while others insist only constant voltage mode meets requirements. Misinterpretation risks voltage instability and financial penalties.

Glossary of Terms Used in NERC Reliability Standards Updated April 20, 2010

AI summary This document provides a glossary of terms from NERC Reliability Standards, defining key concepts, acronyms, and standards critical to electric system reliability. It includes terms related to cybersecurity, emergency operations, transmission planning, and facility ratings, with updates as of April 20, 2010.

1 See 18 CFR 37.6(b)(1) Continent-wide Term Acronym BOT Approved Date FERC Approved Date Definition Capacity Emergency [Archive] 2/8/2005 3/16/2007 A capacity emergency exists when a Balancing Authority Area's operating capacity, plus firm...

AI summary The text defines key terms related to electric system reliability, including 'Capacity Emergency' and 'Cascading,' providing dates of approval by the Board of Trustees (BOT) and the Federal Energy Regulatory Commission (FERC).

Glossary of Terms Used in NERC Reliability Standards Continent-wide Term Acronym BOT Approved Date FERC Approved Date Definition Distribution Factor [Archive] DF 2/8/2005 3/16/2007 The portion of an Interchange Transaction, typically expre...

AI summary This document provides a glossary of terms used in NERC Reliability Standards, including definitions of acronyms such as DF (Distribution Factor), along with dates of approval by the Board of Trustees (BOT) and the Federal Energy Regulatory Commission (FERC).

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 The ability of supply-side and demand...

AI summary The text provides definitions for terms used in ReliabilityFirst Regional Standards, including Resource Adequacy, Net Internal Demand, Peak Period, and Year One, each with specific dates of approval and explanations.

Glossary of Terms Used in NERC Reliability Standards

AI summary A glossary defining terms from NERC Reliability Standards, including organizations (NERC, FERC), regulatory bodies (NSUARB), utilities (NSPI), and technical standards (CIP, FAC, EOP). Focuses on electric system reliability, cybersecurity, and operational protocols.

Endnotes April 20, 2010 Page 51 of 51 † 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, 200...

AI summary FERC approved WECC's Tier One Reliability Standards in 2007, directing WECC to resolve inconsistencies with NERC's glossary. Replacement standards addressing these issues were filed with FERC in 2009.

N ORTH A MERICAN E LECTRIC R ELIABILITY C OUNCIL Princeton Forrestal Village, 116-390 Village Boulevard, Princeton, New Jersey 08540-5731

AI summary The document identifies the North American Electric Reliability Council (NERC) with its address in Princeton, New Jersey, and references related regulatory standards and organizations.

etermining how to either combine the CIP compliance implementation programs, or at a minimum, operate the CIP compliance implementation programs under a common Senior Manager and governance structure. Following the one year analysis period...

AI summary The document outlines requirements for merging or managing CIP compliance programs post-merger of entities with critical cyber assets. It emphasizes the need for a unified governance structure, clear identification of program components per asset, and a merger plan to avoid technical non-compliance and ensure Bulk Power System reliability.

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 appl...

AI summary Measure M1 mandates the Interchange Authority to provide evidence of distributing Arranged Interchange information to all involved reliability entities within specified timeframes, ensuring transparency and coordination in interchange processes.

Timing Requirements for all Interconnections except WECC Inte uest for rchange omitted change Timeline with M bility-Related Respons Α В C D If Arranged Interchange (RFI) 2 is Submitted IA Assigned Time Classification IA Makes Initial Dist...

AI summary The document outlines timing requirements for interconnections (excluding WECC), specifying deadlines for submitting, distributing, and confirming arranged interchange requests based on submission times relative to ramp start. It details response times for entities like IA, BA, and TSP, ensuring reliability assessments and timely implementation.

Timing Requirements for WECC A В С D If Arranged Interchange (RFI) 3 is Submitted IA Assigned Time Classification IA Makes Initial Distribution of Arranged Interchange BA and TSP Conduct Reliability Assessments IA Compiles and Distributes...

AI summary The document outlines timing requirements for WECC (Western Electricity Coordinating Council) related to arranged interchange (RFI) submissions, including IA distribution timelines, reliability assessments, and confirmed interchange implementation based on submission times relative to the ramp start.

Example of Timing Requirements for WECC

AI summary The document provides an example of timing requirements for the Western Electricity Coordinating Council (WECC), referencing a figure (_page_40_Figure_2.jpeg) that likely illustrates compliance deadlines or procedural timelines related to reliability standards.

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-tim...

AI summary The requirements outline procedures for Balancing Authorities and Transmission Service Providers to respond to On-time, Emergency, and Reliability Adjustment Requests for Interchange (RFI) before the reliability assessment period expires. Key evaluation criteria include energy profile, ramp capability, scheduling path connectivity, and transmission service arrangement validity.

Timing Requirements for all Interconnections except WECC Request for Interchange Submitted Interchange Timeline with Minimum Reliability-Related Response Times Α В С D If Arranged Interchange (RFI) 3 is Submitted IA Assigned Time Classific...

AI summary The document outlines strict timing requirements for interconnection processes outside the WECC, specifying response deadlines for Interchange Authority (IA), Balancing Authority (BA), and Transmission Service Providers (TSP) based on submission times relative to ramp start. Deadlines range from 1 minute to 2 hours, with penalties for late submissions.

Timing Requirements for all Interconnections except WECC Request for Interchange Submitted hange Timeline with M pility-Related Respons A В С D If Arranged Interchange (RFI) 2 is Submitted IA Assigned Time Classification IA Makes Initial D...

AI summary The document outlines strict timelines for handling interchange requests based on submission times relative to the ramp start. Time classifications (On-time, Late, ATF) dictate deadlines for actions like initial distribution, reliability assessments, and confirmed interchange implementation, with response windows ranging from 10 minutes to 2 hours depending on submission timing.

Timing Requirements for WECC Α В С D If Arranged Interchange (RFI) 3 is Submitted IA Assigned Time Classification IA Makes Initial Distribution of Arranged Interchange BA and TSP Conduct Reliability Assessments IA Compiles and Distributes...

AI summary The document outlines timing requirements for WECC related to arranged interchange (RFI) submissions, including classifications such as ATF, Late, and On-time, along with specific timeframes for various actions by the IA, BA, and TSP.

2.Violation Severity Levels R # Lo V S L w er M de V S L te o ra H ig h V S L Se V S L ve re R 1. / N A / N A / N A T he Tr iss ion O d i d to an sm p er a r lec f he i f ie d t s t o t no e ne o s p ec ho do log ies fo h A T C t m e r e a...

AI summary The document outlines violation severity levels, with a focus on high and severe violation levels. It includes details about transmission operations and performance issues, indicating potential regulatory concerns related to compliance and operational standards.

R6.2. Be allocated as follows: - For ATC Paths, based on the expected import paths or source regions provided by Load-Serving Entities or Resource Planners - For Flowgates, based on the expected import paths or source regions provided by L...

AI summary Regulatory rules (R6.2–R12) outline CBM allocation, notification timelines, data sharing, and emergency use conditions. CBM must be allocated based on import paths, with 31-day notification requirements for Load-Serving Entities and Resource Planners. Data sharing and approval processes are mandated, with CBM use restricted to NERC Energy Emergency Alerts (EEA 2+). Violation risk factors and time horizons are specified for compliance.

T he C B M in in in ta m a g iss io Se ic i de 's Tr Pr an sm n rv e ov r C B M I D do d dr f t a es n o es s o ne o he b ire t ts su re q u m en O R T he C B M in in in ta m a g Tr iss io Se ic Pr i de 's an sm n rv e ov r C B M I D do d...

AI summary The text discusses the Capacity Benefit Margin (CBM) and its implementation as outlined in the Capacity Benefit Margin Implementation Document (CBMID), focusing on its role in transmission planning and reliability standards, referencing the North American Electric Reliability Corporation (NERC) and other related terms.

Where: NITSNF is the non-firm capacity set aside for Network Integration Transmission Service (i.e., secondary service , including the capacity used to serve bundled load within the Transmission Service Provider's area with external source...

AI summary The text defines non-firm capacity categories (NITSNF, GFNF, PTPNF, OSNF) and provides a formula for calculating firm ATC, incorporating factors like ETC_F, CBM, TRM, and adjustments for postbacks and counterflows.

R1.1.1. Includes at least: - R1.1.1.1. The Transmission Operator area. Equivalent representation of radial lines and facilities 161kV or below is allowed. - R1.1.1.2. All Transmission Operator areas contiguous with its own Transmission Ope...

AI summary The text outlines technical requirements for modeling transmission systems, including equivalent representation of radial lines, in-service system elements, generation modeling above 20 MVA, and phase shifter settings. It emphasizes modeling standards for transmission operator areas and interconnection points.

Where ATCF is the firm Available Transfer Capability for the ATC Path for that period. TTC is the Total Transfer Capability of the ATC Path for that period. ETCF is the sum of existing firm commitments for the ATC Path during that period....

AI summary The text defines key terms related to transmission capacity calculations, including Available Transfer Capability (ATCF), Total Transfer Capability (TTC), and Capacity Benefit Margin (CBM). It outlines an algorithm for computing non-firm ATC (ATCNF) by subtracting commitments, margins, and adjustments from TTC, with specific considerations for postbacks and counterflows.

Where: ATC is the Available Transfer Capability. P is the set of partial Available Transfer Capabilities for all "impacted" Flowgates honored by the Transmission Service Provider; a Flowgate is considered "impacted" by a path if the Distri...

AI summary The text defines key terms related to transmission capacity and flowgate management, including Available Transfer Capability (ATC), partial Available Transfer Capability (PATCn), and distribution factors (DFnp). It explains how Flowgates are deemed 'impacted' based on distribution factors and congestion management procedures used by Transmission Service Providers.

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 set...

AI summary The document outlines violation severity levels for compliance with specific requirements related to relay settings and the management of facilities critical to the Bulk Electric System. It defines criteria for lower, moderate, high, and severe violations under different requirements.

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 methodol...

AI summary The Supplemental Technical Reference Document explains the technical rationale behind a standard, providing methodology examples. It references a 2007 NERC document on relaying loadability ratings, emphasizing that other technically comparable methods are acceptable.

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. -...

AI summary This document outlines a standard for protective relay systems, specifying included functions (e.g., phase distance, overcurrent relays) and excluded systems (e.g., ground fault detection, generator relays). It references NERC Reliability Standards PRC-012 through PRC-017 for Special Protection Systems.

Matrix of Violation Risk Factors for Approval Standard Number Requirement Text of Requirement Violation BAL-001-0.1a R3. Each Balancing Authority providing Overlap Regulation Service shall evaluate Requirement R1 (i.e., Control Performance...

AI summary The document presents a matrix evaluating violation risk factors for approval, focusing on reliability standards for balancing authorities. It outlines requirements under BAL-001-0.1a and BAL-002-0, with varying levels of violation risk (LOWER, HIGH) based on compliance with control performance standards and contingency reserve access.

Matrix of Violation Severity Levels for Approval Standard Number Requirement Number Text of Requirement Lower VSL Moderate VSL High VSL Severe VSL BAL-001-0.1a R3. Each Balancing Authority providing Overlap Regulation Service shall evaluat...

AI summary The document presents a matrix outlining the severity levels of violations related to the provision and receipt of Overlap Regulation Service by Balancing Authorities, referencing specific reliability standards and requirements.

1 2 3 MEMORANDUM OF UNDERSTANDING 4 BETVVEEN 5 NOVA SCOTIA POWER INCORPORATED 6 AND 7 Inc TIIE NORTIIEAST POWER COORDINATING COUNCIL 8 AND 9 TIIE NORTH AMERICAN ELECTRIC RELIABILITY CORPORATION 10 11 12 13 14 15 16 This Memorandum of Under...

AI summary This Memorandum of Understanding (MOU) outlines the collaboration between Nova Scotia Power Incorporated (NSPI), the Northeast Power Coordinating Council (NPCC), and the North American Electric Reliability Corporation (NERC) regarding the approval and implementation of reliability standards in Nova Scotia. It supports a prior MOU between the Nova Scotia Utility and Review Board (NSUARB) and NERC from December 22, 2006.

- NPCC is one of eight Regional Entities responsible for promoting and enhancing the reliability and efficient operation ofthe international, interconnected bulk power system in Northeastern North America. - NPCC is delegated authority fro...

AI summary The document outlines the role of the Northeast Power Coordinating Council (NPCC) in ensuring the reliability and efficient operation of the bulk power system in Northeastern North America. NPCC enforces NERC Reliability Standards in the U.S. and collaborates with Canadian authorities to apply mandatory standards in Canada.

2. Development and Application of NERC Reliabifitv Standards and NPCC Regional RefiabiliJv CriJeria - In accordance with NSP!'s designation as a Registered Entity, NSPI agrees to comply with NERC Reliability Standards and NPCC Regional Rel...

AI summary NSPI agrees to comply with NERC and NPCC reliability standards, which will become mandatory in Nova Scotia upon NSUARB approval. NERC and NPCC will file consolidated proposals by Q2 2010, with NSPI recommending approval or alternative actions to the NSUARB. The process involves stakeholder consultation and timeline coordination.

Stakeholder Participation The signatories anticipate that the NSUARB will require notification to stakeholders of the NERC application and the NPCC application and will provide opportunity for review and comment on the applications by stak...

AI summary The signatories anticipate NSUARB will notify stakeholders of NERC and NPCC applications, requiring stakeholder review and comment. They acknowledge responsibilities to respond to information requests and participate in discovery or hearings if ordered. Key topics include reliability standards, regional criteria, and cost considerations in Nova Scotia.

Notification and Approval of Amendments andlor Additions to NERC Reliability Standards and NPCC Regional Re6abi6ty Criterla The signatories anticipate that there will be ongoing amendments and/or additions made to the NERC Reliability Stan...

AI summary The document outlines a process for approving amendments to NERC and NPCC reliability standards in Nova Scotia. NSPI and NSUARB will be notified of proposed changes, with NSPI providing recommendations for approval. NERC and NPCC must file amendments with NSUARB, which retains authority to approve them before they become mandatory.

Investigations NERC and NPCC, in exercising their respective authority regarding compliance, may investigate alleged violations in Nova Scotia ofReliability Standards or NPCC Regional Reliability Criteria, as appropriate. In order to promo...

AI summary NERC and NPCC collaborate to investigate violations of reliability standards in Nova Scotia, sharing information while maintaining independent outcomes. Their joint efforts aim to enforce NERC Reliability Standards and NPCC Regional Reliability Criteria effectively.

Reporting Requirements NSPI will provide NPCC all information respecting reporting requirements contained in the CMEP for both NERC Reliability Standards and NPCC Regional Reliability Criteria. NSPI will be responsible for providing infonn...

AI summary NSPI is required to report to NPCC under the CMEP framework, covering NERC Reliability Standards and NPCC Regional Reliability Criteria, including routine and event-based reporting obligations.

NERC Compliance Audits NSPI will be subject to compliance audits performed by NPCC related to NERC Reliability Standards and NPCC Regional Reliability aiteria.

AI summary NSPI will undergo compliance audits by NPCC concerning NERC Reliability Standards and NPCC Regional Reliability aiteria, highlighting regulatory oversight of reliability criteria in the electricity sector.

NPCC Regional Reliability Criteria Compliance Audit NSPI will be subject to NPCC Regional Reliability Criteria compliance audits. 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 .-. 31 32 33 34 35 36 37 38...

AI summary NSPI will undergo NPCC Regional Reliability Criteria compliance audits. Points of contact for NERC, NPCC, and NSPI are provided, including names, titles, addresses, and contact information.

July 21,2010 VIA ELECTRONIC FILING Ms. Nancy McNeil Nova Scotia Utility and Review Board 3rd Floor 1601 Lower Water Street Halifax, Nova Scotia B3J 3P6 Re: Nova Scotia Notice of Filing - Application for Approval of Reliability Standards De...

AI summary NERC submitted an application for approval of Reliability Standards to the NSUARB, requesting acceptance of supplemental exhibits (C, E, F, G) related to FERC-approved standards, violation risk factors, and severity levels. NERC seeks NSUARB approval for these materials.

RECEIVE DEC 1 7 2010 December 17, 2010 Nova Scotia Utility and Review Board Nancy McNeil Regulatory Affairs Officer/Clerk Nova Scotia Utility and Review Board 1601 Lower Water Street, 3 rd Floor PO Box 1692, Unit "M" Halifax, NS B3J 3S3 Re...

AI summary The document outlines filings by the Northeast Power Coordinating Council (NPCC) and North American Electric Reliability Corporation (NERC) requesting approval of reliability standards and criteria. Nova Scotia Power Inc. (NSPI) intervened, and the Utility and Review Board (UARB) accepted a timeline for the proceeding, with NSPI submitting recommendations.

Background This matter has arisen as a result of the DARB having signed a Memorandum of Understanding with NERC dated December 22, 2006 wherein the UARB and NERC committed to a process for making NERC Reliability Standards mandatory, and a...

AI summary The document outlines Memoranda of Understanding (MOUs) between DARB, UARB, NERC, NSPI, and NPCC regarding NERC Reliability Standards. NSPI asserts compliance with these standards through audits and maintains its bulk power system infrastructure.

andards. NERC will immediately notify the Board if any jurisdiction remands a proposed reliability standard and will work with stakeholders and all relevant jurisdictions to resolve the issues raised. Upon receiving a request from NERC to...

AI summary The document outlines a process for approving reliability standards, with NERC notifying the Board of remands and collaborating on resolutions. The Board may adopt or remand standards after review. NSPI recommends implementing this process for NPCC and NERC standards, suggesting a change to include FERC approval in the U.S. process.

2010 Audit NPCC performed a compliance audit on NSPI in two stages in 2010. The first stage was completed from August 9 to the 13, 2010 and was an audit of 43 Reliability Standards and 349 of their requirements/sub-requirements. Based on t...

AI summary In 2010, NPCC conducted a two-stage compliance audit of NSPI. The first stage found NSPI compliant with 42 of 43 reliability standards, with 1 standard and 47 requirements not applicable. The second stage identified compliance with all eight CIP standards except for a possible violation in CIP-004 R4 related to access revocation after an employee's death. The final audit report remained unpublished.

1. CI 38266 - 2010 Protection Upgrades In 2008, NPCC approved new criteria (Criteria Document A-IO) for determining whether a substation bus is categorized as bulk power. The criterion is used to identify substation busses that, if a fault...

AI summary NPCC approved criteria in 2008 to identify bulk power substation buses requiring redundancy. The 79N-Hopewell substation met these criteria but lacked fully redundant protection, control, and communication schemes.

2. CI 38182 - 2010 Backup Control Centre NERC requires all Transmission Operators and Balancing Authorities have a back-up control strategy in place by Ql of2012. NSPI's requirement for a Back-Up Control Centre (BCC) originated from a busi...

AI summary NERC requires backup control strategies by Q1 2012. NSPI's existing BCC at Scotia Square relies on RAL, a single point of failure, violating NERC standards. Two 2011 items aim to address NERC and NPCC compliance.

1. CI 40231 - 2011 Protections Upgrades at Lakeside In 2008, NPCC approved new criteria (Criteria Document A-IO) for determining whether a substation bus is categorized as bulk power. The criterion is used to identify substation busses tha...

AI summary NPCC established criteria for bulk power substation buses in 2008, requiring full redundancy for identified stations. The 103H-Lakeside substation meets bulk power criteria but lacks fully redundant protection, control, and communication systems.

2. CI 40233 - 2011 Protections Upgrades at Tufts Cove In 2008, NPCC approved new criteria (Criteria Document A-IO) for determining whether a substation bus is categorized as bulk power. The criteria is used to identify substation busses th...

AI summary The NPCC established criteria requiring upgrades to the Tufts Cove substation bus for redundancy. NSPI states that UARB approval of NERC and NPCC standards would not automatically approve capital expenditures, which would still require regulatory review under ACE guidelines.

Emerging Issues There are two issues which are currently under consideration in North America which could have a material effect on reliability regulation in Nova Scotia; 1) the Bulk-Electric System definition and the 2) the ongoing expans...

AI summary The document highlights two emerging issues in North America—Bulk-Electric System definition and CIP standards expansion—that may impact Nova Scotia's reliability regulation. NSPI submits comments for DARB's consideration without requesting action.

Bulk Electric System Definition Within the NPCC, the definition of Bulk Electric System (BES) has been focused on system elements which could potentially affect system reliability in other jurisdictions. For Nova Scotia, this has been·gene...

AI summary The NPCC defines BES as 345 kV and 230 kV systems, but FERC proposes a 100 kV 'bright-line' standard. Canadian NPCC members, including NSPI, oppose this, citing potential cost increases without reliability benefits. NSPI warns that adopting the standard may require proposing an alternative approach in Nova Scotia.

CIP Standard Expansion Due in large part to concern with potential criminal attacks on the North American bulk power system, a major focus of reliability standard changes has been a shift towards increasingly stringent CIP Standards. These...

AI summary The expansion of CIP Standards, driven by concerns over cyber threats to the North American bulk power system, may increase costs for NSPI. Changes to CIP-002 could expand the scope of critical cyber assets, requiring additional physical and electronic security measures. NSPI will monitor developments and consider alternatives to NERC/NPCC measures.

Recommendation NSPI recommends that the UARB approve the NERC Reliability Standards as requested in its application of June 30, 2010 and the NPCC Reliability Criteria as requested in its application of June 29, 2010. NERC has also requeste...

AI summary NSPI recommends the UARB approve NERC and NPCC reliability standards but opposes approval of VRFs and VSLs, arguing the UARB can independently assess compliance impacts without formal approval. NSPI emphasizes the UARB's discretion in evaluating reliability violations.

Memorandum of Understanding between Nova Scotia Utility and Review Board and North American Electric Reliability Corporation

AI summary The Memorandum of Understanding outlines collaboration between Nova Scotia's utility regulator and NERC, focusing on regulatory compliance, reliability standards, and joint initiatives to ensure grid stability and adherence to reliability protocols.

General Provisions This Memorandum of Understanding (MOU) between the Nova Scotia Utility and Review Board (Board) and the North American Electric Reliability Corporation (NERC) reflects the desire for a continuing and cooperative relatio'...

AI summary This Memorandum of Understanding (MOU) establishes a cooperative relationship between the Nova Scotia Utility and Review Board (UARB) and NERC to enhance North American bulk power system reliability. It outlines the UARB's regulatory authority under the Nova Scotia Public Utilities Act and NERC's role in developing reliability standards, while clarifying the MOU's non-enforceable nature and mutual expectations regarding standard enforcement and cost allocation.

Development of an Electric Reliability Organization The parties understand that NERC has been certified by the U-S_ Federal Energy Regulatory Commission as the "electric reliability organization" (ERO) under U.S. legislation. NERC agrees t...

AI summary NERC is certified by FERC as the Electric Reliability Organization (ERO) under U.S. legislation. NERC agrees to consult with the Board on bylaw amendments to address Canadian and provincial issues, reflecting the international nature of the North American bulk electric system.

Development of Reliability Standards NERC and the Board acknowledge the importance of the active pclliicipation of electricity sector participants from the Province in NERCls standadls development process. NERC commits to notify the Board...

AI summary NERC and the Board outline a collaborative process for developing reliability standards, including NERC's obligation to notify the Board of milestones, file proposed standards, and coordinate with other jurisdictions. The Board may adopt, remand, or separately adopt standards based on public interest considerations.

Compliance The parties understand that, once the Board approves a reliability :standard I compliance with the reliability ~tandard will be mandatory in Nova Scotia. The Board may enforce approved reliability standards directly. The palties...

AI summary The Board enforces reliability standards in Nova Scotia, with NERC providing compliance information. Parties collaborate on reliability risk assessments, and NERC will report on audits, evaluations, and disturbances. The Board retains authority over penalty determination.

13 2. Development and Application of NERC Reliability Standards and NPCC Regional Reliability 14 Criteria 15 - 16 In accordance with NSPI's designation as a Registered Entity, NSPI agrees to comply with NERC 17 Reliability Standards and NP...

AI summary NSPI agrees to comply with NERC and NPCC reliability standards and criteria. Upon NSUARB approval, these will be mandatory in Nova Scotia. NERC and NPCC will submit consolidated filings for NSUARB approval, including all approved standards and criteria.

Responsibilities and Timeline - 25 NERC and NPCC shall endeavour to file the NERC Reliability Standards and NPCC Regional Reliability - 26 Criteria, for approval, with the Board by no later than the end of Q2 2010. In this and subsequent f...

AI summary NERC and NPCC must file reliability standards with the NSUARB by Q2 2010, with NSPI reviewing and recommending actions such as approval, requesting information, or remanding. NSPI will consult NERC/NPCC and file its recommendation by year-end, proposing a timeline for NSUARB approval.

Stakeholder Participation The signatories anticipate that the NSUARB will require notification to stakeholders of the NERC application and the NPCC application and will provide opportunity for review and comment on the applications by stak...

AI summary The NSUARB may require stakeholder notification and review of NERC and NPCC applications, potentially including discovery and hearings. Signatories agree to comply with NSUARB timelines and respond to information requests, with NSPI focusing on Nova Scotia-specific cost considerations.

Notification and Approval of Amendments and/or Additions to NERC Reliability Standards and NPCC Regional Reliability Criteria The signatories anticipate that there will be ongoing amendments and/or additions made to the NERC Reliability St...

AI summary The document outlines a process for approving amendments to NERC Reliability Standards and NPCC Regional Reliability Criteria in Nova Scotia. NERC and NPCC must notify NSUARB and NSPI of proposed changes, with NSPI providing recommendations for approval. This ensures alignment with reliability requirements before implementation.

Investigations NERC and NPCC, in exercising their respective authority regarding compliance, may investigate alleged violations in Nova Scotia of Reliability Standards or NPCC Regional Reliability Criteria, as appropriate. In order to prom...

AI summary NERC and NPCC may investigate alleged violations of reliability standards in Nova Scotia. They will collaborate on investigations while maintaining independent determinations, sharing information under confidentiality policies.

Reporting Requirements NSPI will provide NPCC all information respecting reporting requirements contained in the CMEP for both NERC Reliability Standards and NPCC Regional Reliability Criteria. NSPI will be responsible for providing inform...

AI summary NSPI must provide NPCC with information on reporting requirements under the CMEP, covering NERC Reliability Standards and NPCC Regional Reliability Criteria. This includes routine reporting, investigations, and event-based disturbance reporting.

NERC Reliability Standards and NPCC Regional Reliability Criteria (NSUARB NERC-R-10) NSPI Responses to UARB Information Requests

AI summary The document outlines Nova Scotia Power Inc.'s (NSPI) responses to the Utility and Review Board (UARB) information requests regarding compliance with NERC Reliability Standards and NPCC Regional Reliability Criteria under NSUARB NERC-R-10. It focuses on regulatory compliance and reliability criteria adherence.

13 At this time, NSPI is aware of draft standards which if approved could result in additional - 14 upgrades for reliability of the bulk electric system. Two emerging issues were raised in NSPI's - 15 filing dated December 17, 2010, as exa...

AI summary NSPI is aware of draft standards that could require upgrades to the bulk electric system. Specific projects have not yet been identified as the standards are still under development. NSPI participates in NPCC to address cost implications and other concerns related to new standards. Future capital submissions will include projects justified by these standards.

Response to IR-l: With respect to Violation Risk Factors and Violation Severity Levels, NERC respectfully requests the approval of the referenced: (1) Exhibit F - the associated Violation Risk Factors (VRF); and (2) Exhibit G - the associa...

AI summary NERC requests NSUARB approval of its Violation Risk Factors (VRF) and Violation Severity Levels (VSL) exhibits, emphasizing their role in evaluating reliability standard violations. NERC advocates for quarterly NSUARB reviews of reliability standards post-filing, arguing annual reviews would delay enforcement and undermine reliability. The response includes details on Canadian provincial adoption of reliability standards.

A Summary of Canadian Provincial Adoption of Reliability Standards Framework

AI summary This document summarizes the adoption of reliability standards frameworks by Canadian provinces, referencing the North American Electric Reliability Corporation (NERC) and the Nova Scotia Utility and Review Board (NSUARB). The content includes visual elements but lacks detailed textual analysis.

A Summary of Canadian Provincial Adoption of Reliability Standards Framework This document was prepared by the North American Electric Reliability Corporation (NERC) in consultation with the various Canadian and Provincial jurisdictions ba...

AI summary This document, prepared by NERC in consultation with Canadian provinces, outlines the adoption of reliability standards frameworks. It serves informational purposes only, with Ric Cameron identified as the contact for corrections. The content reflects NERC's understanding of provincial regulatory frameworks.

es ofthe Alberta Commission and the Market Surveillance Administrator (MSA). Specified penalties for violations ofReliability Standards were adopted by the Alberta Commission, effective November 2010. The AESO established the AESO Reliabil...

AI summary Alberta's regulatory framework for reliability standards includes penalties enforced by the Alberta Commission, the AESO Reliability Committee (ARC), and a compliance monitoring program. Reliability Standards are reviewed and approved by the Alberta Commission, with 69 NERC standards either approved or rejected. The AESO revised its Work Plan in 2010 to adopt a risk-based prioritization approach. Alberta entities are excluded from the NERC Compliance Registry but maintain participation through negotiated agreements.

British Columbia: The 2007 provincial Energy Plan committed British Columbia (BC) to "ensure that the province remains consistent with North American transmission reliability standards." With the implementation ofthe Utilities Commission A...

AI summary British Columbia's 2007 Energy Plan aligned with North American reliability standards. The 2009 Utilities Commission Amendment Act mandates reliability standards, designates NERC and WECC as standard-making bodies, and requires the BCUC to review standards' impacts. The BCUC must assess reliability, cost, and suitability of standards for BC, reporting publicly.

Manitoba: Manitoba Hydro is currently required to comply with NERC Reliability Standards through its membership in the Midwest Reliability Organization (MRO) and its membership in NERC, subject to exceptions based on provincial law. Pursua...

AI summary Manitoba Hydro must comply with NERC/MRO Reliability Standards under provincial law, with the PUB authorized to enforce violations. Legislative amendments in 2009 established mandatory reliability standards, with regulations expected in 2011 to define compliance processes and fee allocations.

National Energy Board: The National Energy Board (NEB) has statutory responsibility for authorizing the construction and operation ofinternational power lines (IPL) and designated interprovincial power lines and approving electric exports...

AI summary The National Energy Board (NEB) oversees international and interprovincial power lines under its legislative framework, but lacks authority to levy financial penalties or approve NERC Reliability Standards. The NEB collaborates with NERC via a 2006 MOU and is pursuing mandatory Reliability Standards for IPLs through regulation-making.

New Brunswick: The Electricity Act in New Brunswick established the New Brunswick System Operator (NBSO) on October 1,2004. NBSO is responsible to direct the operation ofthe transmission grid, to maintain the adequacy and reliability ofthe...

AI summary New Brunswick's Electricity Act established the New Brunswick System Operator (NBSO) in 2004 to manage the transmission grid and ensure system reliability. The Public Utilities Board was replaced by the Energy and Utilities Board (EUB). NERC Reliability Standards are enforced through wholesale market rules administered by NBSO, with compliance required for market participants.

Nova Scotia: The Nova Scotia Utility and Review Board (NSUARB) exercises general supervision over all electric utilities operating as public utilities within the Province ofNova Scotia, pursuant to the Nova Scotia Public Utilities Act. In...

AI summary The NSUARB oversees Nova Scotia's electric utilities under the Public Utilities Act, collaborating with NERC on reliability standards via a 2006 MOU. NSPI, as an NPCC member, adheres to NERC standards. The NSUARB may adopt or remand standards, with compliance mandatory in Nova Scotia. NERC provides current standards to the NSUARB, with final approval processes expected by mid-2011.

Ontario: The Electricity Act, 1998 (Ontario) established the Independent Electricity System Operator (IESO). The IESO is responsible for managing Ontario's bulk electric system and operating the wholesale electricity market. The Electricit...

AI summary Ontario's Electricity Act, 1998 established the IESO and Ontario Power Authority. NERC Reliability Standards are enforced via wholesale market rules, with compliance required for licenses from the Ontario Energy Board. Bill 44 (2008) grants the Board authority to review, remand, or revoke NERC standards post-May 14, 2008.

NERC Responds to Nova Scotia Power Inc.'s January 20, 2011 Interrogatories Regarding the June 30, 2010 Filing Concerning the NERC Reliability Standards and NPCC Regional Reliability Criteria (NSUARB NERC-R-I0) North American Electric Relia...

AI summary NERC responds to Nova Scotia Power Inc.'s interrogatories regarding the adoption of NERC reliability standards in Canadian provinces and the U.S. approval process for new standards. The response references an attached summary document on provincial adoption and addresses the standard approval process in the United States.

Response to IR-5: 23 24 (a) A Compliance Application Notice (CAN) provides compliance ~UJ,","u.J,J."'''' applies broadly. The target audience for each CAN is identified in the Primary Interest Group section ofthe CAN. 27 28 29 26 (b) No. N...

AI summary NERC clarifies that its Compliance Application Notices (CANs) do not require regulatory approval, do not establish new reliability standards, and compliance is determined by NERC's existing standards. NERC Alerts require acknowledgment but not UARB approval, with UARB-approved standards taking precedence in conflicts. Compliance failures under NERC Alerts are subject to enforcement by NSUARB.

Response to IR-6: (a) NERC Alerts apply to users, owners, or operators of the bulk power system. When NERC determines it is necessary to place the industry or segments of the industry on formal notice of its findings, analyses, and recomme...

AI summary NERC Alerts apply to bulk power system users and operators, providing non-enforceable guidance to NERC-registered entities. NERC notifies FERC and others but not NSUARB, stating Alerts align with approved reliability standards and do not require NSUARB approval.

5 Response to IR-IO: 4 6 7 NERC does not anticipate having a direct role in an NSPI capital application proceeding. NERC 8 may provide information as requested. North American Electric Reliability Corporation (NERC) Responds to Nova Scotia...

AI summary NERC clarifies it has no direct role in NSPI's capital application proceeding but may provide information if requested. The response addresses NERC's position on compliance obligations if Nova Scotia applies less stringent interpretations of reliability standards compared to the U.S.

5 Response to IR-ll: 6 - 7 The Reliability Standards as approved by the NSUARB will be mandatory and enforceable in - 8 Nova Scotia. Compliance activities in Nova Scotia will be under the direction and control ofthe - 9 NSUARB. Name ofResp...

AI summary NERC responds to Nova Scotia Power Inc.'s interrogatories regarding NERC Reliability Standards and NPCC Regional Reliability Criteria. It confirms NSUARB's authority to enforce reliability standards in Nova Scotia and clarifies that Regional Reliability Criteria must align with NERC standards. The response also addresses jurisdictional questions about the New Brunswick System Operator.

Response to IR-13: The New Brunswick System Operator (NBSO) serves as the Reliability Coordinator for the Maritime Provinces of Nova Scotia, New Brunswick and Prince Edward Island in Canada and northern Maine in the United States. No issue...

AI summary The New Brunswick System Operator (NBSO) serves as the Reliability Coordinator for the Maritime Provinces and northern Maine. NERC states that jurisdictional consultations would be required on a case-by-case basis due to sovereignty concerns. The response addresses IR-13 regarding NERC's reliability standards and NPCC criteria, with David Cook of NERC as the respondent.

andards. NERC will immediately notify the Board if any jurisdiction remands a proposed reliability standard and will work with stakeholders and all relevant jurisdictions to resolve the issues raised. Upon receiving a request from NERC to...

AI summary NERC outlines the process for amending reliability standards in Nova Scotia, stating that amendments follow the same approval pathway as new standards, requiring NSUARB consideration and adoption. The NSUARB must approve any revised or new standards before they take effect, with effectiveness governed by the standard's Effective Date section or NSUARB determination.

A Summary of Canadian Provincial Adoption of Reliability Standards Framework This document was prepared by the North American Electric Reliability Corporation (NERC) in consultation with the various Canadian and Provincialjurisdictions bas...

AI summary The North American Electric Reliability Corporation (NERC) prepared this informational document summarizing Canadian provincial adoption of reliability standards frameworks. It outlines NERC's understanding of regulatory and standards frameworks in consultation with Canadian jurisdictions, emphasizing that the materials are provided without warranty and contact details for Ric Cameron are included for feedback.

es ofthe Alberta Commission and the Market Surveillance Administrator (MSA). Specified penalties for violations ofReliability Standards were adopted by the Alberta Commission, effective November 2010. The AESO established the AESO Reliabil...

AI summary Alberta's regulatory framework for reliability standards involves the Alberta Commission, AESO, and MSA. The AESO established the ARC for stakeholder input on reliability matters, reviews NERC standards with amendments for Alberta's system, and implements a compliance monitoring program. Alberta uses a revised risk-based work plan for reliability standards, diverging from the NERC Functional Model.

British Columbia: The 2007 provincial Energy Plan committed British Columbia (BC) to "ensure that the province remains consistent with North American transmission reliability standards." With the implementation ofthe Utilities Commission A...

AI summary British Columbia's 2007 Energy Plan aligned with North American transmission reliability standards. The 2009 Utilities Commission Amendment Act granted BCUC authority to adopt reliability standards, evaluating public interest and impacts. NERC and WECC are recognized as standard-making bodies, with BCTC (now BC Hydro) required to review standards and report to BCUC.

Manitoba: Manitoba Hydro is currently required to comply with NERC Reliability Standards through its membership in the Midwest Reliability Organization (MRO) and its membership in NERC, subject to exceptions based on provincial law. Pursua...

AI summary Manitoba Hydro must comply with NERC Reliability Standards via its Midwest Reliability Organization (MRO) membership, subject to provincial law exceptions. The 2004 Order in Council approved this compliance, with the 2009 Manitoba Hydro Act establishing enforceable reliability standards and PUB authority for sanctions. Regulations to implement the Act are pending, expected in 2011.

National Energy Board: The National Energy Board (NEB) has statutory responsibility for authorizing the construction and operation ofinternational power lines (IPL) and designated interprovincial power lines and approving electric expolis...

AI summary The National Energy Board (NEB) oversees international power lines (IPL) and interprovincial power lines under its legislative authority. It lacks financial penalty powers and currently lacks formal authority to approve or remand NERC Reliability Standards. The NEB and NERC collaborate via a 2006 MOU, and the NEB seeks to implement mandatory Reliability Standards on IPLs through regulation-making.

New Brunswick: The Electricity Act in New Brunswick established the New Brunswick System Operator (NBSO) on October 1,2004. NBSO is responsible to direct the operation ofthe transmission grid, to maintain the adequacy and reliability ofthe...

AI summary The New Brunswick Electricity Act established the New Brunswick System Operator (NBSO) in 2004 to manage the transmission grid and ensure system reliability. NERC Reliability Standards are enforced via market rules, with compliance tied to licensing. The Energy and Utilities Board (EUB) succeeded the Public Utilities Board as the sector's regulator.

Nova Scotia: The Nova Scotia Utility and Review Board (NSUARB) exercises general supervision over all electric utilities operating as public utilities within the Province ofNova Scotia, pursuant to the Nova Scotia Public Utilities Act. In...

AI summary The NSUARB oversees Nova Scotia's electric utilities under the Public Utilities Act, collaborating with NERC via an MOU to enforce Reliability Standards. NSPI, as an NPCC member, adheres to NERC standards, with NSUARB ensuring compliance and determining penalties. A final approval process for standards is expected by mid-2011.

Ontario: The Electricity Act, 1998 (Ontario) established the Independent Electricity System Operator (IESO). The IESO is responsible for managing Ontario's bulk electric system and operating the wholesale electricity market. The Electricit...

AI summary Ontario's Electricity Act 1998 established the IESO and Ontario Power Authority. NERC Reliability Standards are enforced via IESO market rules, with compliance required for licenses from the Ontario Energy Board. Bill 44 (2008) grants the Board authority to review NERC standards post-May 2008.

North American Electric Reliability Corporation - Reliability Standards; and Northeast Power Coordinating Council, Inc. - Regional Reliability Criteria NERC-R-10/Matter No. M03324

AI summary The document outlines a regulatory proceeding involving NERC's reliability standards and NPCC's regional reliability criteria under Matter No. M03324. It focuses on compliance with reliability requirements for electric power systems in the region.

North American Electric Reliability Corporation – Reliability Standards; and Northeast Power Coordinating Council, Inc. – Regional Reliability Criteria NERC-R-10/Matter No. M03324 Response to Nova Scotia Power, Inc. Date of Response: Febru...

AI summary The response discusses the adoption of Regional Reliability Criteria by provinces within the Northeast Power Coordinating Council (NPCC), noting that Ontario and New Brunswick have adopted them, while other provinces have agreed to abide by NPCC Bylaws and criteria.

Response to Nova Scotia Power, Inc. Date of Response: February 10, 2011 1 Request IR-2: 2 3 Please describe the standard approval process for new Regional Reliability Criteria in the United States. 4 NPCC Response: 5 6 7 8 In NPCC Regional...

AI summary The document outlines the process for developing Regional Reliability Criteria by the Northeast Power Coordinating Council (NPCC) in the United States, emphasizing that these criteria are developed by full members and technical committees and must align with NERC Reliability Standards, without federal oversight.

Response to Nova Scotia Power, Inc. Date of Response: February 10, 2011 - Request IR-3: - Please describe the standard approval process for new Regional Reliability Criteria in each - of the provinces in Canada which have adopted Regional...

AI summary Nova Scotia Power, Inc. requested information on the approval process for Regional Reliability Criteria in Canadian provinces. NPCC responded that approval occurs via its Full Membership and filing with provinces, with automatic adoption in some cases. NPCC is currently focused on Nova Scotia, with Ontario and New Brunswick having adopted the criteria. The response also references ongoing activities in Quebec and mentions enforcement proceedings before the UARB.

ability Standards; and Northeast Power Coordinating Council, Inc. – Regional Reliability Criteria NERC-R-10/Matter No. M03324 Response to Nova Scotia Power, Inc. Date of Response: February 10, 2011 - Request IR-9: - If a less stringent int...

AI summary NPCC asserts that compliance with NERC standards and regional reliability criteria must be uniformly applied across regions, rejecting differential interpretations. It also states no inter-provincial coordination is required for Canadian provinces regarding these standards.

ability Standards; and Northeast Power Coordinating Council, Inc. – Regional Reliability Criteria NERC-R-10/Matter No. M03324 Response to Nova Scotia Power, Inc. Date of Response: February 10, 2011 - 1 Request IR-11: - 2 The New Brunswick...

AI summary NPCC declines to opine on whether UARB has jurisdiction over the New Brunswick System Operator's reliability coordinator obligations to Nova Scotia, stating it is inappropriate for NPCC to provide a position on this matter.

ability Standards; and Northeast Power Coordinating Council, Inc. – Regional Reliability Criteria NERC-R-10/Matter No. M03324 Response to Nova Scotia Power, Inc. Date of Response: February 10, 2011 - Request IR-12: - What process does NPCC...

AI summary The Northeast Power Coordinating Council (NPCC) proposes a process for adopting future Regional Reliability Criteria in Nova Scotia. The process involves filing approved criteria with the UARB, conducting an impact assessment, and allowing public comment before adoption as mandatory and enforceable standards.

IT IS HEREBY ORDERED that: - 1. The Criteria filed by the NPCC are approved. - 2. The Standards and associated Glossary of Terms filed by NERC are approved. - 3. The Standards and the Criteria are mandatory and enforceable for users, owner...

AI summary The Board approves NPCC's Criteria and NERC's Standards and Glossary, making them mandatory for bulk power system participants in Nova Scotia. VRFs and VSLs are accepted for future compliance reviews but not enforceable.

IN THE MATTER OF THE PUBLIC UTILITIES ACT - and - IN THE MATTER OF AN APPLICATION by NORTH AMERICAN ELECTRIC RELIABILITY CORPORATION for approval of its Reliability Standards, and an application by NORTHEAST POWER COORDINATING COUNCIL, INC...

AI summary The Nova Scotia Utility and Review Board considered applications by the North American Electric Reliability Corporation and Northeast Power Coordinating Council, Inc. for approval of reliability standards and regional criteria. Participants included Nova Scotia Power Inc., Quetta Inc., and their legal representatives. The decision was issued on July 20, 2011, with key findings in paragraphs 36-39.

INTRODUCTION - [1] The North American Electric Reliability Corporation ("NERC") is responsible for the development of reliability standards for the electricity grid in North America. The Northeast Power Coordinating Council, Inc. ("NPCC")...

AI summary The document outlines a regulatory proceeding involving NERC, NPCC, and NSPI regarding the approval of reliability standards and criteria in Nova Scotia. The Board requested a timeline for approval, which NSPI proposed and was accepted. No oral hearing was held, and only two interventions were received. The process followed a structured timeline for submissions and responses.

1. Standards and Criteria [20] In response to Board IR-2, NERC provided its report entitled "A Summary of Canadian Provincial Adoption of Reliability Standards Framework". A review of the report indicates widespread acceptance and adoption...

AI summary The Board approved reliability standards after NERC confirmed Canadian provinces' adoption, NPCC outlined regional criteria compliance by members, and NSPI's compliance was verified via audit. No objections were raised to the approval.

ilings, which are the subject of this Decision. The Board has no objection to proceeding in that manner. [27] In its December 17, 2010 letter, NSPI also agreed with this approach, with one exception: NSPI recommends that the UARB implement...

AI summary NSPI recommends that the UARB delay approving NPCC and NERC reliability standards until FERC approval is secured to avoid conflicting compliance requirements and process duplication, given FERC's lack of jurisdiction in Nova Scotia. NSPI notes NERC has filed standards with the UARB but has not yet sought approval.

3. VRFs and VSLs [31] In its application, NERC also requested Board approval of the VRFs and VSLs. In its December 17, 2010 letter to the Board, NSPI disagreed that Board approval of VRFs and VSLs was necessary: NERC has also requested tha...

AI summary NERC requested UARB approval of VRFs and VSLs to assess reliability impacts of violations. NSPI opposed mandatory approval, arguing UARB already has discretion to assess violations. The Board accepted VRFs/VSLs as guidance but agreed formal approval was unnecessary, aligning with NSPI's position while acknowledging their utility in compliance reviews.

Nova Scotia Utility and Review Board North American Electric Reliability Corporation - Reliability Standards, and Northeast Power Coordinating Council, Inc... Regional Reliability Criteria

AI summary The document references the North American Electric Reliability Corporation's reliability standards and the Northeast Power Coordinating Council's regional reliability criteria, highlighting their relevance to regulatory proceedings in Nova Scotia.

NOTICE OF FILINGS Notice is hereby given that the North American Electric Reliability Corporation ("NERC") has filed Reliability Standards and the Northeast Power Coordinating Council, Inc. ("NPCC") has filed Regional Reliability Criteria,...

AI summary The North American Electric Reliability Corporation (NERC) and the Northeast Power Coordinating Council (NPCC) have filed Reliability Standards and Regional Reliability Criteria for approval by the Nova Scotia Utility and Review Board. These standards aim to be mandatory for Nova Scotia's bulk electric power system, operated by Nova Scotia Power Inc. Interested parties may intervene by August 25, 2010, with an order on the timetable to follow.

Nova Scotia Power Inc. c/o Eric Ferguson, CMA Director, Regulatory Affairs 14th Floor, Barrington Tower P. Q. Box 910, Scotia Square Halifax, NS B3J 2W5 Dear Parties: North American Electric Reliability Corporation - Reliability Standards;...

AI summary Nova Scotia Power Inc. (NSPI) commits to filing a recommendation by year-end 2010 regarding NERC and NPCC reliability standards, proposing a timeline for NSUARB approval. The Board requests the proposed timeline by October 15, 2010, with NSPI to coordinate with NERC and NPCC.

VIA E-MAIL October 11, 2010 Mr. Ken M. Montgomery, P. Eng. Senior Advisor Nova Scotia Utility and Review Board 1601 Lower Water St., 3rd Floor PO Box 1692, Unit "M" Halifax, NS B3J 3S3 Canada Dear Mr. Montgomery: Further to your inquiry we...

AI summary The letter discusses how Canadian provinces like Quebec, Manitoba, and Saskatchewan have addressed NERC Reliability Standards. Saskatchewan has a contract to follow NERC standards but has not remanded them, while Quebec and Manitoba have not formally adopted them. All three provinces aim to enhance system reliability without creating inconsistencies.

e a part. They have not to date indicated any issues with standards that would lead them taking action to remand, reject, or significantly alter the NERC Reliability Standards for their jurisdictions. Ontario and New Brunswick are the prov...

AI summary Ontario and New Brunswick have established long-standing processes for adopting NERC Reliability Standards, with regulators retaining final authority. Both provinces have not remanded, rejected, or significantly altered the standards, relying on stakeholder input through system operators.

will apply. Neither province has remanded, rejected, or significantly altered the NERC Reliability Standards, and all standards presently apply. Mr. Ken M. Montgomery, P. Eng. October 11, 2010 Page 2 In British Columbia, the legislated pro...

AI summary British Columbia's process for adopting NERC Reliability Standards involves the BCUC reviewing standards proposed by BCTC (now BC Hydro), considering public input, and adopting them unless a hearing determines otherwise. All 113 NERC/WECC standards were adopted in 2009, with no remands or rejections to date.

ndard being considered by the BCUC, all of which have been recommended for approval by BCTC (BC Hydro). However, to date there have been no remands, rejections or alterations of standards by the BCUC. The Alberta Transmission Regulation 1...

AI summary The text discusses the approval process of reliability standards in Alberta under the Alberta Transmission Regulation, noting BCUC's recommendation of BCTC (BC Hydro) standards. It outlines NERC's recognition by Alberta's Minister of Energy, AESO's role in consulting market participants, and AUC's reliance on AESO recommendations unless intervenors challenge them.

-auc-rules/acts-and-regulations/Documents/EUA/AR86-2007.pdf. & lt;sup>2 See the Current Alberta Standards at: http://www.aeso.ca/rulesprocedures/17006.html. Mr. Ken M. Montgomery, P. Eng. October 11, 2010 Page 3 It should also be noted tha...

AI summary The letter from David N. Cook encourages the NSUARB to adopt mandatory reliability standards, noting Alberta's use of its own classification system instead of NERC's. It emphasizes the importance of enforceable standards for grid reliability and offers further discussion.

NERC Reliability Standards and NPCC Regional Reliability Criteria (NSUARB NERC-R-10) NSPI Information Requests to NERC

AI summary The document outlines information requests by NSPI (Nova Scotia Power Inc.) to NERC (North American Electric Reliability Corporation) regarding compliance with NERC Reliability Standards and NPCC Regional Reliability Criteria under the NSUARB NERC-R-10 proceeding. It focuses on regulatory oversight of grid reliability.

NERC Reliability Standards and NPCC Regional Reliability Criteria (NSUARB NERC-R-10) NSPI Information Requests to NPCC

AI summary The document outlines NSPI's information requests to NPCC regarding compliance with NERC reliability standards and NPCC regional reliability criteria under NSUARB NERC-R-10. It focuses on regulatory oversight of grid reliability and interregional coordination.

NOVA SCOTIA UTILITY AND REVIEW BOARD IN THE MATTER OF: THE PUBLIC UTILITIES ACT - and- IN THE MATTER OF: Filings by North American Electric Reliability Corporation ("NERC") and Northeast Power Coordinating Council Inc. ("NPCC") for approva...

AI summary The Nova Scotia Utility and Review Board seeks comments on the cost impacts of adopting NERC reliability standards and NPCC regional reliability criteria. The request is part of a regulatory proceeding under the Public Utilities Act, with responses due by February 10, 2011.

2011 NSUARB-NERC-R-10 NOVA SCOTIA UTILITY AND REVIEW BOARD IN THE MATTER OF: THE PUBLIC UTILITIES ACT - and- IN THE MATTER OF: Filings by North American Electric Reliability Corporation (UNERC") and Northeast Power Coordinating Council Inc...

AI summary The Nova Scotia Utility and Review Board (NSUARB) requests comments on Nova Scotia Power Inc.'s December 2010 letter, focusing on Violation Risk Factors and Security Levels. It also seeks an update on the adoption of reliability standards in Canadian jurisdictions since October 2010.

- Appendix B A Summary of Canadian Provincial Adoption of Reliability Standards Framework - Appendix C Event Categories and Levels of Analysis (As documented in the ERO Event Analysis Process Manual, October 25, 2010) - Appendix D Chapter...

AI summary This document includes appendices summarizing Canadian provincial adoption of reliability standards, event categories and levels of analysis, and scenario assessments from the NERC Reliability Assessment Guidebook.

Index to NERC Responses to Directives and Other Actions from September 16, 2010 FERC Order on Three-Year ERO Performance Assessment P No. Directive Page 169 Directs NERC to establish criteria it will use to select a subset of events, which...

AI summary The document outlines two directives from the FERC Order dated September 16, 2010, related to the Three-Year ERO Performance Assessment. The first requires NERC to establish selection criteria for events with the highest impact on reliability, while the second mandates collaboration with Regional Entities to ensure timely information reporting to Commission staff.

2. Progress in Implementing Specific NERC Actions Identified in the Assessment Related to Each Area of Discussion Attachment 2 of the Assessment included summaries of stakeholder and Regional Entity comments and recommendations that were r...

AI summary NERC and Regional Entities collaborated to revise agreements and rules following stakeholder feedback, filing revised Delegation Agreements in 2010. Progress on implementing NERC actions across areas like reliability standards, compliance, and event analysis is detailed in Appendix A. NERC filed an informational report with FERC in 2011 and notified Canadian authorities.

A. Response to FERC Discussion of Opportunities for Improvement in Each Program Area In its September 16, 2010 Order, P 12, FERC stated: "The Commission believes that the July 6 Conference provided a useful, high level discussion of topics...

AI summary FERC plans to hold a second Commissioner-led technical conference in 2011 to discuss reliability monitoring, enforcement, compliance, and policy issues related to NERC Reliability Standards. The Commission emphasizes public dialogue to clarify expectations for standard development and will collaborate with NERC and international regulators on agenda development.

tification Committee Program and for Approval of Amended Compliance and Certification Committee Charter , filed March 15, 2010, in Docket No. RR10-8-000; approved by Letter Order issued June 10, 2010. NERC's two most significant statutory...

AI summary NERC outlines its compliance activities with FERC, including updates to reliability standards and procedural rules. It discusses pending filings, stakeholder input processes, and efforts to gain recognition for reliability standards in Canada and Mexico. NERC emphasizes ongoing revisions to its Rules of Procedure and compliance with FERC directives.

1. Development of Reliability Standards In its September 16, 2010 Order, P 67, FERC commended NERC on its efforts and progress in moving the industry from a voluntary to a mandatory Reliability Standards environment, and encouraged NERC to...

AI summary FERC commended NERC's progress in transitioning to mandatory Reliability Standards but highlighted areas for improvement in developing high-quality standards to enhance Bulk-Power System reliability.

a. Quality of Proposed Reliability Standards In its September 16, 2010 Order, P 74, FERC stated: "We remain concerned about the ability of the NERC Reliability Standards Development Process to develop high quality Reliability Standards tha...

AI summary FERC expressed concerns in its 2010 Order P 74 about NERC's Reliability Standards Development Process, emphasizing the need for high-quality standards to ensure Bulk-Power System reliability. FERC urged NERC to hire technical staff to advise its Board of Trustees on proposed standards, ensuring compliance and regulatory oversight.

In P 75, FERC stated: "We share EEI's concerns that ambiguities should be minimized in Reliability Standards to the extent possible. The 95 Commission-approved Reliability Standards contain over 700 requirements and may not clearly account...

AI summary FERC acknowledges EEI's concerns about ambiguities in NERC's Reliability Standards, noting over 700 requirements may not address all compliance scenarios. FERC urges NERC to improve clarity through compliance with prior Commission orders, such as Order No. 693, to enhance standard interpretation.

In P 76, FERC stated: "We encourage NERC, as the entity ultimately responsible for the quality of regional Reliability Standards, to exercise strong oversight to ensure that all regional Reliability Standards developed are necessary and ju...

AI summary FERC urges NERC to ensure regional reliability standards are necessary, justified, and uniformly applied. It emphasizes consistency through continent-wide stakeholder input, NERC technical review, and integration with broader reliability processes to enhance system reliability and best practices.

NERC Response to FERC's Directive – P 76 NERC agrees with the several practices suggested by FERC in P 76 for use during the development of regional Reliability Standards. To this end, the ERO Executive Management Group ("ERO/EMG") has est...

AI summary NERC agrees with FERC's Directive P 76 practices for regional reliability standards. The ERO's Regional Standards Group (RSG) will coordinate standard development, ensure consistency across North America, and disseminate governmental and ERO information to enhance reliability.

b. Time Required to Develop Reliability Standards In its September 16, 2010 Order, P 85, FERC stated: "While we are encouraged by NERC's efforts to revisit its Standards Development Process, we believe that it is important that the Commiss...

AI summary FERC, in Order P 85 (2010), renews a directive requiring NERC to submit quarterly reports for three years, detailing the time required to develop reliability standards, including analyses of project timelines and stages.

d. Prioritization of Reliability Standards Development and Results-Based Standards

AI summary The section discusses the prioritization of reliability standards development and the implementation of results-based standards, focusing on regulatory approaches to ensure grid reliability and performance outcomes.

Prioritization of Reliability Standards Development In its September 16, 2010 Order, P 105, FERC stated: "We believe that improved prioritization of the Reliability Standards development process will alleviate some of the burdens discussed...

AI summary FERC emphasized in Order P 105 (2010) the need for improved prioritization of reliability standards development to reduce burdens while maintaining quality. NERC agreed, proposing a prioritization tool to balance Commission directives, industry inputs, and reliability performance feedback, focusing on high-impact projects for the Bulk-Power System.

Results-Based Standards In its September 16, 2010 Order, P 106, FERC stated: "Now that NERC has obtained some experience with developing and enforcing mandatory Reliability Standards, it is appropriate for it to assess whether the number a...

AI summary FERC's 2010 Order P 106 directed NERC to assess reliability standards' effectiveness in meeting national goals, emphasizing alignment with prior orders (693, 706) and minimizing administrative burdens. The Commission stressed that revised standards must ensure reliability while streamlining requirements.

i. Uniformity In its September 16, 2010 Order, P 118, FERC stated: "[it] strongly supports NERC's efforts to address the uniformity concerns raised by commenters and encourages NERC to continue making improvements in consistency, particula...

AI summary FERC supports NERC's efforts to improve uniformity in compliance, reporting, and data gathering. It emphasizes the need for auditors to prepare thoroughly, consider the burden on entities providing information, and recommends auditor training. FERC also highlights NERC's Regional Operations Group as a means to enhance audit consistency.

ii. Focus Audits on Actual Performance In its September 16, 2010 Order, P 121, FERC stated: "The Commission agrees that the Reliability Standard Audit Worksheets should serve as no more than guidance to the auditor and the audited entity a...

AI summary FERC's 2010 Order P 121 emphasizes that Reliability Standard Audit Worksheets (RSAWs) should guide audits without prescribing rigid compliance methods. NERC is tasked with continuously improving RSAWs through input from Regional Entities and alignment with FERC guidance. Additional compliance tools like CANs and Compliance Bulletins aid entities in understanding standards.

NERC Responses to FERC's Other Action – P 138 The revised Delegation Agreements that were filed on June 21, 2011 establish processes for the collaborative development by NERC and the Regional Entities of performance goals, measures and oth...

AI summary NERC's revised Delegation Agreements (2011) establish collaborative processes with Regional Entities to develop performance metrics aligned with ERO goals, ensuring consistent implementation of the Compliance Monitoring and Enforcement Program (CMEP) and enhancing bulk power system reliability. Metrics focus on transparency, consistency, and organizational performance across program areas.

4. Compliance Registry In its September 16, 2010 Order, P 162, FERC stated: "While NERC indicates that it will consider whether to raise the thresholds set forth in the Registry Criteria, NERC also observes that the registration process is...

AI summary FERC's 2010 Order emphasizes that NERC must justify threshold changes to the Compliance Registry from a reliability perspective. NERC acknowledges the current process works well but is refining registration requirements in alignment with Bulk Electric System definitions and the Ad Hoc Generator Owner/Transmission Owner Report. Revisions to Section 500 and Appendix 5A of the Rules of Procedure were approved by FERC.

i. Improvements to Event Analysis In its September 16, 2010 Order, P 169, FERC stated: "The Commission agrees that NERC cannot timely and effectively analyze every event that occurs and, therefore, must select a subset of events to analyze...

AI summary FERC directed NERC to establish criteria for selecting events with the highest impact on reliability for analysis, focusing on lessons learned. This addresses the impracticality of analyzing every event due to resource constraints and similarity of some events.

In P 170, FERC stated: "In addition, the Commission's staff needs timely access to detailed event information. Absent such information, the Commission's identification of any needed improvements in the Reliability Standards could be delaye...

AI summary FERC emphasizes the need for timely access to detailed event information by its staff to identify improvements in Reliability Standards. It directs NERC to collaborate with Regional Entities to provide such information upon request, including event sequences and diagrams, and mandates NERC to report implementation steps in an informational report.

i. Assessment Reports In its September 16, 2010 Order, P 180, FERC stated: "Scenario Assessments are a critical tool for addressing reliability considerations arising from various emerging issues, including faster renewable resource integr...

AI summary FERC's September 16, 2010 Order P180 emphasizes the importance of scenario assessments for reliability, directing NERC to update protocols for annual scenario analysis to address emerging issues like renewable integration. This ensures timely development of reliability standards.

NERC Response to FERC's Directive – P 180 Scenario assessments provide detailed quantitative and qualitative analyses that "stress" the Reference Case (Long-Term Reliability Assessment ("LTRA") Forecast) and provide a sensitivity analysis...

AI summary NERC incorporates scenario assessments into its reliability evaluations per FERC Directive P 180, enhancing Long-Term Reliability Assessments (LTRA) with sensitivity analyses. The process, outlined in NERC's Guidebook Version 2.1, includes annual scenario analyses and special assessments addressing emerging issues like extreme demand and capacity shortfalls.

ii. Assessment Process Improvement In its September 16, 2010 Order, P 182, FERC stated: "The Commission supports NERC's implementation of its Reliability Assessment Improvement Plan. We recognize that the reliability assessment process has...

AI summary FERC supports NERC's improvements in reliability assessment processes, noting increased transparency and granularity. However, the Reserve Margin Index may not adequately assess systems with high variable resources like wind and solar. FERC directs NERC to develop a new plan addressing capacity and energy in reliability assessments.

NERC Response to FERC's Directive – P 183 NERC strives to provide continuous improvement of reliability assessments and welcomes FERC's suggestions for further improvement. With respect to FERC's specific directive, NERC will implement pro...

AI summary NERC responds to FERC's directive by implementing probabilistic assessments in the Long-Term Reliability Assessment (LTRA), with a voluntary trial phase in 2011 and full implementation in 2012. The Generation and Transmission Reliability Planning Models Task Force (GTRPMTF) developed methods to supplement traditional reliability metrics with probabilistic indices, enhancing energy-based assessments.

iii. Assessment Data Collection and Validation In its September 16, 2010 Order, P 185, FERC stated: "The Commission supports NERC's actions with respect to data collection and validation. Also, we direct NERC to consider establishing perma...

AI summary FERC supports NERC's data collection efforts and directs NERC to establish permanent databases for transmission projects, generation interconnection queue data, and other reliability assessment data. NERC must evaluate feasibility and integrate existing databases into reliability assessments within six months.

NERC Response to FERC's Directive – P 185 In 2009 NERC began a review of its internal data collection and validation processes to fortify its current data analysis system and to improve data validation. NERC agrees with FERC's directive of...

AI summary NERC is enhancing its data collection and validation processes per FERC's directive, including establishing permanent databases for reliability assessments, evaluating transmission and generation data, and developing a web application for data management.

A. Reliability Standards Development - 1. Focus existing reliability standards and reliability standards development on areas that will lead to the greatest improvement in bulk power system reliability. - a. Continue to utilize the annual...

AI summary The document emphasizes prioritizing reliability standards development to enhance bulk power system reliability. NERC utilizes its annual Reliability Standards Development Plan and a Standards Development Project Prioritization Tool, created in response to a 2010 directive, to rank projects based on risks and policy issues.

Appendix 3A — Reliability Standards Development Procedure may be necessary or desirable.] As the result of amendments submitted and approved since the 3-Year ERO Performance Assessment Report was filed with the Commission, the current NERC...

AI summary The NERC Standard Processes Manual outlines procedures for gathering stakeholder feedback during reliability standards development, including mandatory 30-day informal comment periods and public summary responses. This follows amendments approved by the Commission in 2010, emphasizing transparency in the drafting process.

andard drafting team chair, allow NERC staff coordinator to provide a straw man draft reliability standard in advance of the first standard drafting team meeting to optimize effective team discussion. NERC staff has reached an understandin...

AI summary NERC aims to enhance reliability standard development by providing pre-meeting draft standards, engaging trade groups like APPA and NRECA to involve smaller entities, and improving stakeholder communication through subcommittees and forums. Efforts are ongoing since the 3-Year Assessment Report.

7. Enhance Stakeholder Communications. a. Continue to conduct open Webcasts to present and obtain feedback on proposed concepts; for example, to stakeholders as reliability standards are being developed. The conduct of webcasts, webinars,...

AI summary NERC aims to enhance stakeholder communication through webcasts, forums, and blogs, though progress is delayed due to website redesign. They also seek to expedite fill-in-the-blank reliability standards as part of their 2011–2013 development plan.

Operating Committees. See response in B.1.a above. c. Request comments on the existing criteria from the Regional Entities through the Registration Working Group (RWG). See response in B.1.a above. d. Review data from registered entities s...

AI summary The text outlines NERC's role in entity registration under FERC Order 743, stakeholder discussions on criteria application, and the ERO's case-by-case review of registration issues. NERC's primary responsibility for registry management, with regional input, is emphasized, along with the impact of the BES definition project on criteria.

D. Event Analysis and Information Exchange - 1. Backlog of final event analysis reports delays dissemination of lessons learned to the industry; consider interim reports. - a. Revise the event analysis process to include interim reports fo...

AI summary The text discusses revisions to the ERO Event Analysis Process to address backlogs, including interim reports for prolonged analyses, real-time alerts, and hiring to fill open positions. It also proposes threshold criteria for event analysis and the use of root-cause analysis experts to expedite processes.

E. Reliability Assessment - 1. Assessment reports need to avoid taking policy advocacy positions and include more support from well-researched information. - a. Investigate and validate assumptions, data, and conclusions in future reliabil...

AI summary NERC is enhancing reliability assessments by avoiding policy advocacy, validating data with Regional Entities, improving metric definitions, and expanding stakeholder feedback processes. Reorganization of LTRAs and peer review refinements aim to increase transparency and technical accuracy in reliability evaluations.

F. Performance Analysis and Metrics - 1. Improve process for data collection. - a. Develop a centralized automated data collection, reporting and validation process, and calculation tools to support reliability metrics. Processes for data...

AI summary The document outlines initiatives to enhance data collection automation, focus on critical bulk power system reliability metrics, involve stakeholders via the Reliability Metrics Working Group (RMWG), and improve metric dissemination. Key actions include developing a centralized reporting system, vetting metrics against ALR standards, and publishing annual reliability performance reports.

H. Situation Awareness - 1. Real-time situation awareness is outside of NERC's scope. - a. NERC will continue to develop its SA to meet obligations set forth in its ERO certification application and in NERC's ROP, Section 1000. In carrying...

AI summary NERC discusses its plans to enhance real-time situation awareness (SA) through the SAFNR Version 2 system, transition reliability tools to industry stakeholders, and improve communication protocols with government agencies. NERC emphasizes collaboration with ESCC, ES-ISAC, and federal entities like DHS and FBI to strengthen emergency preparedness and system resilience.

12. Consider a "shared reserve" among Regional Entities and NERC. a. Continue discussion with Regional Entities concerning this concept as future budgets are developed. The concept of "shared reserve" among Regional Entities and NERC has b...

AI summary The proposal for a 'shared reserve' among Regional Entities and NERC was discussed but failed to reach consensus. Alternatives like individual cash reserves, lines of credit, and budget amendments were considered for funding unanticipated costs. Further dialogue with Regional Entities is recommended as budgets develop.

s many webinars, workshops, and presentations also aid in reaching non-traditional and smaller entities. b. NERC will work to implement specific suggestions received as a result of these discussions. 20 Reliability Standards Under Developm...

AI summary NERC collaborates with industry associations like APPA and NRECA to disseminate reliability information through interviews and publications, while developing new reliability standards. Efforts focus on engaging non-traditional stakeholders and sharing technical insights on topics like long-term reliability assessments and wind generation.

A Summary of Canadian Provincial Adoption of Reliability Standards Framework

AI summary This document summarizes the adoption of reliability standards by Canadian provinces, focusing on frameworks and compliance mechanisms involving organizations like NERC and FERC.

A Summary of Canadian Provincial Adoption of Reliability Standards Framework This document was prepared by the North American Electric Reliability Corporation (NERC) in consultation with the various Canadian and Provincial jurisdictions ba...

AI summary This document, prepared by NERC, summarizes Canadian provinces' adoption of reliability standards frameworks. It outlines NERC's collaboration with provincial jurisdictions and serves as an informational resource. Contact Ric Cameron for corrections.

Alberta: The Alberta Transmission Regulation (Reg 288/2009 as amended) outlines the framework for Reliability Standards in Alberta. The North American Electric Reliability Corporation (NERC) Reliability Standards apply in Alberta to the ex...

AI summary Alberta's Transmission Regulation (2009) integrates NERC Reliability Standards through AESO consultation and Alberta Commission oversight. The Minister of Energy recognized NERC as the ERO in 2007, and the 2009 Electricity Statutes Amendment Act formalized enforcement by the Alberta Commission and MSA, with penalties for non-compliance.

British Columbia: The 2007 provincial Energy Plan committed British Columbia (BC) to "ensure that the province remains consistent with North American transmission reliability standards." With the implementation of the Utilities Commission...

AI summary British Columbia's 2007 Energy Plan aligned with North American reliability standards. The 2009 Utilities Commission Amendment Act granted the BC Utilities Commission (BCUC) exclusive authority to enforce reliability standards, recognizing NERC and WECC as standard-making bodies. The BC Transmission Corporation (BCTC) must review reliability standards' impacts, with BCUC ensuring public access to reports and stakeholder feedback.

Manitoba: Manitoba Hydro is currently required to comply with NERC Reliability Standards through its membership in the Midwest Reliability Organization (MRO) and its membership in NERC, subject to exceptions based on provincial law. Pursua...

AI summary Manitoba Hydro complies with NERC Reliability Standards via membership in MRO, subject to provincial exceptions. The Manitoba Hydro Act (2004) and subsequent legislative amendments establish a framework for enforceable reliability standards, with PUB authorized to enforce compliance. A 2008 agreement with NERC/MRO outlines joint responsibilities, pending new provincial legislation and regulations expected in 2011.

National Energy Board: The National Energy Board (NEB) has statutory responsibility for authorizing the construction and operation of international power lines (IPL) and designated interprovincial power lines and approving electric exports...

AI summary The National Energy Board (NEB) oversees international power lines (IPLs) and interprovincial power lines, enforcing permit conditions without financial penalties. It lacks authority to approve or remand NERC Reliability Standards but collaborates with NERC via a 2006 MOU. The NEB seeks to implement mandatory reliability standards on IPLs through regulation-making.

New Brunswick: The Electricity Act in New Brunswick established the New Brunswick System Operator (NBSO) on October 1, 2004. NBSO is responsible to direct the operation of the transmission grid, to maintain the adequacy and reliability of...

AI summary New Brunswick's Electricity Act established the New Brunswick System Operator (NBSO) in 2004 to manage the transmission grid and ensure system reliability. NERC Reliability Standards are enforced via market rules, with compliance required for licenses. The Public Utilities Board was replaced by the Energy and Utilities Board (EUB) as the regulatory authority.

Nova Scotia: The Nova Scotia Utility and Review Board (NSUARB) exercises general supervision over all electric utilities operating as public utilities within the Province of Nova Scotia, pursuant to the Nova Scotia Public Utilities Act. In...

AI summary The Nova Scotia Utility and Review Board (NSUARB) oversees electric utilities under the Nova Scotia Public Utilities Act, ensuring compliance with reliability standards. An MOU with NERC allows NSUARB to adopt or remand reliability standards, making compliance mandatory in Nova Scotia. NSPI, part of NPCC, adheres to NERC standards, with NSUARB proposing mandatory adoption by mid-2011.

th NERC Reliability Standards by it or by market participants and is subject to NERC's Reliability Standards CMEP processes up to but not including financial penalties. The provincial government recognized NERC as the ERO on November 28, 2...

AI summary Ontario recognized NERC as the ERO in 2006, with the IESO and NERC entering a MOU to govern reliability standards. The Board oversees NERC, while the IESO ensures compliance with NERC and NPCC standards. The 2009 Green Energy Act amended the Electricity Act to empower the IESO to enforce reliability rules and direct market participants.

Québec: On December 13, 2006, the Québec Government adopted legislation "An Act Respecting the Implementation of the Québec Energy Strategy and Amending Various Legislative Provisions" (Bill 52) which gave the Régie de l'énergie du Québec...

AI summary Québec adopted Bill 52 in 2006, granting the Régie de l'énergie du Québec authority over reliability standards. The Régie partnered with NERC and NPCC in 2009 to implement compliance programs, including the QCMEP. A 2009 consultation on QROP and QCMEP documents led to revisions by 2010 to ensure consistent enforcement across North America.

Saskatchewan: Prior to 2004, SaskPower generally followed accepted industry practice. In 2004, following the 2003 eastern seaboard blackout, SaskPower committed itself formally to adopt NERC Reliability Standards. SaskPower joined MRO, and...

AI summary SaskPower adopted NERC reliability standards post-2003 blackout, joined MRO, and established a reliability oversight authority under the Power Corporation Act. A 2009 MOU with MRO and NERC outlines their roles as EROs, with Saskatchewan retaining enforcement authority. No penalties are currently envisioned, but future enforcement methods may be considered.

Operating Reliability Event Categories Operating reliability events are those events that are deemed to have significantly impacted the reliable operation of interconnected system. These events are divided into five (5) categories that acc...

AI summary Operating reliability events are categorized into five groups based on their impact on system reliability. These categories guide the level of analysis required. Examples are provided, with unspecified events to be categorized by the impacted entity and Regional Entity (RE).

Category 1: An event resulting in one or more of the following: a. The loss of a bulk power transmission component(s) in response to a single-phase line-toground fault with delayed clearing2 (stuck breaker or protection system failure). (R...

AI summary Category 1 defines events impacting bulk power system reliability, including delayed fault clearing, loss of multiple BPS elements, frequency deviations, SPS/RAS failures, voltage reductions, and unintended system separations. These scenarios are categorized under transmission standards (C6-C9) and emphasize system-wide reliability risks.

Category 2: An event resulting in one or more of the following: - a. Loss of all BPS control center voice or data functionality for 30 minutes or more. - b. Unplanned evacuation from BPS control center facility - c. Voltage excursions equa...

AI summary Category 2 events include critical BES disruptions such as control center outages, voltage excursions, generation station losses, load shedding, system separation, and IROL violations. Thresholds for reporting are defined based on MW losses, demand impacts, and reliability standards like TOP-007.

Category 3: An event resulting in one or more of the following: - a. The loss of load or generation (excluding SPS/RAS, UFLS, or UVLS actuation) of 2,000 MW or more in the Eastern Interconnection or Western Interconnection, or 1,000 MW or...

AI summary Category 3 defines events involving significant loss of load/generation (2,000 MW+ in Eastern/Western Interconnections or 1,000 MW+ in ERCOT/Québec) or unintended system separations creating islands of 5,000–10,000 MW, Alberta/New Brunswick/Florida separation from their respective interconnections.

Category 4: An event resulting in one or more of the following: - a. The loss of load or generation from 5,001 MW to 9,999 MW (excluding SPS/RAS as noted in Category 2, UFLS, or UVLS actuation). - b. Unintended system separation resulting...

AI summary Category 4 defines events involving significant loss of load or generation (5,001–9,999 MW) or unintended system separation creating an island over 10,000 MW, excluding specific regions. These scenarios exclude SPS/RAS, UFLS, and UVLS actuation.

Category 5: An event resulting in one or more of the following: - a. The loss of load of 10,000 MW or more. - b. The loss of generation of 10, 000 MW or more.

AI summary Category 5 defines events causing loss of load or generation exceeding 10,000 MW. It includes scenarios involving significant system failures impacting bulk electric system reliability and grid stability.

Chapter 9 – Scenario Assessment of the NERC Reliability Assessment Guidebook

AI summary This chapter evaluates the NERC Reliability Assessment Guidebook's scenario assessment methods, focusing on ensuring bulk electric system reliability through compliance with mandatory reliability standards and regulatory frameworks.

Background Each year, NERC's staff and its technical committees prepare a 10-year Long-Term Reliability Assessment (LTRA). This preparation includes data concentrated on Summer and Winter peak internal demand and associated demand and supp...

AI summary NERC prepares a 10-year Long-Term Reliability Assessment (LTRA) and Reference Case, assuming stable policies and historical trends. Scenario analysis evaluates sensitivity to factors like demand response, weather, and nuclear capacity. NERC's Planning Committee adopted a process in 2007 to assess emerging issues, with input from FERC and industry stakeholders.

Emerging Issue Qualification To qualify for consideration in this process, candidate emerging issues must meet the following criteria: - Subcommittees should have a high degree of confidence that the emerging issue to be evaluated would af...

AI summary Candidate emerging issues must demonstrate long-term (multi-year) impacts on bulk power system reliability, with effects not visible for at least three years. They must affect regional reliability, not local/subregional issues, and require analysis beyond Transmission Planners/Planning Authorities' scope.