N-10Reliability Standards of the North American Electric Reliability Corporation 7/5/2010
34 passages
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.
1. Title: Telecommunications 2. Number: COM-001-1.1 3. Purpose: Each Reliability Coordinator, Transmission Operator and Balancing Authority needs adequate and reliable telecommunications facilities internally and with others for the exchan...
AI summary The document outlines the importance of reliable telecommunications facilities for Reliability Coordinators, Transmission Operators, and Balancing Authorities to ensure the exchange of critical information necessary for maintaining system reliability.
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.
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.
C. Measures - M1. The Reliability Coordinator and Planning Authority shall each be able to demonstrate that it developed its Transfer Capabilities consistent with its Transfer Capability Methodology. - M2. The Reliability Coordinator and P...
AI summary The Reliability Coordinator and Planning Authority must demonstrate compliance with Transfer Capability Methodology and provide Transfer Capabilities according to requestors' schedules. Two measures (M1 and M2) outline these requirements for ensuring proper transfer capability documentation and adherence to scheduling protocols.
B. Requirements - R1. The Reliability Coordinator shall ensure that SOLs, including Interconnection Reliability Operating Limits (IROLs), for its Reliability Coordinator Area are established and that the SOLs (including Interconnection Rel...
AI summary The document outlines requirements for establishing and communicating System Operating Limits (SOLs) and Interconnection Reliability Operating Limits (IROLs) across reliability coordinator, transmission operator, planning authority, and transmission planner roles. Entities must align with their methodologies, share limits with stakeholders, and provide contingency and stability-related information.
r r ea , bu les ha 2 5 % t t 5 0 % o r m or e, s n 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 ( R 1 ) t e y. T he S O Ls fo he t re a re r , Co Re l ia b i l i d ina Ar...
AI summary The text discusses violation severity levels related to System Operating Limits (SOLs) and their alignment with reliability standards, referencing the Reliability Coordination and the SOLs in the Reliability Coordination's transmission planning standard (R1).
. SPP shall perform studies to determine which external flowgates SPP will monitor and help control. An external flowgate selected by one of the studies will be considered a Coordinated Flowgate (CF). In its calculation, SPP shall consider...
AI summary SPP must adopt a 'Market Flow Calculation' methodology for determining parallel flows on Coordinated Flowgates (CF), replacing the 'Per Generator Method without Counter Flow' in Attachment 1-IRO-006-1 Section 5. This approach impacts TLR Procedure calculations for Network and Native Load (NNL), excluding tagged transactions and focusing on market-dispatched energy within the SPP footprint.
Priority Purpose Explanation and Conditions S1 To allow a flowing Interchange Transaction to maintain or reduce its current MW amount in accordance with its energy profile. The MW amount is the lowest between currently flowing MW amount an...
AI summary The text outlines priorities for managing Interchange Transactions, including adjusting MW amounts based on energy profiles and schedules. It also describes the 'Market Flow Calculation' methodology used by SPP to determine energy flow across facilities in the RTO's Coordinated Flowgate List.
These market flow impacts for current hour and next hour will be separated into their appropriate priorities and provided to the IDC by SPP. The market flows will then be represented and made available for curtailment under the appropriate...
AI summary The document outlines the process for handling market flow impacts for the current and next hour, which will be separated by priority and sent to the IDC by SPP. These impacts will be represented and made available for curtailment under appropriate TLR levels, even without conventional tags. Subpriorities (S1 through S4) should be assigned by the NERC IDC using comparable logic to tagged transactions.
Priority Purpose Explanation and Conditions S1 To allow existing market flow to maintain or reduce its current MW amount. The currently flowing MW amount is the amount of market flow existing after the RTO has recognized the constraint for...
AI summary The text outlines three priorities related to market flow adjustments during Transmission Loading Relief (TLR). Priority S1 allows existing market flow to maintain or reduce its current MW amount, S2 allows curtailed market flow to reload to its desired amount, and S3 allows market flow to increase to its next-hour desired amount. The text also mentions that the Regional Difference will be contained in NERC and NAESB standards upon completion of a field test.
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.
Example 1 Flow to maintain on Facility 800 MW Expected flow next hour from Transactions using Point-to Point Transmission Service 950 MW Contribution from flow next hour from service to Network customers and Native Load -100 MW Expected Ne...
AI summary The text provides examples of flow calculations on a facility, including expected flows, contributions from service to network customers, net flows, and amounts to be held for reallocation or entered into the Interchange Database (IDC). It also explains the process for handling TLR levels 3b or 5b, involving the Reliability Coordinator and IDC to manage curtailments and flows.
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.
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.
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.
A. Introduction - 1. Title: System Performance Following Loss of Two or More Bulk Electric System Elements (Category C) - 2. Number: TPL-003-0a - 3. Purpose: System simulations and associated assessments are needed periodically to ensure t...
AI summary This document outlines TPL-003-0a, a transmission planning standard requiring periodic system simulations to ensure reliability and meet performance requirements. It applies to Planning Authority and Transmission Planner, effective April 23, 2010, emphasizing modifications and upgrades to address current and future system needs.
- R1.3.6. Be performed and evaluated for selected demand levels over the range of forecast system demands. - R1.3.7. Demonstrate that System performance meets Table 1 for Category C contingencies. - R1.3.8. Include existing and planned fac...
AI summary The text outlines requirements for system performance evaluations, including contingency planning, reactive power resources, protection systems, and control devices. It mandates documentation of reliability assessments, corrective plans, and annual reporting to NERC Regional Reliability Organizations, with specific attention to Reliability Standard TPL-003-0_R1.
C. Measures - M1. The Planning Authority and Transmission Planner shall have a valid assessment and corrective plans as specified in Reliability Standard TPL-003-0_R1 and TPL-003-0_R2. - M2. The Planning Authority and Transmission Planner...
AI summary The Planning Authority and Transmission Planner must maintain valid assessment and corrective plans under Reliability Standards TPL-003-0_R1 and TPL-003-0_R2, and provide evidence of reporting reliability assessments and corrective plans as required by TPL-003-0_R3.
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.
Continent-wide Definitions: A 4 After the Fact [Archive] ATF 10/29/2008 12/17/2009 A time classification assigned to an RFI when the submittal time is greater than one hour after the start time of the RFI. Agreement [Archive] 2/8/2005 3/16...
AI summary This section provides continent-wide definitions related to electric reliability and transmission planning standards, including terms such as 'After the Fact,' 'Agreement,' 'Altitude Correction Factor,' and 'Ancillary Service.' These definitions are relevant to the operation and regulation of the Bulk Electric System and are aligned with standards set by organizations like FERC and NERC.
1 See 18 CFR 37.6(b)(1) Continent-wide Term Acronym BOT Approved Date FERC Approved Date Definition Blackstart Resource [Archive] 8/5/2009 A generating unit(s) and its associated set of equipment which has the ability to be started without...
AI summary The text provides a definition of a 'Blackstart Resource' as a generating unit and associated equipment capable of being started without support from the system and included in the Transmission Operator's restoration plan. It references a regulatory standard (18 CFR 37.6(b)(1)) and includes 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 Continent-wide Term Acronym BOT Approved Date FERC Approved Date Definition Flowgate [Archive] 08/22/2008 11/2...
AI summary The text provides a definition of 'Flowgate' as a portion of the transmission system used in calculating power flow from interchange transactions, and as a mathematical construct used to analyze the impact of power flows on the Bulk Electric System.
Exhibit D
AI summary Exhibit D provides a list of acronyms and their expansions relevant to regulatory standards, compliance, and operational protocols in the Nova Scotia utility sector, including cybersecurity, emergency operations, and transmission planning.
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.
R5.2. 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 The allocation of ATC Paths and Flowgates depends on inputs from Load-Serving Entities and Resource Planners. The Transmission Planner must establish a Capacity Benefit Margin (CBM) value every 13 months for long-term planning, incorporating studies and reserve margin requirements from various entities.
br>u p hr hs to t t ee m on a g o. T he Tr iss ion O ha to an sm p er a r s T R M I D ha do t t t a es n o inc ha ha ha te t t or p or a c ng es ve be de hr t en m a ee o r m or e hs bu les ha ix t t t m on a g o s n s hs t m on a g o. O R...
AI summary The document discusses the Transmission Reliability Margin Implementation Document (TRMID) and its role in addressing transmission reliability issues. It outlines specific violation severity levels and the requirements for the TRMID to ensure proper implementation and adherence to standards.
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 Transmission commitments for the ATC Path during...
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 provides a formula for calculating non-firm ATC, incorporating factors like existing commitments, reliability margins, and adjustments from postbacks and counterflows.
4. Applicability: - 4.1. Each Transmission Operator that uses the Rated System Path Methodology to calculate Total Transfer Capabilities (TTCs) for ATC Paths. - 4.2. Each Transmission Service Provider that uses the Rated System Path Method...
AI summary The section outlines the applicability of the Rated System Path Methodology for calculating transfer capabilities by Transmission Operators and Service Providers, with an effective date contingent on the approval of four specific standards by regulatory authorities.
int of interconnection in the studied area. - R1.1.4. Models phase shifters in non-regulating mode, unless otherwise specified in the Available Transfer Capability Implementation Document (ATCID).
AI summary The text references modeling phase shifters in non-regulating mode, subject to specifications in the Available Transfer Capability Implementation Document (ATCID), and mentions interconnection integrity in the studied area.
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.
Matrix of Violation Risk Factors for Approval Standard Number Requirement Text of Requirement Violation FAC-003-1 R2. The Transmission Owner shall create and implement an annual plan for vegetation management work to ensure the reliability...
AI summary The document presents a matrix of violation risk factors for approval, focusing on vegetation management requirements under FAC-003-1. It outlines the need for annual vegetation management plans and quarterly reporting of outages caused by vegetation, with high and lower risk levels assigned to these requirements.
Matrix of Violation Severity Levels for Approval Standard Number Requirement Number Text of Requirement Lower VSL Moderate VSL High VSL Severe VSL FAC-001-0 R2.1.2. Procedures for notification of new or modified facilities to others (those...
AI summary The document presents a matrix outlining violation severity levels for approval, focusing on FAC-001-0 R2.1.2, which requires timely notification of new or modified facilities to ensure reliability of interconnected transmission systems. The severe violation level indicates that the Transmission owner's procedures failed to include this subrequirement.
07810Quarterly Application for Approval of Reliability Standards of the North American Electric Reliability Corporation - September 2, 2011 9/6/2011
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- 3) Updated NERC Glossary of Terms 1.) NERC Reliability Standards Applicable to Nova Scotia Approved by FERC Since June 30, 2010 Filing EOP-005-2 - System Restoration from Blackstart Resources (formerly EOP-005- 1; also incorporates parts...
AI summary The document provides an updated list of NERC reliability standards applicable to Nova Scotia, including their approval dates by FERC. These standards cover system restoration, facility coordination, interchange scheduling, and reliability operations.
- R6.6. Reducing load, through procedures such as public appeals, voltage reductions, curtailing interruptible loads and firm loads. - R7. Once the Balancing Authority has exhausted the steps listed in Requirement 6, or if these steps cann...
AI summary The document outlines emergency procedures for balancing authorities and reliability coordinators, including load reduction methods, manual load shedding, and initiating Energy Emergency Alerts (EEA) per NERC guidelines. It specifies steps for addressing transmission service priority changes and reporting to NERC.
- 2.4.1 Notification of ATC adjustments . Resulting increases in ATCs shall be simultaneously communicated to the Energy Deficient Entity and the market via posting on the appropriate OASIS websites by the Transmission Providers. - 2.4.2 A...
AI summary The text outlines procedures for managing energy shortages, emphasizing communication between Reliability Coordinators, Transmission Providers, and the Energy Deficient Entity. Key steps include notifying ATC adjustments, evaluating transmission relief impacts, and requiring the Energy Deficient Entity to utilize all resources before declaring an Alert 3, such as activating generation units and curtailing demand-side management.
2.Violation Severity Levels # R L V S L ow er M de V S L te o ra H ig h V S L Se V S L ve re
AI summary This section outlines different violation severity levels, categorized as Low, Medium, and High. It appears to be part of a regulatory framework that defines the severity of violations within the Bulk Electric System (BES), potentially related to reliability and transmission operations.
1. Title: Coordination of Plans For New Generation, Transmission, and End-User Facilities 2. Number: FAC-002-1 3. Purpose: To avoid adverse impacts on reliability, Generator Owners and Transmission Owners and electricity end-users must mee...
AI summary This document outlines the purpose of FAC-002-1, which is to ensure that Generator Owners, Transmission Owners, and electricity end-users meet facility connection and performance requirements to avoid adverse impacts on reliability.
C. Measures - M1. Each Receiving and Sending Balancing Authority shall have and provide upon request evidence that could include, but is not limited to, interchange transaction tags, operator logs, voice recordings or transcripts of voice...
AI summary The document outlines requirements for Receiving and Sending Balancing Authorities to provide evidence confirming Interchange Schedules' accuracy in the ACE equation (M1) and coordination with HVDC tie Transmission Operators (M2), referencing specific regulatory requirements (R1, R1.1, etc.).
- Operator shall immediately inform the Reliability Coordinator of the status of the Special Protection System including any degradation or potential failure to operate as expected. - R13. Each Reliability Coordinator shall ensure that all...
AI summary The text outlines requirements for Reliability Coordinators to manage the Bulk Electric System (BES), including notifying of Special Protection System status, preventing SOL/IROL violations across areas, disseminating transmission limits, alerting to transmission issues, and confirming reliability assessments. Key themes involve system reliability, coordination among entities, and compliance with operational limits.
IRO-005-1 Requirement R12 R12. Whenever a Special Protection System that may have an inter-Balancing Authority, or inter-Transmission Operator impact (e.g., could potentially affect transmission flows resulting in a SOL or IROL violation)...
AI summary Requirement R12 mandates that Reliability Coordinators be informed of Special Protection Systems (SPS) impacts on inter-area transmission flows, and the Transmission Operator must immediately notify Reliability Coordinators of SPS status changes, including degradation or failure.
ameter. - R11. The Transmission Service Provider shall respect SOLs and IROLs in accordance with filed tariffs and regional Total Transfer Calculation and Available Transfer Calculation processes. R12. Each Reliability Coordinator who fore...
AI summary The document outlines two regulatory requirements: R11 mandates that the Transmission Service Provider adhere to System Operating Limits (SOLs) and Interconnection Reliability Operating Limits (IROLs) per filed tariffs, while R12 obligates Reliability Coordinators to promptly alert Transmission Operators and Balancing Authorities about transmission issues, ensuring timely mitigation.
2. Violation Severity Levels: Requirement Lower Moderate High Severe R10 N/A N/A N/A The responsible entity failed to operate the Bulk Electric System to the most limiting parameter in instances where there was a difference in derived limi...
AI summary This section outlines violation severity levels for specific requirements related to the operation of the Bulk Electric System and adherence to System Operating Limits. It highlights severe violations involving failure to comply with operational standards and tariff requirements.
PRC-012-0 Requirements R1 and R1.3 R1. Each Regional Reliability Organization with a Transmission Owner, Generator Owner, or Distribution Providers that uses or is planning to use an SPS shall have a documented Regional Reliability Organiz...
AI summary The text outlines requirements for Regional Reliability Organizations (RROs) to ensure Special Protection Systems (SPS) comply with NERC standards and regional criteria. Specifically, R1.3 mandates that SPS design must prevent a single component failure from compromising transmission system performance as defined in TPL-001-0, TPL-002-0, and TPL-003-0.
A. Introduction - 1. Title: Transmission Loading Relief Procedure for the Eastern Interconnection - 2. Number: IRO-006-EAST-1 - 3. Purpose: To provide an Interconnection-wide transmission loading relief procedure (TLR) for the Eastern Inte...
AI summary The document outlines a Transmission Loading Relief (TLR) procedure for the Eastern Interconnection (IRO-006-EAST-1), aimed at preventing or mitigating exceedances of System Operating Limits (SOL) and Interconnection Reliability Operating Limits (IROL) to ensure the reliability of the Bulk Electric System (BES).
A. Introduction 1. Title: Available Transmission System Capability 2. Number: MOD-001-1a 3. Purpose: To ensure that calculations are performed by Transmission Service Providers to maintain awareness of available transmission system capabil...
AI summary The purpose of MOD-001-1a is to ensure Transmission Service Providers (TSPs) calculate available transmission system capability and future flows on their systems and neighboring systems to maintain awareness and reliability.
B. Requirements - R1. Each Transmission Operator shall select one of the methodologies[1](#page-17-0) listed below for calculating Available Transfer Capability (ATC) or Available Flowgate Capability (AFC) for each ATC Path per time period...
AI summary The requirements outline methodologies for calculating Available Transfer Capability (ATC) and Available Flowgate Capability (AFC) by Transmission Operators and Service Providers, specifying time periods for calculations and the need for an ATCID document detailing implementation details and counterflow accounting.
ad forecast and facility outages) used to calculate TTC or TFC as well as other evidence (such as copies of operations planning studies, models, supporting information, or data) to show that the assumptions used in determining TTC or TFC a...
AI summary Transmission Operators must demonstrate that assumptions used in calculating Total Transfer Capability (TTC) or Total Flowgate Capability (TFC) are no more limiting than those in operations planning, using evidence like studies or data. Differences in input data due to timing should not be considered differences in assumptions (R6).
2. Violation Severity Levels R # Lower VSL Moderate VSL High VSL Severe VSL R1. N/A N/A N/A The Transmission Operator did not select one of the specified methodologies for each ATC Path per time period identified in R2 for those Facilities...
AI summary The document outlines violation severity levels for transmission operators, with a specific reference to R1, which identifies a severe violation when the Transmission Operator fails to select specified methodologies for each ATC Path per time period as outlined in R2.
MOD-001-01 Requirement R2: - R2. Each Transmission Service Provider shall calculate ATC or AFC values as listed below using the methodology or methodologies selected by its Transmission Operator(s): - R2.1. Hourly values for at least the n...
AI summary Requirement R2 mandates Transmission Service Providers (TSPs) to calculate Available Transfer Capability (ATC) or Available Flowgate Capability (AFC) values using methodologies selected by their Transmission Operators. Calculations must cover hourly (48 hours), daily (31 days), and monthly (12 months) timeframes.
MOD-001-01 Requirement R8: - R8. Each Transmission Service Provider that calculates ATC shall recalculate ATC at a minimum on the following frequency, unless none of the calculated values identified in the ATC equation have changed: - R8.1...
AI summary Requirement R8 mandates Transmission Service Providers (TSPs) to recalculate Available Transfer Capability (ATC) hourly, daily, and monthly, with exceptions allowing up to 175 hours annually where recalculations are not required if ATC equation values remain unchanged. Specific frequencies include hourly recalculations, daily recalculations, and monthly recalculations performed weekly.
Question #1 Is the "advisory ATC" used under the NYISO tariff subject to the ATC calculation and recalculation requirements in MOD-001-1 Requirements R2 and R8? If not, is it necessary to document the frequency of "advisory" calculations i...
AI summary The question examines whether 'advisory ATC' under NYISO's tariff must comply with MOD-001-1 Requirements R2 and R8 for ATC calculations and recalculation. It also asks if documentation of advisory calculation frequency is required in the Responsible Entity's Available Transfer Capability Implementation Document.
Response to Question #1 Requirements R2 and R8 of MOD-001-1 are both related to Requirement R1, which defines that ATC methodologies are to be applied to specific "ATC Paths." The NERC definition of ATC Path is "Any combination of Point of...
AI summary The response explains that NYISO's ATC Paths align with NERC's definition, implying NYISO's 'advisory ATC' is equivalent to standard ATC. It also notes that pre-scheduling on external paths requires ATC calculations prior to day-ahead scheduling, as mandated by MOD-001-1 Requirements R2 and R8.
MOD-029-01 Requirements R5 and R6: R5. When calculating ETC for firm Existing Transmission Commitments (ETCF) for a specified period for an ATC Path, the Transmission Service Provider shall use the algorithm below: $$ETC_F = NL_F + NITS_F...
AI summary Requirement R5 outlines a formula for calculating Existing Transmission Commitments (ETC) for firm commitments on an ATC Path, specifying components like NL_F, NITS_F, GF_F, PTP_F, ROR_F, and OS_F. The Transmission Service Provider is mandated to apply this algorithm.
Where: NLF is the firm capacity set aside to serve peak Native Load forecast commitments for the time period being calculated, to include losses, and Native Load growth, not otherwise included in Transmission Reliability Margin or Capacity...
AI summary The text defines several transmission capacity terms (NLF, NITSF, GFF, PTPF, RORF, OSF) and provides a formula for calculating non-firm Existing Transmission Commitments (ETCNF). These terms relate to reserved firm capacity for specific services and the algorithm to compute ETCNF using components like NITSF, GF, PTP, and OS.
Standard MOD-001-1a — Available Transmission System Capability effective date of a Transmission Service Provider's Open Access Transmission Tariff or "safe harbor tariff." PTPNF is non-firm capacity reserved for confirmed Point-to-Point Tr...
AI summary The text defines PTPNF (Point-to-Point Non-Firm) and OSNF (Other Service Non-Firm) as categories of non-firm transmission capacity under the Open Access Transmission Tariff. It specifies their allocation for confirmed Point-to-Point Transmission Service and other unspecified services, respectively, using the ATCID (Available Transfer Capability Identifier) framework.
Question #2 Could OSF in MOD-029-1 Requirement R5 and OSNF in MOD-029-1 Requirement R6 be calculated using Transmission Flow Utilization in the determination of ATC?
AI summary The question asks whether Operating Security Factor (OSF) and Operating Security Factor for Non-Firm (OSNF) under MOD-029-1 Requirements R5 and R6 can be calculated using Transmission Flow Utilization in determining Available Transfer Capability (ATC).
Response to Question #2 This request for interpretation and the NYISO Open Access Transmission Tariff describe the NYISO's concept of "Transmission Flow Utilization;" however, it is unclear whether or not Native Load, Point-to-Point Transm...
AI summary The response clarifies ambiguity about whether 'Transmission Flow Utilization' under NYISO's tariff includes Native Load or services defined in Requirements R5/R6. It argues that if these components are excluded, they should be categorized under 'Other Services,' but inclusion would be inappropriate if they are already part of 'Transmission Flow Utilization.'
R5.2. 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 The document outlines allocation rules for ATC Paths and Flowgates based on inputs from Load-Serving Entities and Resource Planners, and mandates the Transmission Planner to establish a Capacity Benefit Margin (CBM) value every 13 months for long-term planning, incorporating studies and reserve margin requirements from various entities.
C. Measures - M1. Each Transmission Service Provider that maintains CBM shall produce its CBMID evidencing inclusion of all information specified in R1. (R1) - M2. Each Transmission Service Provider that maintains CBM shall have evidence (...
AI summary The measures outline compliance requirements for Transmission Service Providers, Load-Serving Entities, and others regarding Capacity Benefit Margin (CBM) management, including documentation, notifications, and adherence to specific regulations (R1-R12). Entities must provide evidence of CBM allocation, notifications, and compliance with reliability and operational standards.
R 6. T he Tr iss io P lan i h t an sm n ne r w ia d Tr iss io te an a ss oc an sm n T he Tr iss io P lan i h t an sm n ne r w ia d Tr iss io te an a ss oc an sm n Se ic Pr i de ha in in t t m ta rv e ov r a s C B M b l is he d C B M fo h t...
AI summary The text discusses the Transmission Plan, including the Capacity Benefit Margin (CBM) and its implementation over a period of 10 years, with references to specific figures and dates, such as 19hs and 22hs, which may relate to capacity measurements or timeframes.
4. Applicability: - 4.1. Each Transmission Operator that uses the Area Interchange Methodology to calculate Total Transfer Capabilities (TTCs) for ATC Paths. - 4.2. Each Transmission Service Provider that uses the Area Interchange Methodol...
AI summary The section outlines applicability for Transmission Operators and Service Providers using the Area Interchange Methodology to calculate transfer capabilities. The effective date is tied to the approval of four standards (MOD-001-1, MOD-028-1, MOD-029-1, MOD-030-1) by regulatory authorities.
Where: - NITSF is the firm capacity set aside for Network Integration Transmission Service (including the capacity used to serve bundled load within the Transmission Service Provider's area with external sources) on ATC Paths that serve as...
AI summary The text defines terms related to transmission service capacity (NITSF, GFF, PTPF, RORF, OSF) and outlines a formula for calculating non-firm Energy Transfer Commitments (ETCNF) using components like NITSF, GF, PTP, and OS. It references Requirement R9 for algorithmic calculations involving violation risk factors and time horizons.
established at least once in the calendar week prior to the specified period for TTCs used in hourly and daily ATC calculations, at least once per calendar month for TTCs used in monthly ATC calculations, and within 24 hours of the unexpec...
AI summary The text outlines procedural requirements for establishing Total Transfer Capability (TTC) values in transmission planning, specifying frequencies for hourly, daily, and monthly calculations, as well as response timelines for unexpected outages of high-voltage transmission facilities.
Models phase shifters in non-regulating mode, unless otherwise specified in the Available Transfer Capability Implementation Document (ATCID). - R1.1.5. Uses Load forecast by Balancing Authority.
AI summary The text specifies modeling phase shifters in non-regulating mode, referencing the Available Transfer Capability Implementation Document (ATCID), and mandates the use of load forecasts by the Balancing Authority under R1.1.5. These requirements relate to grid operations and reliability standards.
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 capability calculations, including Available Transfer Capability (ATCF), Total Transfer Capability (TTC), and adjustments like Capacity Benefit Margin (CBM) and Transmission Reliability Margin (TRM). It outlines an algorithm for calculating non-firm ATC, incorporating factors like counterflows, postbacks, and repeated CRASS terms.
Where: ATCNF is the non-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 pe...
AI summary The text defines key terms related to transmission capacity and margins, including non-firm and total transfer capability, existing commitments, capacity benefit margins, and adjustments to available transfer capability. These terms are critical for managing transmission reliability and capacity allocation.
Response to Question #2 This request for interpretation and the NYISO Open Access Transmission Tariff describe the NYISO's concept of "Transmission Flow Utilization;" however, it is unclear whether or not Native Load, Point-to-Point Transm...
AI summary The response clarifies ambiguity about whether 'Transmission Flow Utilization' under NYISO's tariff includes Native Load or services defined in Requirements R5/R6. It argues that if these components are excluded, they should be categorized under 'Other Services,' but inclusion would be inappropriate if they are already part of 'Transmission Flow Utilization.'
Where: AFCNF is the non-firm Available Flowgate Capability for the Flowgate for that period. TFC is the Total Flowgate Capability of the Flowgate. ETCFi is the sum of the impacts of existing firm Transmission commitments for the Flowgate d...
AI summary The text defines terms related to transmission capacity calculations, including non-firm and total flowgate capability, and outlines requirements for recalculating Available Flowgate Capability (AFC) and converting it to Available Transfer Capability (ATC). R10 mandates hourly, daily, and weekly recalculations, while R11 specifies an algorithm for ATC conversion.
in l ist f t m t es no a a a c ur ren o fac i l it ies it ica l t he l ia b i l ity o t cr re f t he Bu l k E lec ic Sy tr ste o m , O R D i d n i de he l ist f fac i l it ies ot t p ro v o it ica l t he l ia b i l ity f t he o t cr re o B...
AI summary The text discusses the criticality of facilities and their reliability within the Bulk Electric System (BES), referencing requirements and standards related to transmission and generation protection systems. It mentions various entities involved in transmission, generation, and distribution.
IRO-005-1 Requirement R12 R12. Whenever a Special Protection System that may have an inter-Balancing Authority, or inter-Transmission Operator impact (e.g., could potentially affect transmission flows resulting in a SOL or IROL violation)...
AI summary Requirement R12 mandates that Reliability Coordinators be informed of Special Protection Systems (SPS) impacts on inter-area transmission flows, and the Transmission Operator must immediately notify Reliability Coordinators of SPS status changes, including degradation or failure.
IRO-005-1 Requirement R12 R12. Whenever a Special Protection System that may have an inter-Balancing Authority, or inter-Transmission Operator impact (e.g., could potentially affect transmission flows resulting in a SOL or IROL violation)...
AI summary Requirement R12 mandates that Reliability Coordinators be informed of Special Protection Systems (SPS) impacts on inter-area transmission flows, and the Transmission Operator must immediately notify Reliability Coordinators of SPS status changes, including degradation or failure.
PRC-012-0 Requirements R1 and R1.3 R1. Each Regional Reliability Organization with a Transmission Owner, Generator Owner, or Distribution Providers that uses or is planning to use an SPS shall have a documented Regional Reliability Organiz...
AI summary The text outlines requirements for Regional Reliability Organizations (RROs) to ensure Special Protection Systems (SPS) comply with NERC standards and regional criteria. Specifically, R1.3 mandates that SPS design must prevent a single component failure from compromising transmission system performance as defined in TPL-001-0, TPL-002-0, and TPL-003-0.
1 See 18 CFR 37.6(b)(1) Continent-wide Term Acronym BOT Approved Date FERC Approved Date Definition Block Dispatch [Archive] 08/22/2008 11/24/2009 A set of dispatch rules such that given a specific amount of load to serve, an approximate g...
AI summary The text defines key terms related to the electric power industry, including 'Block Dispatch' and 'Bulk Electric System,' with details on their approval dates and definitions as determined by regulatory bodies.
Glossary of Terms Used in NERC Reliability Standards Continent-wide Term Acronym BOT Approved Date FERC Approved Date Definition Facility Rating [Archive] 2/8/2005 3/16/2007 The maximum or minimum voltage, current, frequency, or real or re...
AI summary This section provides definitions of key terms used in NERC Reliability Standards, including Facility Rating, Fault, Fire Risk, Firm Demand, Firm Transmission Service, Flashover, and Flowgate. These definitions are approved by the Board of Trustees and the Federal Energy Regulatory Commission.
Matrix of Violation Risk Factors for Information S d d Nu b ta n a r m e r Re ire t q m e n u Nu b m e r Te f Re ire t o t q m e n x u V io la io R is k t n Fa to c r MOD-001-1a R3.6.3. How outages from other Transmission Service Providers...
AI summary The document outlines a matrix for evaluating violation risk factors related to information, focusing on how outages from other Transmission Service Providers are addressed when they cannot be mapped to the Transmission model used for calculating transfer or Flowgate capability. The status of this item is listed as 'Pending'.