DOCSLIB.ORG

Transmission Planning Technical Guide

Total Page：16

File Type：pdf, Size：1020Kb

Download full-text PDF Read full-text
Transmission Planning Technical Guide Transmission Planning Technical Guide © ISO New England Inc. System Planning REVISION: 5.0 EFFECTIVE DATE: 09/13/2019 NOTE: Additional updates continuing to review the content of the guide in further detail to match current processes and procedures will follow. ISO-NE PUBLIC TPTG Disclaimer The provisions in this document are intended to be consistent with ISO New England’s Tariff. If, however, the provisions in this planning document conflict with the Tariff in any way, the Tariff takes precedence as the ISO is bound to operate in accordance with the ISO New England Tariff. Revision: 5.0 – Effective Date: 09/13/2019 page iii ISO-NE PUBLIC TPTG Contents Disclaimer............................................................................................................................................................................. iii Contents ............................................................................................................................................................................... iv Figures ................................................................................................................................................................................. vii Tables................................................................................................................................................................................... vii Section 1 Introduction ......................................................................................................................................................... 8 1.1 Purpos e ....................................................................................................................................................................... 8 1.2 Applicable Reliabili ty Standards................................................................................................................................ 9 1.3 Types of Sys tem Planni ng Studi es...........................................................................................................................10 Section 2 Modeling Assumptions .....................................................................................................................................12 2.1 Bas e Cas e Topology .................................................................................................................................................12 2.1.1 Modeling Existing and Proposed Generation.................................................................................................15 2.1.2 Bas e Cas es for PPA Studi es and Sys tem Impact Studi es ...............................................................................15 2.1.3 Coordinating Ongoing Studies.........................................................................................................................16 2.1.4 Base Case Sensitivities .....................................................................................................................................16 2.1.5 Modeling Projects with Different In-Service Dates........................................................................................16 2.2 System Load .............................................................................................................................................................17 2.2.1 System Load Levels ..........................................................................................................................................17 2.2.2 Load Levels Tested ...........................................................................................................................................18 2.2.3 Non-CELT Loads ................................................................................................................................................20 2.2.4 Load Power Factor ...........................................................................................................................................20 2.2.5 Load Models .....................................................................................................................................................21 2 .3 Sys tem Res ourc es ....................................................................................................................................................22 2.3.1 Generator Maximum Power Rating Types .....................................................................................................22 2.3.2 Generator Models ............................................................................................................................................23 2.3.3 Maximum Real Power Ratings.........................................................................................................................23 2.3.4 Rea c ti ve Power Ra ti ngs....................................................................................................................................26 2.3.5 Generator Unavailability Probability ..............................................................................................................26 2.3.6 Combined Cycle Generation............................................................................................................................27 2.3.7 Wind Generation ..............................................................................................................................................27 2.3.8 Conventional Hydro Generation .....................................................................................................................27 2.3.9 Pumped Storage Hydro Generation................................................................................................................27 2.3.10 Solar Photovoltaic Generation ......................................................................................................................28 2.3.11 Dema nd Resour c es ........................................................................................................................................31 2.3.12 Behind-the-Meter Mill Generation ...............................................................................................................31 Revision: 5.0 – Effective Date: 09/13/2019 page iv ISO-NE PUBLIC TPTG 2.4 Phas e Shi fting Trans formers ...................................................................................................................................31 2.5 Load Tap Changing Trans formers ...........................................................................................................................32 2 .6 Sta tic Compensa ti on Devic es ..................................................................................................................................32 2.6.1 Ser i es Devic es ...................................................................................................................................................32 2.6.2 Shunt Devices ...................................................................................................................................................34 2.7 Dynamic Compensation Devices.............................................................................................................................34 2.8 Interface Transfer Levels .........................................................................................................................................34 2.8.1 Methodology to Determine Transfer Limits...................................................................................................34 2.8.2 Sys tem Condi tions............................................................................................................................................34 2.8.3 Modeling Procedures .......................................................................................................................................35 2.9 High Voltage Direct Current (HVDC) Lines .............................................................................................................35 2.10 Special Protection Systems / Remedial Action Schemes ....................................................................................36 2.11 Steady State Power Flow Solution Settings .........................................................................................................36 2.11.1 Area Interchange Control ..............................................................................................................................37 2.11.2 Transformer Load Tap Changer Adjus tment ................................................................................................37 2.11.3 Phas e Shi fti ng Trans former Adj us tments.....................................................................................................38 2.11.4 Switched Shunt Adjustments ........................................................................................................................38 2.11.5 High Voltage Direct Current (HVDC) Lines Tap Adjustments ......................................................................38 2.11.6 Ser i es Reac tive Devic es..................................................................................................................................38 Section 3 Reliability Criteria and Guidelines ...................................................................................................................39 3.1 Steady State Criteria
Load more

Recommended publications
  • Page 2 SCHEDULE 21 – VEC LOCAL SERVICE SCHEDULE of VERMONT ELECTRIC COOPERATIVE, INC
    SCHEDULE 21 – VEC LOCAL SERVICE SCHEDULE OF VERMONT ELECTRIC COOPERATIVE, INC. Page 2 TABLE OF CONTENTS Schedule 21 – VEC LOCAL SERVICE SCHEDULE I. Common Service Provisions 1 Definitions 1.1 Definitions 1.2 Firm Local Point-to-Point Transmission Service 1.3 Independent System Operator 1.4 Load Ratio Share 1.5 Load Shedding 1.6 Local Network Customer 1.7 Local Network Load 1.8 Local Network Operating Agreement 1.9 Local Network Operating Committee 1.10 Local Network Upgrades 1.11 Local Non-Firm Sale 1.12 Local Service Agreement 1.13 Local Transmission Customer 1.14 Non-Firm Local Point-to-Point Transmission Service 1.15 Parties 1.16 Phase I/Phase II HVDC Facilities 1.17 Reserved 1.18 Short-Term Firm Local Point-to-Point Transmission Service 1.19 Transmission Owner 1.20 Transmission Owner 1.21 VEC 1.22 VEC’s Monthly Transmission System Peak 1.23 VTransco 2 Initial Allocation and Renewal Procedures Page 3 2.1 Reservation Priority For Existing Firm Service Customers 3 Ancillary Services 4 Billing and Payment 4.1 Billing Procedure 4.2 Interest on Unpaid Balances 4.3 Customer Default 5 Accounting for VEC’s Use of the Tariff 5.1 Transmission Revenues 5.2 Study Costs and Revenues 6 Regulatory Filings 7 Creditworthiness 8 Dispute Resolution Procedures 8.1 Internal Dispute Resolution Procedures 8.2 External Arbitration Procedures 8.3 Arbitration Decisions 8.4 Costs 8.5 Rights Under the Federal Power Act II. LOCAL POINT-TO-POINT TRANSMISSION SERVICE 9 Preamble 9.1 Classification of Firm Local Transmission Service 9.2 Classification of Non-Firm
    [Show full text]
  • January 26, 2021 VIA ELECTRONIC FILING the Honorable Kimberly D
    January 26, 2021 VIA ELECTRONIC FILING The Honorable Kimberly D. Bose, Secretary Federal Energy Regulatory Commission 888 First Street, N.E. Washington, D.C. 20426 Re: Revisions to Schedule 24 of the ISO New England Open Access Transmission Tariff to Comply with Order No. 676-I; ISO New England Inc. and New England Power Pool, Docket No. ER21-___-000 Dear Secretary Bose: Pursuant to Section 205 of the Federal Power Act (“FPA”)1 and Order No. 676-I,2 ISO New England Inc. (the “ISO” or “ISO-NE”)3 joined by the New England Power Pool (“NEPOOL”) Participants Committee4 (together, the “Filing Parties”), hereby electronically submit to the Federal Energy Regulatory Commission (“FERC” or “Commission”) revisions to Schedule 24 – Incorporation by Reference of NAESB Standards (“Schedule 24”) of the ISO OATT to include certain updated business practice standards adopted by the Wholesale Electric Quadrant (“WEQ”) of the North American Energy Standards Board (“NAESB”) and incorporated by reference in the Commission’s regulations through Order No. 676-I (the “Schedule 24 Revisions”). 1 16 U.S.C. § 824d (2006 and Supp. II 2009). 2 Standards for Business Practices and Communication Protocols for Public Utilities, Order No. 676-I, 170 FERC ¶ 61,062 (2020) (“Order No. 676-I”). 3 Capitalized terms used but not otherwise defined in this filing have the meanings ascribed thereto in the ISO’s Transmission, Markets and Services Tariff (the “ISO Tariff”). Section II of the ISO Tariff contains the Open Access Transmission Tariff (the “ISO OATT”). 4 Under New England’s RTO arrangements, the rights to make this filing of changes to Schedule 24 of the ISO OATT under Section 205 of the FPA are the ISO’s.
    [Show full text]
  • October 11, 2019 VIA ELECTRONIC FILING
    October 11, 2019 VIA ELECTRONIC FILING Honorable Kimberly D. Bose, Secretary Federal Energy Regulatory Commission 888 First Street, N.E. Washington, DC 20426 Re: ISO New England Inc. and New England Power Pool, Docket No. ER20-___-000; Transmission Planning Improvements Dear Secretary Bose: Pursuant to Section 205 of the Federal Power Act, 1 ISO New England Inc. (the “ISO”) joined by the New England Power Pool (“NEPOOL”) Participants Committee2 (together, the “Filing Parties”), hereby jointly3 submit proposed tariff revisions to enhance the competitive transmission solicitation process and make other improvements to the ISO’s transmission planning process (collectively, “Transmission Planning Improvements”). The Filing Parties are joined by the Participating Transmission Owners Administrative Committee (the “PTO AC”) on behalf of the Participating Transmission Owners (the “PTOs”).4 The PTO AC joins in the revisions to Localized Costs in Section III.B.3 of this transmittal letter. The Tariff changes 1 16 U.S.C. § 824d (2006 and Supp. II 2009). 2 Capitalized terms used but not defined in this filing are intended to have the meaning given to such terms in the ISO New England Inc. Transmission, Markets and Services Tariff (the “Tariff”). Section II of the Tariff is the Open Access Transmission Tariff (“OATT”). 3 Under New England's Regional Transmission Organization arrangements, except as noted below, the rights to make this filing of changes to the OATT under Section 205 of the Federal Power Act are the ISO's. NEPOOL, which pursuant to the Participants Agreement provides the sole market participant stakeholder process for advisory voting on ISO matters, supported the changes reflected in this filing and accordingly, joins in this Section 205 filing.
    [Show full text]
  • 2021 Energy Efficiency Forecast Data Review and Verification: End Use Measure Data
    DECEMBER 7, 2020 | WEBEX 2021 Energy Efficiency Forecast Data Review and Verification: End Use Measure Data Energy Efficiency Forecast Working Group Tim Costa SYSTEM PLANNING ISO-NE PUBLIC Outline • Measure Data Collection Background • Measure Detail – New England Summary • Measure Detail - State Level • Measure Detail – Focus on Connecticut • Energy, Demand, and Cost by Measure ISO-NE PUBLIC 2 Disclaimer • This presentation and data representation are not intended to be used as cost effectiveness tests for Energy efficiency programs. The ISO has no position regarding cost effectiveness. • Measure data is sourced from Program Administrator submissions over the past energy efficiency Forecast data collection cycles. • The dataset is not complete, particularly in the area of dollars spent per measure type. Therefore, analysis is only presented where complete data are available. • All assumptions and conclusions from these representations are preliminary and for informational purpose only. ISO-NE PUBLIC 3 Background on Measure Data • 2012 Forecast – PA data collection process included request to report the measures in each program for 2008-2010, where available. • 2013 Forecast – PA data collection process included a request to report the relative percentage of energy savings for the 10 top measures in each program year 2011, where available. • 2014 Forecast – PA data collection process included a request to report the relative percentages of energy savings, demand savings, and dollars spent for the 10 top measures in each program for years
    [Show full text]
  • Finalized Auction Results Confirm Sufficient Capacity Resources for New England During 2024–2025
    FOR IMMEDIATE RELEASE Contact: Ellen Foley (413) 535-4139 Janine Saunders (413) 540-4408 Finalized Auction Results Confirm Sufficient Capacity Resources for New England during 2024–2025 Holyoke, MA—February 26, 2021—Finalized results confirm that New England’s annual capacity auction concluded with sufficient secured resources to meet projected electricity needs three years in the future. ISO New England Inc. filed the results today with the Federal Energy Regulatory Commission (FERC). The filing also includes a list of electricity resources committed to ensuring reliable power for New England for the same period. Capacity acquired and retained The 15th Forward Capacity Market (FCM) auction (FCA 15), conducted on February 8, procured capacity for the June 1, 2024 to May 31, 2025 capacity year. In total, commitments for 34,621 megawatts (MW) were secured. This capacity is comprised of 29,243 MW of generation, 3,891 MW of demand resources, and 1,487 of imports from New York, Québec, Canada and New Brunswick, Canada. More than 2,525 MW of new resources within New England secured obligations. Of this total, approximately 19 MW received their obligations under the renewable technology resource (RTR) designation, which is the last year for this exemption. The eligibility requirements to conduct a substitution auction were not met in this auction, so there are no results to report. Prices FCA 15 concluded with three different prices across four regional capacity zones: Northern New England (NNE), made up of Vermont, Maine and New Hampshire; Maine, which includes Maine alone and is nested within NNE; Southeast New England (SENE), comprising Northeastern Massachusetts, Greater Boston, Southeastern Massachusetts, and Rhode Island; and Rest of Pool (ROP), which includes Connecticut and western and central Massachusetts.
    [Show full text]
  • ISO New England Overview and Regional Update
    MARCH 3, 2021 ISO New England Overview and Regional Update Kerry Schlichting EXTERNAL AFFAIRS Eric Johnson DIRECTOR, EXTERNAL AFFAIRS ISO-NE PUBLIC ISO New England (ISO) Has More Than Two Decades of Experience Overseeing the Region’s Restructured Electric Power System • Regulated by the Federal Energy Regulatory Commission • Reliability Coordinator for New England under the North American Electric Reliability Corporation • Independent of companies in the marketplace and neutral on technology ISO-NE PUBLIC 2 ISO New England Performs Three Critical Roles to Ensure Reliable Electricity at Competitive Prices Grid Market Power System Operation Administration Planning Coordinate and direct Design, run, and Study, analyze, and the flow of electricity oversee the markets plan to make sure New over the region’s where wholesale England's electricity high-voltage electricity is bought needs will be met over transmission system and sold the next 10 years ISO-NE PUBLIC 3 Numerous Entities Including an Independent Board Provide Oversight of and Input on ISO’s Responsibilities ISO-NE PUBLIC 4 New England’s Power Grid Is Part of a Larger Electric Power System • Part of the Eastern Interconnection, one of four large power grids in North America – Interconnected through primarily alternating current (AC) transmission • Tied to Québec only through direct current (DC) transmission • 2003 blackout ushered in wide-area monitoring and mandatory reliability standards • Subject to reliability standards set by NERC and NPCC* * North American Electric Reliability
    [Show full text]
  • Connecticut Energy and Technology Committee Informational Forum on Storm Response and Rate Increases
    Connecticut Energy and Technology Committee Informational Forum on Storm Response and Rate Increases Testimony of ISO New England Anne George, VP External Affairs & Corporate Communications Eric Johnson, Director, External Affairs August 27, 2020: 10:30 a.m. via Zoom Thank you for inviting us to join you virtually to share what we do as New England’s independent system operator, and how we work closely with both our federal regulator—the Federal Energy Regulatory Commission—as well as with the states, and specifically, Connecticut. These comments address the announced topics of the hearing. Additional topics were raised during the hearing and we look forward to the opportunity to continue this conversation with the committee. ISO New England is responsible for ensuring the reliable operation of the New England electric grid, administering the region’s wholesale electricity markets, and conducting regional system planning and ensuring resource adequacy. The ISO is independent of companies in the marketplace, does not own transmission or generation assets, and has no financial interest in any companies participating in the region’s wholesale electricity markets. ISO New England, the wholesale markets that it administers, and the power system that it operates are regulated by the Federal Energy Regulatory Commission (FERC) and ultimately governed by the Federal Power Act (FPA). The Federal Power Act also grants states the authority to determine the resource mix within their jurisdictions, as well as set retail electricity prices. The balance created by the FPA among the states and the federally regulated ISO shapes the electricity landscape that we have in New England today.
    [Show full text]
  • ISO New England Overview and Regional Update
    J A N U A R Y 2 7 , 2 0 1 7 | MONTPELIER , VT ISO New England Overview and Regional Update Vermont House Committee on Energy and Technology Vermont Senate Committee on Natural Resources and Energy Eric Johnson and Molly Connors EXTERNAL AFFAIRS ISO-NE PUBLIC Overview of Presentation • About ISO New England • Electric Grid At-a-Glance • Strategic Planning • Resource Developments • Transmission Developments ISO-NE PUBLIC 2 ISO New England (ISO) Has Two Decades of Experience Overseeing the Region’s Restructured Electric Power System • Regulated by the Federal Energy Regulatory Commission • Reliability and Planning Coordinator for New England under the North American Electric Reliability Corporation • Independent of companies in the marketplace and neutral on technology ISO-NE PUBLIC 3 Reliability Is the Core of ISO New England’s Mission Fulfilled by three interconnected and interdependent responsibilities Overseeing the day-to-day operation of New England’s electric power generation and transmission system Managing comprehensive regional power system planning Developing and administering the region’s competitive wholesale electricity markets ISO-NE PUBLIC 4 Numerous Entities Including an Independent Board Provide Oversight of and Input on ISO’s Responsibilities ISO-NE PUBLIC 5 Ensuring Reliable Power System Operations Is a Major Responsibility • Maintain minute-to-minute reliable operation of region’s generation and transmission system • Perform centralized dispatch of the lowest- priced resources • Coordinate and schedule maintenance outages
    [Show full text]
  • Summary of ISO New England Board and Committee Meetings September 13, 2019 Participants Committee Meeting
    NEPOOL PARTICIPANTS COMMITTEE SEP 13, 2019 MEETING, AGENDA ITEM #4 Summary of ISO New England Board and Committee Meetings September 13, 2019 Participants Committee Meeting Since the last update, the Compensation and Human Resources Committee met by teleconference on August 21. In addition, the Audit and Finance Committee, the Markets Committee, the System Planning and Reliability Committee, and the Nominating and Governance Committee each met in Holyoke on August 22. Please note that the committees are meeting again on September 12, as is the Board, which will hold its “annual” meeting on that date. At the annual meeting, the Board elects officers and directors and establishes committee assignments. We will provide the committee updates on our usual schedule, i.e., in time for the October Participants Committee meeting. However, I will also provide an oral update at the September 13 meeting regarding Board resolutions to the extent they involve changes in the Board’s leadership, including committee leadership. I will revise and repost this report after the September 13 meeting to include the details of committee membership. The Compensation and Human Resources Committee met in executive session to review the Company’s succession and development plans. The Audit and Finance Committee reviewed a report from the Code of Conduct Compliance Officer and also agreed to recommend that the Board adopt two changes to the Code of Conduct at the Board’s September meeting. (If the Board approves these changes, we will report on them in the next CEO report.) Next, the Committee received an update on internal audit activities, as well as highlights of recent audits.
    [Show full text]
  • 2019 Northeastern Coordinated System Plan ISO New England, New York ISO, and PJM
    2019 Northeastern Coordinated System Plan ISO New England, New York ISO, and PJM FINAL April 28, 2020 2019 Northeastern Coordinated System Plan Contents Contents ........................................................................................................................................................ ii Figures .......................................................................................................................................................... iii Tables ........................................................................................................................................................... iii Preface ......................................................................................................................................................... iv Executive Summary ....................................................................................................................................... v 1. Interregional Transmission Planning and Cost-Allocation Requirements ................................................ 1 1.1 Interregional Coordination Requirements ................................................................................................. 2 1.2 Cost-Allocation Requirements ......................................................................................................................... 2 2. Implementation of the ISO/RTO Planning Processes................................................................................ 3 2.1 PJM ..............................................................................................................................................................................
    [Show full text]
  • Assumptions for Calculating the Installed Capacity Requirement and Related Values for the 2024-2025 Forward Capacity Auction (FCA 15)
    JUNE 30, 2020 | WEBEX Assumptions for Calculating the Installed Capacity Requirement and Related Values for the 2024-2025 Forward Capacity Auction (FCA 15) Power Supply Planning Committee Meeting Manasa Kotha SENIOR ENGINEER, RESOURCE STUDIES AND ASSESSMENTS ISO-NE PUBLIC Objective of this Presentation • Review the assumptions used in the development of the Installed Capacity Requirement (ICR) and related values*: – Transmission Security Analysis (TSA) – Local Resource Adequacy Requirement (LRA) – Local Sourcing Requirement (LSR) – Maximum Capacity Limit (MCL) – Marginal Reliability Impact Demand Curves (MRI Demand Curves) – Hydro Quebec Installed Capability Credits (HQICCs) *The ICR, LSR, MCL, the MRI Demand Curves and HQICCs are collectively referred to as the ICR- Related Values ISO-NE PUBLIC 2 Modeling the New England Control Area for FCA 15 • The General Electric Multi-Area Reliability Simulation model (GE MARS) is used to calculate several of the ICR-Related Values • Internal transmission constraints are not modeled in the ICR calculation. All loads and resources are assumed to be connected to a single electric bus – Internal transmission constraints are addressed through the LSR and MCLs • A LSR will be calculated for the import-constrained Southeast New England (SENE) Capacity Zone, consisting of the NEMA/Boston, SEMA and RI Load Zones • MCLs will be calculated for two export-constrained Capacity Zones: the Maine Capacity Zone and the Northern New England (NNE) Capacity Zone, consisting of the combined Load Zones of Maine, New
    [Show full text]
  • November 5, 2019 VIA ELECTRONIC FILING the Honorable Kimberly D
    November 5, 2019 VIA ELECTRONIC FILING The Honorable Kimberly D. Bose, Secretary Federal Energy Regulatory Commission 888 First Street, NE Washington, DC 20426 Re: ISO New England Inc., Docket No. ER20-___-000, Filing of Installed Capacity Requirement, Hydro Quebec Interconnection Capability Credits and Related Values for the Fourteenth FCA (Associated with the 2023-2024 Capacity Commitment Period) Dear Secretary Bose: Pursuant to Section 205 of the Federal Power Act (“FPA”),1 ISO New England Inc. (the “ISO”) hereby electronically submits to the Federal Energy Regulatory Commission (“FERC” or “Commission”) this transmittal letter and related materials that identify the following values for the 2023-2024 Capacity Commitment Period,2 which is associated with the fourteenth Forward Capacity Auction (“FCA 14”): (i) Installed Capacity Requirement (“ICR”);3 (ii) Local Sourcing Requirement (“LSR”) for the Southeast New England (“SENE”) Capacity Zone;4 (iii) Maximum Capacity Limits (“MCLs”) for the Maine Capacity Zone and the Northern New England (“NNE”) Capacity Zone;5 (iv) Hydro Quebec Interconnection Capability Credits (“HQICCs”); and (v) Marginal Reliability Impact (“MRI”) Demand Curves.6 The ICR, LSR for the SENE Capacity Zone, MCLs for the Maine Capacity Zone and the NNE Capacity Zone, HQICCs, and 1 16 U.S.C. § 824d (2019). 2 The 2023-2024 Capacity Commitment Period starts on June 1, 2023 and ends on May 31, 2024. 3 Capitalized terms used but not otherwise defined in this filing have the meanings ascribed thereto in the ISO’s Transmission, Markets and Services Tariff (the “Tariff”). 4 The SENE Capacity Zone includes the Southeastern Massachusetts (“SEMA”), Northeastern Massachusetts (“NEMA”)/Boston and Rhode Island Load Zones.
    [Show full text]