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New England Regional System Plan (RSP05) Administrative

New England Regional System Plan (RSP05) Administrative. Michael I. Henderson PAC03 April 06, 2005. Agenda. Regional System Horizon-Year Study Status of Proposed Generating Units FERC Wind NOPR New England Operable Capacity Analysis Projected New England Installed Capacity Requirements

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New England Regional System Plan (RSP05) Administrative

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  1. New England Regional System Plan(RSP05)Administrative Michael I. Henderson PAC03 April 06, 2005

  2. Agenda • Regional System Horizon-Year Study • Status of Proposed Generating Units • FERC Wind NOPR • New England Operable Capacity Analysis • Projected New England Installed Capacity Requirements • Update on Renewable Portfolio Standards • Air Emissions Analysis

  3. Announcements • Interregional Planning • Draft Northeast Coordinated System Plan To Be Posted at www.interiso.com • Stakeholder Meeting tentatively scheduled for June 2 at a Northeast location TBD • April 05 Transmission Update posted at • http://www.iso-ne.com/committees/planning_advisory_committee/RSP_2005/April%20%2705_ISO-NE_Project_Listing_%28FINAL-REDACTED%29_03-30-05.xls

  4. Administrative • Please submit questions and comments to: teac_matters@iso-ne.com • Next meetings: • 5/04/05 • With RC at NGRID Energy Institute • 6/15/05 – Tentative Date • To Be Coordinated with RC • At NGRID Energy Institute • 8/17 – NEW DATE • Page turn at location TBD • 9/7 – NEW DATE • Public Meeting at Boston Location

  5. Regional System PlanRSP0510-Year Plan and Horizon-Year Study Michael I. Henderson PAC03 April 6, 2005

  6. RSP Ten-Year Plan • Assesses Bulk Power System Needs and Conditions Covering 2005-2014 • System Assumptions • Resource Adequacy • Transmission Adequacy • Considers Known Improvements • Identifies Needed System Improvements • Resources • Transmission

  7. RSP05 Deliverables Ten-Year Plan • Complete Resource Adequacy Analysis • Covering a 10-Year Horizon (2005-2014) • LOLE Analysis • Operable Capacity Analysis • Identify Needed Resources • Air Emissions Analysis • Projections • Impact of Renewable Portfolio Standards (RPS) • Comprehensive Area Transmission Review of the New England Bulk Power Transmission System (NPCC Request) • Study Year 2009 • Includes NSTAR 345kV Project and all Projects with 18.4 Effective 4/1/04 • Inter-Area Assessment (NPCC) • Update Required Transmission Improvements • Develop work plan for creating a more robust 10-year internal New England Plan

  8. What is a Horizon-Year Study? • Conceptual Analysis to Provide Long-Term Direction in System Development • Roadmap of Possible Long-Term System Improvements • Pick a High Load Level • 40,000 MW? • Scenario Analysis • Provides Indication of Scope of Transmission Development that Could be Required to Address Various Geographic Scenarios of Generation Development • Creates a Target System

  9. Benefits of a Horizon Year Study • Ensures Consistency of 5 and 10-Year Improvements with the Longer Term Needs • Promotes Effective Use of Transmission Investment • Provides Direction on Use of Rights-of-Way • Evaluates whether 345kV and 115kV transmission voltage classes meet longer-term needs

  10. Considerations for Long-Term Horizon Year Study • Identify Assumptions • Load Level: 40,000 MW? • Generation Expansion Scenarios • Type and MW • Location • Additions to meet Renewable Portfolio Standards • Effects of Implementation of Regional CO2 Cap • Load Response Scenarios • MW • Location • Examine Application of Voltage Classes other than 345kV and 115kV • Consider Application of New Technologies

  11. RSP05 DeliverablesRoadmap of Long-Term Horizon Study • Initiate Long-Term Conceptual Transmission Adequacy Analysis • Study Plan • System Conditions • Schedule • Priorities • Identify Simulation Tools and Methods

  12. Status of Proposed Generating Units Kevin Mankouski ISO-NE System Planning PAC03 April 06, 2005

  13. ISO-NE Interconnection Queue • Queue first published November 1997 as part of implementation of the NEPOOL Tariff (3/1/97) in compliance with FERC Order 888 • Includes all planned generation projects not yet interconnected as of March 1, 1997 • Includes Generator Interconnection Requests and Requests for Elective Transmission: Merchant Transmission Interconnection and Transmission Expansion

  14. ISO-NE Interconnection Queue (Cont’d) • Overall Statistics* • 134 Generator Interconnection Requests totaling 46,859 MW • 74 have withdrawn 31,739 MW • 2 have been temporarily commercial totaling 93 MW • 28 are presently commercial totaling 11,582 MW • 29 are active in the interconnection process under the ISO-NE Tariff totaling 3,432 MW • 38 Merchant Transmission and Elective Transmission Requests • 36 have withdrawn • 1 is commercial: Cross Sound Cable • 1 is active: Northern Reliability Project *Note: All capacities are based on the project ratings in the Study Queue as of 3/29/05

  15. ISO-NE Generation Interconnection Queue:Active Generation Projects – MW* *Note: All capacities are based on the project ratings in the Study Queue as of 3/29/05

  16. New England Capacity Mix

  17. Capacity* of Generation Interconnection Requests by Application Year *Note: All capacities are based on the project ratings in the Study Queue as of 3/29/05

  18. Capacity* of Generation Interconnection Requests by RSP Zone *Note: All capacities are based on the project ratings in the Study Queue as of 3/29/05

  19. Number of Generation Interconnection Requests

  20. Number of Transmission Project Interconnection Requests

  21. Mean MW Size of Generation Interconnection Requests* *Note: All capacities are based on the project ratings in the Study Queue as of 3/29/05

  22. FERC Wind NOPR Kevin Mankouski ISO New England

  23. FERC Wind NOPR • FERC released NOPR 1 -24-05 on interconnection for wind energy and other alternative technologies • Special accommodations for uniqueness of non-synchronous generating technologies • American Wind Energy Association petition • Low Voltage ride-through capability standard • Power factor criteria 0.95 lagging/leading • Requires transmission providers to participate in formal process to develop, update and improve models and specifications for wind plants • Allow wind interconnection customers to “Self-Study” feasibility and enter Interconnection Queue w/o detailed specification of the project

  24. ISO-NE Position • Provide level playing field • Non-discriminatory treatment • Maintain reliability in accordance with existing reliability standards • Wind should meet the same performance and data collection standards as other types of generation in New England

  25. ISO-NE Position: Low Voltage Ride-Through • Do not adopt generator voltage-time characteristic requirement • New England practice is that a generator should stay on-line for normal criteria faults electrically close that do not require the clearing of the generator (i.e. system performance based) • Generator specific criteria creates potential reliability shortfalls if the generator does not ride through that would in-turn result in cost allocation issues for any mitigation • Default generator standard may result in disincentive to wind industry to improve • Generators can meet the system performance based standard by either enhancing wind turbine performance or adding parallel devices to support voltage (e.g. STATCOM)

  26. ISO-NE Position: Supervisory Control and Data Acquisition (SCADA) • Wind Generators should meet the existing ISO-NE Operating Procedures 14 and 18. • Provide ways to lower dispatch of wind as required to maintain system security following contingency conditions • Provide for any future procedures that may require the wind generator to telemeter operating data to ISO NE to better enable the coordination of wind into day-ahead markets and minute-to-minute operations

  27. ISO-NE Position :Power Factor Design Criteria (Reactive Power) • All new generation should have the potential to generate power with a power factor range of at least 0.95 leading to at least 0.95 lagging throughout its output range • Consistent with today’s ISO-NE LGIA requirement • Should support (not necessarily dynamically) a voltage schedule at the point of interconnection with the utility system • Larger Projects Should Provide Dynamic Voltage Support • Enables smaller projects that have less impact on system reliability to utilize switched capacitors and not provide dynamic voltage support • Larger projects demonstrating the need for dynamic voltage support may address by utilizing generators utilizing power electronic technology (e.g. wound rotor induction generator) or an alternative add-on dynamic voltage control device (e.g. synchronous condenser or STATCOM)

  28. ISO-NE Position: Models and Self-Study Feasibility • Self-Study Provisions Not Necessary • Treat all generator customers consistently • Historically Interconnection enabled generator modifications as an alternative to network upgrades (e.g. excitation system upgrades) • Section 4.4.4 of the pro forma LGIP enables the Transmission Provider to evaluate whether any generator modifications (change in technical parameters after the onset of the System Impact Study) are Material Modifications that would require restudy and a new Queue Position • Planning Study Models • Generator Customer should provide a model, parameters and documentation of the model to support its validity whenever an industry-wide formally adopted model does not exist • Wind generators should be treated as any other generator in regard to use of non Industry-wide adopted models where updating for any deficiencies in the models is required within a reasonable time period

  29. New England Operable Capacity Analysis Scott Hodgdon ISO New England April 6, 2005

  30. What is a New England Operable Capacity Analysis? • Determines New England’s ability to operate the power system under specific scenarios using: • Peak loads (50/50 & 90/10) • Reserve requirements • Available capacity • Existing and new • Taking into account potential unit outages

  31. Changes to New England Operable Capacity Analysis From RTEP04 • Updated load forecast • Updated capacity • Reflects recent unit deactivations/retirements • Devon 7 & 8 (214 MW) • Kendall Jet 2 (15 MW) • Updated allowance for unplanned outages • Forced and maintenance outages scheduled less than 14 days in advance

  32. Projected New England Capacity Situation (50/50 Load Forecast) Does not include tie line benefits or OP-4 Actions

  33. Projected New England Capacity Situation (90/10 Load Forecast) Does not include tie line benefits or OP-4 Actions

  34. Projected New England Installed Capacity Requirements Covering Power Years 2005/2006 – 2015/2016 Presentation to the ISO Planning Advisory Committee April 6, 2005 National Grid Offices, Westborough MA

  35. Background The Installed Capacity Requirement (sometimes referred to as Objective Capability) is the amount of installed generating capacity that New England needs to meet the NEPOOL resource planning reliability criterion of 1 day in 10 years disconnection of non-interruptible customers. This criterion takes into account: • Possible levels of peak loads due to weather variations, • Impact of assumed generating unit performance, and • Possible load and capacity relief obtainable through the use ofISO-NE Operating Procedure no. 4 – Action During a Capacity Deficiency.

  36. Objective • This presentation provides information regarding the range of future New England installed generation requirements to meet the 1 day in 10 years LOLE resource planning reliability criterion. • The methodology and assumptions used in this analysis is consistent with those used in the development of the 2005/2006 New England Installed Capacity Requirements, except for the treatment of the reliability benefits associated with the HQ Phase II interconnection. In this analysis, the reliability benefits of interconnecting with neighboring Control Areas are modeled as tie benefits.

  37. Foreword • This analysis used the single areas Westinghouse/ABB Capacity Model Program to simulate system conditions covering 2005/06 through 2014/2015. • The majority of the assumptions used in this analysis has been reviewed with the PAC at the February 2, 2005 meeting. This presentation covers these assumptions again to facilitate your understanding of the analysis results. • The assumptions will be covered briefly unless there is a specific request to cover a particular assumption in detail.

  38. Loads Capacity Existing Additions Attrition Purchases and Sales Daily Cycle Hydro Ratings ICAP Capable Load Response Program Assets SWCT RFP Unit Availability Tie Benefits Other OP-4 Load Relief Proxy Units for meeting reliability Assumptions

  39. Loads • Based on CELT 2005 forecast • Weekly distributions represented with: • Expected value (mean) • Standard deviation • Skewness • Annual peaks ranged from 26,355 MW for summer of 2005 to 30,180 MW for summer of 2014

  40. Capacity • Existing Capacity • Based on 2005 CELT Data • Assets within January 2005 Seasonal Claimed Capability (SCC) Report • Summer Rating – August 2004 SCC Report • Winter Rating – January 2005 SCC Report • Units categorized as “EMS” & “SO” units included • Energy Management System = 30,516 MW (S) & 32,878 MW (W) • Settlement Only resources = 238 MW (S) & 313 MW (W)

  41. Capacity • Capacity Additions • Ridgewood Generation (8.4 MW) • Kendall Steam 3 Reactivation (25 MW) • Kendall CT Reactivation (158 MW) • Proxy units (described later), if needed for reliability. • Capacity Attrition • No attrition assumed

  42. Capacity • Purchases and Sales • Purchases and Sales as reported in 2004 CELT Report (453 MW Net Purchase) • Daily Cycle Hydro Ratings • 50 Percentile value of daily flows assumed with adjustment (59 MW in July) to Installed Capacity Requirements.

  43. Load Response Assumptions • ICAP Capable Load Response Program • All capacity listed as of January 1, 2005 as “ready to respond” enrolled in: • Day-Ahead Demand Response Program • Real-Time Demand Response Program • Real-Time Profiled Response Program • Assets grouped by Program and Area • Assets assumed to have performance factors based on August 20, 2004 audit results and NERC Class Average EFORd values for known emergency generation.

  44. Assumed MW from Load Response Program EFOR values based on Aug. 20, 2004 audit results and NERC Class average data

  45. Unit Availability Assumptions - Non-Nuclear • 5-year average EFORd modeled • Forced Outage Rates (EFORd) determined using combination of NERC Class Average EFORd data and available New England GADs data. • NERC Class Average used Jan’00 – Feb’03 • Calculated EFORd using GADs used Mar’03 – Dec ’04 • Since Dec 04 data was not available,Dec 03 data is used for Dec 04.

  46. Unit Availability Assumptions - Nuclear • Analysis shows that New England Nuclear units performed better than the NERC Class Average EFORd • For Nuclear units, used ISO-NE calculated Jan’00 through Feb’03 EFOR and Mar’03 through Dec’04 EFORd. • Since Dec 04 data was not available,Dec 03 data is used for Dec 04.

  47. Results of 60-Month Average

  48. Tie Reliability Benefits • Tie Reliability Benefits from Hydro-Quebec, New Brunswick, and New York are modeled in the Westinghouse/ABB Capacity Model Program as resources • Three sets of tie benefits assumptions were considered • 0 MW • 1,000 MW • 2,000 MW

  49. OP-4 Load Relief • Load Relief values based on ISO-NE Operating Procedure No. 4 (OP-4) • 5% Voltage Reduction is based on 1.5% of the seasonal peak load as determined by Spring Voltage Reduction Test Results

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