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Texas Nodal Team Cost Benefit Group

Texas Nodal Team Cost Benefit Group. Background to Standard Market Design in New England. March 2, 2004 Michael Taniwha Manager, Market Administration ISO New England Inc. Overview of Presentation. History of NEPOOL & ISO New England Inc.

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Texas Nodal Team Cost Benefit Group

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  1. Texas Nodal TeamCost Benefit Group Background to Standard Market Design in New England March 2, 2004 Michael Taniwha Manager, Market Administration ISO New England Inc.

  2. Overview of Presentation • History of NEPOOL & ISO New England Inc. • Building Blocks & Interim Wholesale Electricity Market • Evolution of CMS/MSS project to SMD • Standard Market Design (SMD) Project • SMD Market Features • Questions

  3. New England Power Pool (NEPOOL) • NEPOOL Established in November 1971 • Outcome of the formation of the Northeast Power Coordinating Council following 1st Great Northeast Blackout in 1965 • Voluntary association of vertically integrated utilities • Utility members had direct and influencing stake in NEPOOL • Objectives for forming NEPOOL: • Manage System Reliability • Improve dispatch efficiency through economic dispatch • Key characteristics of NEPOOL • Closed “tight” power pool with central dispatch • Economic dispatch and pool-to-pool savings shared by member utilities

  4. Wholesale Market ISO New Englandand what do we do? • INDEPENDENT system/market operator based in Holyoke, MA • Private, not-for-profit corporation created on July 1, 1997 • Outcome of FERC 888 Order • Responsible for system reliability, administration and oversight of wholesale electricity markets, regional transmission tariff, and regional planning • 400 employees

  5. 320 mi. 520 km New England’s Electric Power System ISO and satellite facilities • 14 million people • 6 state region • One contiguous control area • 350+ generators • 200+ market participants • 8,000+ miles oftransmission lines • 4 satellite control centers • Interconnections to 3 neighboring systems • 30,000 MW of installed generating capacity • Peak load 25,348 MW 400 mi. 650 km

  6. Building Blocks: The New England Wholesale Market Story • Solid Foundation of central dispatch • Single, region-wide reliability andeconomic dispatch since 1971 • Open-Access Transmission Tariffin place: 1997 • Regional regulatory infrastructure • 5 out of 6 states with restructuredretail markets • Highest level of divestiture in U.S. • Highly diverse marketplace with many competing interests • Wholesale (interim) market opened: May 1999

  7. Drivers for changing Interim Market • Interim market had recognized deficiencies • One energy clearing price (ECP) for entire region • Ex-ante pricing • No Day-Ahead Market • These deficiencies had negative impacts on the market • Significant risks for generators and load • Inability to adjust positions intra-day • Management of congestion in real time difficult because lack of locational marginal pricing • Inability to hedge energy and congestion uplift

  8. CMS/MSS* Project • New England’s CMS/MSS Project Initiated 1999 • Proposal filed with FERC in March 1999 • Green fields design • Phase I Schedule Q1 2003 • Phase II Schedule Q1 2004 • Phase I CMS/MSS budget: $73 million • Phase II CMS/MSS budget (total): $100 - $120 million * Congestion Management System (CMS) and Multi-Settlement System (MSS)

  9. CMS/MSS Project cont.. • Risks • Unproven Market Design • Non-convergence with Northeast markets • Problems with CMS/MSS schedule and budget emerge • After 2 years of CMS/MSS project goal posts still some years and many millions away • Solution Identified • Strategic decision made to move to a Standardized Market Design in March 2001 • PJM market identified as blue print for New England market design

  10. Standard Market Design (SMD) project • Solution presented to NEPOOL stakeholders May 2001 • Joint filing to FERC submitted by NEPOOL and ISO-NE June 2001 • Standard Market Design justification • Reduce risk by implementation of proven market design • Use of existing software reduce development costs and risks • Reduce ongoing support and maintenance costs • Provide market convergence between PJM and ISO • Facilitate transactions in Northeast though uniform market rules • Satisfy major requirements of CMS/MSS system design • Implementation of CMS/MSS features reduced by 9-12 months and $20 to $40 million

  11. SMD Project cont.. • New England’s SMD based on PJM’s market design • Fork lifted Market Rules & Manuals from PJM • Fork lifted software from PJM with modifications from vendor • Enhanced by ISO-New England in several areas • Comprehensive business process documentation developed • Manuals and business process documentation are public • Losses included in LMPs • Hydro units can offer energy with daily MWh limits • FTR’s not grand fathered • Customizations allowed ONLY for physical power system differences

  12. SMD Project Benefits • SMD provides strong market foundation to build market improvements upon • Market and software standardization allows sharing of knowledge and training between ISO’s and RTO’s staff • PJM, NYSIO, ISO-NE and MISO as examples (no need to reinvent the wheel each time) • New England now working on further market enhancements • Co-optimization of energy and reserves markets • Locational ICAP market • Forward Reserves market (in operation)

  13. SMD Development Timeline 2001 2002 2003 2nd Quarter 3rd Quarter 4th Quarter 1st Quarter 2nd Quarter 3rd Quarter 4th Quarter 1st Quarter 2nd Quarter Mkt Rules Development & Filings Post Production Hardware Acquisition & Installation Development - Settlements Systems Development - Market Operations (CMS/MSS systems) Testing - Planning and Product Testing Testing - Integration & Performance Testing Market Trials Production Cutover & Data Conversion Program & Life Cycle Management  Business Process/Procedures/Training  Participant Training Go Live3/1/03

  14. Scope of SMD • Energy Markets • Day-Ahead Market (financial forward market) • Real-Time Market (spot market) • Ancillary Services • Regulation Market • Forward Reserve Market (from January 1, 2004) • Transmission Rights • Financial Transmission Rights (FTR) auction • Qualified Upgrade Awards (for non-tariff transmission investments) • Capacity Market • Installed Capacity (ICAP)

  15. Key Features of SMD • Locational Marginal Pricing (LMP) • Congestion and losses are explicitly priced at all nodal and zonal locations • Enhanced risk management tools • Bilateral contracts • Day-Ahead Market (DAM) • Real-Time Market • Financial Transmission Rights (FTRs) • Auction Revenue Rights (ARRs) • Market Monitoring and Mitigation

  16. Key Features of SMD • Multi-settlement Energy Market • Day Ahead and Real-Time Market Settlement • Differences between energy cleared in the Day-Ahead Market and Real-Time production/consumption settled at the Real-Time price • DAM settlement is financially binding, providing price certainty and powerful incentives for Real-Time performance • ICAP resources must offer into the Day-Ahead Market (mandatory) • Participation of demand and virtual supply/demand in the Day-Ahead Market creates a more balanced, liquid, and competitive marketplace

  17. Questions? Michael Taniwha Manager, Market Administration ISO New England Inc. Tel: (413) 535 4110 Email: mtaniwha@iso-ne.com Web: www.iso-ne.com

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