News Release

August 20, 2008

Revised Nodal Schedule Pushed to October

The revised nodal program schedule will be presented at the October board of directors meeting, instead of September as earlier indicated, Chief Information Officer and Nodal Executive Program Director Ron Hinsley reported to the ERCOT Board of Directors Tuesday.

During a lengthy discussion about the project delay, members of the board and Public Utility Commission expressed strong concerns over the status of the nodal project and directed the ERCOT staff to provide a full re-assessment of the project status as quickly as possible. 

Since the market redesign delay announcement in May, the nodal team has undergone personnel changes in leadership and in program management and begun working on a new integrated schedule.  Hinsley said the new organization is better organized, and will have far better information and awareness going forward. 

In moving to the integration phase, new issues came to light because the projects had generally been developed in silos independent of each other.  Also, additional vendor delays were identified during the re-planning effort. At the project level, these issues led to further analysis that required ERCOT to go back to its vendors and request revised schedules from them.   

Prior to integration, the project teams had been working independently to deliver their respective deliverables, so it was not until preparation of the integrated, program-wide schedule that program-level dependencies and functionality issues were revealed, Hinsley reported in the nodal program update

Based on lessons learned from cumulative data and recommendations from the stakeholder taskforce overseeing nodal protocol implementation, the new integrated schedule will:

  • Deliver a schedule with a clear, achievable date;
  • Allow sufficient time for market participant testing;
  • Include additional time for complexities uncovered during the development of the integrated schedule and issues that may arise when all the pieces are put together;
  • Provide time for testing and break-fix cycles (time to resolve defects as they are discovered).

     

    Hinsley reported progress in the status of the CIM Importer (Common Information Model importer that converts data from the Network Model Management System into the Energy Management System).  It is now in testing at the vendor location, and ERCOT subject-matter experts are on-site to identify and resolve issues during the testing. 

    Several board members asked for a detailed assessment of the program status as well as a vendors’ “report card” at a special board meeting to be called shortly. 

    OTHER BOARD ACTION

    Also in the meeting, the board voted to approve Oncor’s dynamic reactive project, estimated to cost $35 million and proposed to be in service by summer 2010.  ERCOT staff and the Technical Advisory Committee supported the project which addresses the need for dynamic reactive support in the Dallas-Fort Worth area. 

    The board approved several Protocol Revision Requests (PRR) and Nodal Protocol Revision Requests: NPRR 114, NPRR 127, NPRR 132, NPRR 133  and NPRR 097; PRR 766PRR 753 was tabled until next month to allow additional time to work on the language. 

    STAFF REPORT SUMMARIES

    Staff reports for Tuesday’s board meeting included: 

    System Planning Report

    • ERCOT is currently tracking 243 active generation interconnect requests totaling about 104,000 megawatts (MW); includes almost 52,000 MW of wind generation
    • New Interconnect Agreements signed last month included:
      • Barney Davis re-powering in Nueces County for 360 MW
      • Nueces Bay re-powering In Nueces County for 327 MW
    • 293 MW of new wind generation began commercial operations, bringing total installed wind capacity to 5,812 MW.
    • 282 MW of wind generation with interconnect agreements were cancelled by the developers.
    • Regional planning is reviewing proposed transmission improvements totaling $608 million
    • Transmission projects approved in 2008 to date total $182 million.
    • All projects in engineering, routing, licensing and construction total $3.8 billion.
    • Transmission projects completed through July 2008 total $375 million 

    Market Operations Report

    Retail Activity

    • June switch activity was significantly higher than last year
    • Residential switching away from former affiliated Retail Electric Providers (REP) continues to increase
    • Unplanned systems outage in June impacted some transaction processing performance measures  

    Wholesale Activity

    • Settlements and billing performance measures continued strong performance
    • Energy services reported an 11.7 percent increase in market volume, likely due to higher summer temperatures in 2008 than 2007
    • Summary of balancing energy price data and total load data shows a continued increase in natural gas prices; hub price increases are lower than prior months.
    • One new REP was added (Texas Power, LP.).  Four new Qualified Scheduling Entities (QSE) were added (PPM Energy, EC and R Panther Creek, Integrys Energy Services, and Invenergy McAdoo).  One QSE was deleted (Entergy Solutions Supply).

    Grid Operations Report

    • The June peak demand of 59,508 MW exceeded the June 2007 peak, but was below the all-time actual peak of 62,339 MW and forecast 2008 peak of 63,702 MW
    • Day-ahead load forecast error for June was below 3 percent.
    • Zonal transmission congestion increased from June 2007 due mainly to higher load and North-South congestion.
    • Storms in the west caused a number of transmission outages and some load was temporarily transferred to Southwest Power Pool, the neighboring grid.
    • ERCOT implemented step 1 of the emergency procedures on June 18 when responsive reserves dropped below 2500 MW; Load was 2,100 MW higher than the day-ahead load forecast due to temperature predictions being lower than actual.
    • No “excused” periods for schedule control error performance were reported in July due to implementation of Protocol Revision Request (PRR) 762.
    • ERCOT is developing an operational reliability assessment tool with expected implementation by the end of 2008.  

    Information Technology Report

    • Retail and Wholesale Systems Performance
      • Retail transaction processing year-to-date performance continues to be below the service level target.
      • Wholesale batch operations’ July performance was impacted by a data issue that caused a job to abort and be backed out and rerun. The delay caused by this incident required several days of catch up time to meet the success criteria.
    • Market and grid control systems reported no problems in July in real-time balancing market or frequency control.  
    • Nodal systems performance reported a software interface issue within the Energy Management System (EMS) subsystems is causing the State Estimator to fail. The vendor is developing a fix which will be applied in a future release of EMS.  

    CPS1 Forecasting Presentation

    Vice President of System Operations Kent Saathoff presented a report on CPS1 forecasting.  CPS1 is a measure of how well ERCOT is matching generation with demand (i.e., controlling frequency). 

    Board meeting documents are posted on posted online with the August 19 meeting agenda

  • The Electric Reliability Council of Texas (ERCOT) manages the flow of electric power to more than 25 million Texas customers -- representing about 90 percent of the state‚Äôs electric load. As the independent system operator for the region, ERCOT schedules power on an electric grid that connects more than 46,500 miles of transmission lines and 650+ generation units. It also performs financial settlement for the competitive wholesale bulk-power market and administers retail switching for nearly 8 million premises in competitive choice areas.

    ERCOT is a membership-based 501(c)(4) nonprofit corporation, governed by a board of directors and subject to oversight by the Public Utility Commission of Texas and the Texas Legislature. Its members include consumers, cooperatives, generators, power marketers, retail electric providers, investor-owned electric utilities, transmission and distribution providers and municipally owned electric utilities.

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