Market Information System Grid and Market Conditions

News Release

October 21, 2009

ERCOT NEWS: October Board Meeting Highlights



Board Action Includes Protocol Revisions, 2010 Zone Boundary Elements

The Board of Directors for the Electric Reliability Council of Texas, grid operator and manager of the electric market for most of the state, approved 10 market rule changes and designation of transmission constraint boundaries for the 2010 congestion zones at Tuesday’s monthly meeting.  

The board approved designation of the "closely related elements" for the 2010 congestion zones and commercially significant constraints (CSCs).  Closely related elements (CREs) are transmission facilities that have similar characteristics to the CSCs and which act as a CSC when the CSC facilities are out of service.   

The approved list includes 25 CREs, including four new ones for 2010:

  • Rothwood – King 345A
  • Rothwood – Kuykendahl
  • Springvalley – McGregor
  • Springvalley – Cottonwood 

At its Sept. 15 meeting, the board approved the four zones and commercially significant constraints for 2010.  Tuesday’s vote was the final step in the board’s annual review of the zones and related constraints as required by market rules.  

The board approved ten Protocol Revision Requests  (PRR), and Nodal Protocol Revision Request (NPRRs), and sent one PRR back to the Technical Advisory Committee (TAC).

PRR 811, which establishes a requirement for wind units to provide ERCOT with their real-time production potential, was remanded to TAC with instructions for them to develop a consistent methodology for calculating wind production potential. 

Approved protocol revisions included:

  • PRR 817 – Cease Late Payment Charges for Defaulted Entities
    Enables ERCOT to cease charging late fees to defaulting entities prior to the initiation of the uplift process, provided that ERCOT has determined recovery of late fees is unlikely;
  • PRR 822 – Removing Access to Restricted Computer Systems, Control Systems and Facilities
    Improves protection of restricted computer systems, control systems and facilities; approved with revisions to indicate the protocol rule applies to cyber assets only;
  • PRR 823 – Clarifying Language for Resource 12-Month Rolling Planned Outage Schedule Format and Reporting Requirement
    Clarifies ambiguous language about when and how the outage information should be submitted;
  • PRR 829 – Total Transmission Capacity Correction
    Redefines the acronym "TTC" as "Total Transmission Capacity," instead of "Total Transfer Capability" to avoid confusion with "Total Transfer Capability" as used by the North American Electric Reliability Corporation; a comparable term but does not apply to ERCOT region since there is only one transmission system;
  • PRR 831 – Annual Transmission Congestion Rights (TCR) Auction Amount
    Revises the amount of TCRs sold in the annual TCR auction from 40 to 30 percent;
  • NPRR 174 – Fuel Index Price Modifications in Verifiable Startup and Minimum Energy Cost and Recovery of Exceptional Fuel Costs During Reliability Unit Commitment Intervals
  • NPRR 189 – Ancillary Service Deployment Clarification
    Clarifies the difference between ancillary service capacity deployment and energy deployment and how it affects Security-Constrained Economic Dispatch;
  • NPRR 191 – Synchronization of PRR 819, Changes to Support Revisions to the PUCT POLR and Expedited Switch Rules
    Synchronizes the Nodal Protocols with PRR 819;
  • NPRR 193 – Application of Nodal Implementation Surcharge in Verifiable Costs
    Allows generation resources to include in their verifiable costs the nodal implementation surcharge for periods while ramping up from breaker close to low sustained limit;
  • NPRR 195 – Removal of McCamey Congestion Management from Nodal Protocols
    Removes the unique congestion management procedures for the McCamey area from the Nodal Protocols, consistent with zonal protocol revisions made in PRR 810; the need to manage congestion related to high levels of wind generation is no longer unique to the McCamey area. 

The TAC report also included a report on PRR 828 which was rejected by TAC.  The PRR would have removed the exemption for wind units from the schedule control error performance metric.  TAC Chair Mark Bruce said that as follow-up to rejection of the PRR, TAC is investigating how ancillary service costs should be allocated to wind units and has assigned the task to a Wholesale Market Subcommittee task force.

Nodal Program Preps for Market Connectivity

ERCOT Chief Technology Officer Mike Cleary briefed the board on the nodal program’s preparations for market connectivity tests – the program’s next major milestone – and a market readiness effort which is rapidly gaining speed. 

Market connectivity, which begins on Oct. 28, will give ERCOT market participants access to the nodal market trials environment and the latest version of several software applications, enabling them to complete their own development activities. 

Full-scale market trials begin in early 2010. The nodal market remains on track for its December 2010 implementation. 

"There are no major defects in the system tests … there’s nothing on the critical path we see causing us any issues," Cleary said. "All lights are green." 

A revamped Readiness Center went live Tuesday on the ERCOT web site.  The center includes a readiness scorecard for ERCOT and market participants to measure their readiness for market trials and nodal’s go-live date. Metrics measuring a relevant market trials phase will be initiated on the scorecard and tracked accordingly. 

The nodal readiness team has also begun a series of 33 outreach site visits with market participants.  

ERCOT Controller Mike Petterson said the nodal program has recorded a $24.5 under-run in program costs since January 2009. He said $12.4 million will be used for delayed projects and work in future months, but proposed the remaining $12.1 million be added to the board’s discretionary fund. Combined with a $14 million increase to the fund due to an interest rate hedging program and changes in nodal borrowing levels, the discretionary fund (contingency funding) now stands at $84.8 million, an increase of $26.2 million from $58.6 million. 

Petterson also presented a re-forecasted estimate-to-complete total of $98.3 million in direct project costs. 

"We’re trying to cover the known work that’s left, but we now have nearly as much money in the contingency fund as we have to complete the program," Cleary said.

CEO Report: Met Center Power Outages

CEO Bob Kahn briefed the board on two power outages at ERCOT’s Austin facility earlier this month.  The facility’s control room and data center were in backup mode during the outages, so there was no effect to reliability, markets or operations during the outages.  However, database issues caused by the outages will affect implementation timelines for the advanced metering and the Providers-of-Last-Resort (POLR) projects, Kahn said.   

The advanced metering core functions will be implemented as scheduled on Nov. 21, but the remaining non-core functions will be delayed to Dec. 14, still ahead of the Jan. 31 regulatory deadline. 

The POLR project will be implemented in three phases, instead of two, but is planned for completion by May as originally scheduled.

Staff Analyses, Reports Presented

ERCOT staff presented several special reports on recent market changes: 

Local Congestion and OOME

  • Reviewed the increase in local congestion and Out-of-Merit Energy (OOME) volume between 2008 and 2009;
  • Concluded the increases were due to a rapid buildup in wind capacity – from 4,614 megawatts (MW) in January 2008 to 8,111 MWs  in December 2008, concentrated primarily in the West Zone – and to several major transmission outages;
  • Listed several pending transmission projects estimated for completion in December 2009, October 2010, December 2011, and December 2013 (numerous transmission projects that are part of the Competitive Renewable Energy Zones process), that will mitigate congestion in the future.

NSRS Cost Analysis - PRR 776 Implementation

  • Analyzed the effect of changes to the procurement methodology for Non-spinning Reserve service (NSRS), effective Nov. 1, 2008, and PRR 776, effective May 22, 2009, which changed NSRS requirements;
  • Concluded that the new method resulted in procuring more NSRS but that the overall NSRS costs went down, due in part to lower fuel costs and the increased market certainty. 

Seasonal Analysis of PRR 763

  • Analyzed the impact of PRR 763, effective July 2008, which requires the use of the AWS Truewind forecast in the day-ahead resource plans;
  • Concluded that performance in meeting the 80 percent target indicated improvement from November 2008 to August 2009. 

Regular monthly staff reports included:

Market Operations Report

  • Very strong retail activity in 2009 compared to 2008;
  • Switching from the incumbent retail electric provider is higher in all customer classes;
  • Balancing Energy Price Data – Load zone prices significantly lower in 2009 compared to 2008.

Grid Operations and Planning Report

  • August peak demand was 62,056 MW (Aug. 5) – 1,397 MW lower than the all-time peak demand of 63,453 MW (July 13, 2009) and less than the forecasted peak of 63,356 MW;
  • September  peak demand was 55,210 MW (Sept. 3);
  • 224 active generation interconnection requests totaling more than 79,000 MW
  • 8,515 MW wind capacity on line as of September 2009 – a 180 MW increase from August
  • Reliability-must-run contract executed with Luminant for Permian 6, effective Oct. 1 – Dec. 31, 2009. 

Financial Summary Report

  • Execution of the March 2009 cost-control plan has been successful, achieving reductions primarily in labor-related costs, consultant and contractor costs, hardware and software support and maintenance, and interest expense;
  • Year-to-date favorable variance of $2.5 million. 

All board meeting documents are available at this link.

Board, Executive Changes Announced

Chief Operating Officer H.B. "Trip" Doggett has been selected to serve as interim chief executive officer, effective Nov. 2, while a search for a permanent successor is underway. Bob Kahn, who joined ERCOT as CEO in 2007, announced last month that he planned to step down Nov. 1.  

See News Release: Trip Doggett Appointed Interim CEO for ERCOT 

ERCOT will begin a search for a new independent board member to replace Mark Armentrout who announced Oct. 19 that  he would not seek election to a third term. Armentrout, whose term ends in November, was elected to the board in June 2003 when ERCOT first added independent board members – those unaffiliated with ERCOT market participants – and re-elected for a second term in 2006.  He was the first independent board member to be elected as board chair, serving from 2005 to 2008.    

See News Release: ERCOT Initiating Search for New Independent Board Member 

Roy P. Bowman was approved by the board to serve as interim vice president and chief financial officer while a search for a permanent successor is underway. Bowman previously served as interim chief financial officer in 2005.  Bowman comes from the Houston office of Tatum, LLC, where he has been a partner since 2001.  He has extensive experience in the energy industry in the areas of establishing and implementing policies and procedures, and developing internal controls. Mr. Bowman holds a bachelor’s degree in accounting from the University of Texas, Austin.   

Former CFO Steve Byone resigned last month to assume the position of vice president and controller for the Tennessee Valley Authority.

ERCOT Sunset Review Documents Available Online

The mission and performance of the Electric Reliability Council of Texas are currently being reviewed by the Legislature as required under the Texas Sunset Act. The act provides that the Sunset Commission, composed of legislators and public members, periodically evaluate a state agency to determine if the agency is still needed, and what improvements are needed to ensure that state funds are well spent.  

The Sunset review involves three steps. First, Sunset Commission staff will evaluate ERCOT and, in April 2010, will issue a report recommending solutions to problems found. The Sunset Commission will then meet to hear public testimony on the agency and the recommendations of the Sunset staff. This meeting will likely be scheduled for May 2010.  

Based on public input and the Sunset staff report, the Sunset Commission will adopt recommendations for the full Legislature to consider when it convenes in January 2011. 

Documents online:

The Electric Reliability Council of Texas (ERCOT) manages the flow of electric power to more than 26 million Texas customers -- representing about 90 percent of the state’s 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 710+ 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.