News Release

July 26, 2011

ERCOT NEWS: July Board Meeting Highlights

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Price correction approved for day-ahead market software error

The Board of Directors for the Electric Reliability Council of Texas (ERCOT), the state grid operator and manager of the wholesale electric market, approved a price correction for selected intervals in the day-ahead market, in a unanimous vote at last week’s monthly meeting. 

The resettlement is estimated to impact 29 days from Dec. 3. 2010 to April 5, and totaling approximately $330,000.  The average price error was $0.06 too high, and the largest price error was $36.86.  Almost all impacts are to congestion revenue rights account holders.   

The software error affecting the day-ahead market was discovered and corrected in early April.  The board was briefed on the price correction options at the June board meeting but delayed voting until more information was available on the impact of the resettlement. 

CEO reviews June 27 emergency event

CEO Trip Doggett presented a timeline of the events on June 27 when ERCOT declared an Energy Emergency Alert level 1 from 3:25 to 4:50 p.m.  The emergency procedures were triggered when the daily operating reserves dropped below 2,300 megawatts (MW), following the loss of three large generation units, totaling 1,834 MW, between 12:54 and 2:38 p.m. 

Doggett’s report also included a graph on the impacts of economy and weather on energy use in 2011, showing a significant weather impact for June.  Energy consumed in June was 33.6 terawatt-hours (TWh) – 14 percent higher than the forecast, 29.4 TWh, primarily due to a hotter-than-normal month.   The graph shows the impact from the economy continues to rise each month.

Seventeen market rule changes approved

Board members approved 13 Nodal Protocol Revision Requests (NPRRs), three System Change Request (SCR), one Planning Guide Revision Request (PGRR), and one impact assessment for an NPRR on the parking deck.  The changes approved included:

NPRR 312 – Clarification of Qualified Scheduling Entity Requirements for Split Generation Resources;

NPRR 314 – Requirement to Post Generation Resources Temporal Constraints;

NPRR 319 – Required Documentation to Recover Fuel Costs for Reliability Unit Commitment Deployments;

NPRR 324 – Conductor/Transformer Transmission Facility Rating;

NPRR 328 – Clarifies Duplicative or Vague Requirements Related to Reactive Resources;

NPRR 332 – Revise Quick Start Generation Resource (QSGR) Processes for Current Operating Plan Reporting of QSGR Assigned Off-Line Non-Spinning Reserve and Application of Emergency Operations Settlement;

NPRR 333 – Removal of Redundant Reporting Requirement Related to Equipment Ratings;

NPRR 337 – Correct Section Reference in Section 1.3.1.1 Pertaining To Protected Information of Direct Current Ties;

NPRR 338 –Modifications to Support Revenue Neutrality;

NPRR 344 – Define Reliability Must Run Fuel Adder;

NPRR 346 – Removal of Redundant Posting Requirement Related to Electrical Bus Changes;

NPRR 376 – Congestion Revenue Right Volume Limitation Enhancements;

NPRR 387 – Hydro Responsive Reserves Deployment Under-Frequency Relay Set Point;

SCR 761 – Provide Price Republication Notifications via Application Programming Interface and Provide Price Corrections via Extensible Mark-up Language;

SCR 762 – Enable a Single Step Cancel/Resubmit of Trades;

SCR 763 – Modify Current Operating Plan Validation Rule for Hydro Responsive Reserves;

PGRR 006 – New Planning Guide Section 6.5, Annual Load Data Request. 

The board also approved an impact assessment for NPRR 258 (Synchronization with PRR 824 and PRR 833 and Additional Clarifications), which is on the “parking deck” since it was designated as not needed for nodal go-live. 

In other action, the board approved revised procedures for setting the day-ahead market credit requirement parameters, as recommended by the stakeholders’ Technical Advisory Committee and endorsed by the board’s Finance and Audit subcommittee. 

New vice president of business integration announced

The board ratified Betty Day for a new officer position – vice president of business integration – for 2011.  Day joined ERCOT in 2000 as manager of load profiling.  In her most recent role she served as director of commercial operations with responsibilities for retail customer choice, settlement metering, data aggregation, settlements and billing, and data integrity and administration.   

DOE Long-term study on track for June 2013 final report

ERCOT staff presented an update on the Texas Interconnection Long-term Study, funded in part by a Department of Energy grant.  Quarterly stakeholder meetings will be conducted beginning in August, with the goal of completing a final report for the Department of Energy in June 2013. 

Other staff reports covered:

ALSO ONLINE

Archived broadcasts of ERCOT board meetings

July 19 ERCOT Board meeting

July 18 Finance and Audit Committee meeting

July 18 HR and Governance Committee meeting  

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’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 600+ 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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