ERCOT NEWS - April 16, 2008
- Board of Directors Meeting Highlights
- Nodal Market Update
- Protocol Revisions
- 2009 Budget Review
- Staff Reports
- ERCOT CEO Testifies at Joint Senate Hearing
The Board of Directors approved eight protocol revisions and the 2007 financial statements at Tuesday’s monthly meeting.
The board also approved the Technical Advisory Committee’s plan for managing protocol content and revisions during implementation of the nodal market. The plan was created in response to stakeholder discussions regarding scope challenges to nodal delivery and how to assure full protocol delivery. The plan outlines a process to ensure transparency and certainty on what functionality will be available for Texas Nodal Market Implementation.
As defined by the process, once a scope issue is identified, the Transition Plan Task Force (TPTF) will immediately assess the issue and then assign it to one of three categories: 1) needed for nodal “go-live;” 2) approved for post go-live; or 3) deferred projects. ERCOT staff will review the recommendations and report to TPTF on cost and schedule, and then TPTF will follow its established processes.
Board Chair Mark Armentrout expressed his appreciation to the Technical Advisory Committee for reaching a compromise on managing items in the nodal protocols that may not have functionality as originally planned.
The nodal market redesign remains on schedule for the Dec. 1, 2008 launch with less than 20 weeks before the beginning of the 168-hour (24-hours for 7 days) readiness tests during September. Checkpoints are in place to ensure ongoing viability of the go-live date, said Jerry Sullivan, executive director of the market redesign, in the nodal update.
The nodal software is now into the ninth and final release, Sullivan said. The top risk continues to be the challenge of integrating multiple systems into the common information model. Regression testing is being employed to ensure that new code fixes do not adversely affect other code functionality.
ERCOT readiness status is acceptable, but staffing levels and procedures need improvement. Market participant readiness is an area of concern and is projected to go to “red” status due to insufficient training and readiness.
In other board action, the directors approved the following Protocol Revision Request (PRR) and Nodal Protocol Revision Requests (NPRR):
- PRR 747: Interval Data Recorder Requirement Change
- PRR 752: Update to Posting Requirements of Standard Qualified Scheduling Entity (QSE)-Specific Market Reports (approved with edits).
- PRR 758: Clarification of Language Related to Generation Netting for ERCOT Polled Settlement Meters (approved with corrections)
- NPRR 092: Remove Voltage Schedules Requirement
- NPRR 099: Reliability-Must-Run Incentive Factor Payment
- NPRR 100: Pre-Assigned Congestion Revenue Right Release Mechanism
- NPRR 101: Modify Time Requirements for Entry of Equipment in the Outage Scheduler
- NPRR 103: Settlement of Power Imported via Direct Current Ties and Block Load Transfer Under a Declared Emergency Condition
PRR 743, Transmission Congestion Rights (TCR) to Congestion Revenue Rights (CRR), was deferred back to the Technical Advisory Committee for further revisions to address how to handle refunds if the nodal market does not go live Dec. 1, 2008. The PRR provides for a transition plan to move the market from TCRs to CRRs, following implementation of the nodal market.
Chief Financial Officer Steve Byone reviewed the 2009 budget proposal, which the board will be asked to vote on at the next board meeting in May. The board’s Finance and Audit Committee has reviewed the budget three times and has recommended approval.
The proposed budget includes a $0.15 increase in the system administration fee, from the current $0.42 fee to $0.57 per megawatt hour.
Policy decisions driving the funding requirements include new functions necessary for nodal operations, primarily the cost for staffing new functions, adding new technology applications and facilities to house new staff and systems, and one-time items for nodal stabilization. Facilities requirements include space demands for staffing and data center space as required by the nodal market, and relocation of the Austin center due to lease expiration.
The system administration fee is assessed on wholesale energy transactions and becomes part of the overall cost of electricity. The approximate impact on an average household using 1000 kilowatt-hours/month would be $0.57 per month under the proposed budget. If including the nodal surcharge of $0.17 per MWh, which is expected to expire in 2013, the total approximate impact would be $0.74 per month.
If the budget is approved by the board in May, a fee case will be filed with the Public Utility Commission for review and approval.
Director of System Planning Dan Woodfin presented an update on the CREZ Transmission Report which was filed with the Public Utility Commission April 2. The PUC filing is available on the ERCOT Web site.
Other ERCOT staff report highlights included:
- ERCOT is tracking 219 active generation requests, totaling over 100,000 MW (including 44,000 MW of wind generation);
- 210 MW of new generation went in service in March (80 MW coal unit upgrade in Bexar county and 130 MW of wind in Erath and Sterling counties);
- Laredo Peaking Power Plant signed an interconnection agreement last month for a 200-MW gas plant in Webb county, expected in-service May, 2008;
- Regional Planning Group is currently reviewing proposed transmission improvements totaling $206.3 million;
- The Wind Ancillary Services Study update was filed with the Public Utility Commission April 2.
- Switching activity in February was about the same as the prior year;
- Balancing energy prices continue to track natural gas prices which are up;
- Volatility in the West Hub continues as increased concentration of wind combined with transmission constraints produces expected swings in clearing prices;
- Five new qualified scheduling entities and one new retail electric provider were added in March.
- West to North zone congestion was recorded on 24 days in February, compared to no days in February 2007. North to West zone congestion was recorded on 15 days, compared to 2 days last year. North to South congestion totaled 4 days, and South to North, 2 days.
- Follow-up actions from the February 26 emergency grid event include:
- An independent wind generation forecast has been manually integrated into some of the operators’ tools;
- ERCOT staff met with Southwest Power Pool and AEP to clarify and improve the process for arranging emergency schedules over the North and East direct current ties;
- ERCOT staff is working with market participant stakeholder committees on wind integration and changes that may be needed to ancillary service procurement.
- The load forecast performance error for mid-term load forecast was 3.59 for February. The error for 2008 year-to-date is 3.44, compared to 3.55 in 2007, 3.79 in 2006 and 4.56 in 2005.
Information Technology Report (March performance metrics):
- Retail transaction processing – 97.05 percent
- Texas Market Link availability – 97.13 percent
- MarkeTrak availability – 95.67 percent
CEO Bob Kahn presented testimony at a joint hearing of the Senate Business and Commerce and Senate Natural Resources Committees on April 15. Kahn’s presentation “Planning for Texas’ Energy Future” is available on the ERCOT Web site.
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.