ERCOT at a Glance: News Update - March 22, 2006
- Board Recommends Nodal Funding Proposal
- ISO/RTO Planning Committee Report Posted
- System Planning Report Highlights
The ERCOT Board of Directors unanimously approved a resolution today to seek authority from the Public Utility Commission (PUC) to impose a system administration fee surcharge or other mechanism to recover costs from the nodal market redesign project.
After a review of five debt financing options, the boardâ€™s Finance and Audit Committee recommended a â€œflat fee option.â€? This option uses a blend of borrowed funds (62 percent) and a nodal surcharge (38 percent) to produce a relatively flat fee from 2006-2012 (the nodal development period and the estimated average useful life of the assets). Using the current estimate of $125 million total cost for the market redesign, the fee surcharge would be approximately 6.6 cents for seven years. ERCOTâ€™s System Administration Fee is currently set at $.42 per megawatt-hour. It is expected to decrease to an estimated $.417 per MWh for 2006 pending a final PUC order.
The board also authorized ERCOT to borrow up to $20 million to finance the nodal project costs until a cost recovery mechanism is approved by the PUC. Commission Chairman Paul Hudson estimated the fee filing case could be a five-month process.
The board previously approved spending up to $5 million on the nodal project preparation. The spending level for 2006 is estimated at $30 million under the current timeline for implementation Jan. 1, 2009, CIO Ron Hinsley said. Approximately $528,000 in nodal spending has been incurred through the end of February 2006, he said.
The nodal cost estimate and timeline are based on approval of the nodal protocols which are before the PUC in a contested case. A final order in this case is expected soon.
Other board action included:
- Approval of an ERCOT compensation strategy, as recommended by the boardâ€™s HR and Governance Committee
- Approval of three Protocol Revision Requests (PRR):
PRR 635 â€“ Resource Plan Performance Metrics Update
PRR 640 â€“ Update Provisions for Capacity and Energy Payments for RMR Service and Add a New Standard Form Agreement for Synchronous Condenser Service
PRR 642 â€“ Lower Limit to IDR Meters in MRE for True-Up Settlement IDR Threshold
- Report from COO Sam Jones on the timeline for compliance with the Federal Energy Policy Act :
March 28 â€“ The North American Electric Reliability Council (NERC) expects to file documents requesting certification as the electric reliability organization (ERO) specified in the energy policy act
After NERC application is finalized on March 28, ERCOT plans to host a public meeting to gather input from stakeholders
April 18 â€“ ERCOT board to discuss and vote on ERCOT options for a regional entity structure that would comply with the Federal Energy Regulatory Agency (FERC) ERO rule
June-July â€“ ERCOT regional entity application documents and budget to be filed
August 8 â€“ NERC anticipates receiving ERO certification from FERC
- Report from Director of Corporate Security Jim Brenton regarding facilities needs for the nodal project:
- Up to 150 spaces may be needed for the nodal team
- Preliminary estimated cost for build-out of the Taylor facilities is $4.93 million
- Facilities staff will do further evaluation on space needs and costs and will report back to the board at the April 18 meeting.
Board meeting presentations and background materials are posted on the ERCOT Web site meeting calendar.
The ISO/RTO Planning Committee has published a report, â€œISO/RTO Electric System Planning Current Practices, Expansion Plans, and Planning Issues.â€? The paper documents the status of ISO/RTO planning; summarizes the current ISO/RTO system plans; and reports on system planning practices and issues, such as reliability planning, economic planning, deliverability of capacity, resource adequacy, generator interconnection, including the impact of wind generators, and the potential impact of increasing dependence on natural gas for the generation of electricity.
The ISO/RTO Planning Committee promotes communication and assists in coordinating issues of mutual concern that affect ISO/RTO planning in the electricity industry among the independent system operators (ISOs) and regional transmission organizations (RTOs) in North America. The current members, in addition to ERCOT, are Alberta Electric System Operator, California Independent System Operator, Independent System Operator of the Province of Ontario, Independent System Operator of New England, Midwest Independent System Operator, New York Independent System Operator, PJM Interconnection, and Southwest Power Pool.
Director of System Planning Bill Bojorquez released highlights from the February System Planning Report including:
Interconnection Requests Increased by 1,915 MW in February: Several new generation interconnection requests were received by ERCOT for screening studies in February. The total capacity in all generation interconnection requests is 20,618 megawatts (MW).
Significant Transmission Construction Completion Anticipated in 2006: The ERCOT region is anticipating almost $1 billion in transmission construction to be placed into service in 2006.
Reliability Must Run (RMR) Cancellation Notice Sent to Barney M. Davis: ERCOT sent a termination notice to Sempra Texas Services on Feb. 19, 2006, for the RMR contract for B.M. Davis Unit # 1 (335 MW). The RMR contract will be terminated effective May 19, 2006.
CenterPoint submits Houston Dynamic Reactive Proposal for RPG Review: CenterPoint has submitted a 100 MVAr dynamic VAr device for regional review. Request has been distributed to stakeholders for review and comments by April 3, 2006.
The February System Planning Report is posted on the Web site with the April ROS meeting documents.
ERCOT Meeting Calendar
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.