Market Information System Grid and Market Conditions

News Release

August 19, 2009

ERCOT NEWS: August Board Meeting Highlights, IMM Report

August Board Meeting Highlights

Board Approves Go-live for First Core Nodal System

The Board of Directors for the Electric Reliability Council of Texas, grid operator for most of the state, voted unanimously to proceed with the Aug. 31 go-live date for the single-entry model – the first core nodal system to be brought to market.

The single-entry model (SEM)is a network model management system where transmission service providers can interactively view and update the ERCOT network model (a representation of the physical grid) concerning changes to the grid such as new lines, substations and equipment, and retirements.

After the SEM go-live, the nodal network operations model will become the official model of the ERCOT system, and it will be synchronized with the current zonal model until it goes away following the nodal market launch in late 2010.

Full market trials are scheduled to begin in February 2010. The nodal market remains on track for its December 2010 implementation.

“This is important because this is the first (nodal system) out of the box,” Chief Technology Officer Mike Cleary said. “The TAC (Technical Advisory Committee) and everyone involved need to be thanked for their hard work on this.”

TAC convened prior to the board and also certified that SEM was ready for go-live, with remaining issues able to be worked out in the coming months.  Comprised of ERCOT stakeholders, TAC makes recommendations to the board regarding ERCOT policies and procedures and is responsible for prioritizing projects through the protocol revision requests, system change requests and guide revision processes.

Nodal Program Moves into Integration Phase; Market Trials on Target

Cleary reported the nodal program has moved past the development of software applications into the full integration stage, with the testing efforts gradually increasing in complexity.  Cleary presented an integration timeline and added that the program team is finalizing a ground-up analysis to determine exactly what work remains.

The program is currently testing 78 connectors between the various software applications that will comprise the nodal market. 

“We’re starting to see additional issues coming out as we test the connectivity between systems,” Cleary said. “However, I don’t see anything causing us to delay full market trials in February (2010).”

Chief Financial Officer Steve Byone reported the nodal program’s July financials reflect a cumulative forecast under-run of $3.2 million, primarily driven by external resource costs, software and hardware. The program’s cumulative under-runs have grown to $19.4 million, and it continues to hold the board’s discretionary fund of $58.6 million.  Re-forecasted estimates at completion are to be presented at the October board meeting.

Parking Deck Process for Postponed Nodal Protocols Approved

After a lengthy discussion, the board narrowly approved a "parking-deck process" to manage nodal protocol revision requests that cannot be implemented prior to the nodal market go-live date.  TAC recommended the parking deck process for better change management and version control, among other reasons.

The board also approved numerous Protocol Revision Requests (PRR), and Nodal Protocol Revision Requests (NPRR):

  • PRR 787 – Add Non-Compliance Language to Qualified Scheduling Entity Performance Standards
  • PRR 801 – Manual Transmission Congestion Rights Adjustments
  • PRR 805 – Adding Provider of Last Resort Customer Class and Advanced Metering System Meter Flag to the Database Query Function on the Market Information System
  • PRR 810 – Remove McCamey Congestion Management
  • PRR 814 – Nitrogen Oxide Emissions Allowance Index Price
  • PRR 816 – Closely Related Element Determination Criteria
  • PRR 819 – Changes to Support Revisions to the Public Utility Commission of Texas Provider of Last Resort and Expedited Switch Rules
  • PRR 820 – Definition for Transmission and/or Distribution Service Provider
  • NPRR 171 – Synchronization of PRR 805
  • NPRR 175 – Hub Bus List Clarification
  • NPRR 176 – Resource Status Input to Reliability Unit Commitment (RUC) and Ancillary Service Awards from RUC
  • NPRR 177 – Synchronization of Nodal Protocols with PRR 808, Clean-up and Alignment of Renewable Energy Credits Trading Program Language with Public Utility Commission of Texas Rules
  • NPRR 178 – Regulation Reduction (GS-FR3) and Reg-Up/Reg-Down Allocation to Qualified Scheduling Entities
  • NPRR 180 – Reconciliation of Congestion Revenue Rights Related Protocol Language
  • NPRR 182 – Non-Protocol Postings on the Market Information System
  • NPRR 187 – Definition for Transmission and/or Distribution Service Provider.

The board approved one Retail Market Guide Revision Request : RMGRR 079 – Changes to Support Revisions to the Public Utility Commission of Texas Provider of Last Resort and Expedited Switch Rules.

The TAC presentation included a report on the Reliability and Operations Subcommittee study of the amount of Loads Acting as Resources (LAARs) capable of providing responsive reserve service.  The study recommended that ERCOT continue to allow no more than 50 percent of responsive reserve service to be provided by LAARs.

2010 Budget Presented; Vote in September

ERCOT staff presented the 2010 Proposed Budget and Five-Year Forecast including three scenarios:

  • A management-recommended budget based on a 3-cent increase in the fee and requiring elimination of 23 positions;
  • A moderate-service reduction budget based on a 2-cent increase in the fee and requiring elimination of 54 positions;
  • A zero-fee increase budget requiring elimination of 102 positions.

“We realize these are difficult economic times and we are doing everything possible to keep the fee as flat as possible” CEO Bob Kahn said in his opening remarks to the board.  “ERCOT has actively managed costs to keep a flat-to-declining fee over the last several years.”

Additional budget detail by division, presented at the board’s Finance and Audit Committee Aug. 17 public budget hearing, is available online:

The system administration fee, which represents 98 percent of ERCOT''s total base operating revenue requirement, is paid by wholesale users of the power grid.  If the current fee $0.4171 per megawatt hour were passed directly through to end-use customers, it would average about 42 cents per month or $5 per year, based on 1,000 kilowatt-hour usage per month.

Kahn indicated that ERCOT staff would continue to “scrub” the proposals.  The board is scheduled to vote on the budget in its Sept. 15 monthly meeting in anticipation of a filing with the Public Utility Commission by Sept. 30. 

Market, Grid, IT Reviewed in Staff Updates

Additional staff presentations reported at the board meeting included:

Market Operations Report

  • July retail switching activity continues the strong trend seen throughout 2009
  • Advanced Metering Project Update – All Design Documentation and Development completed. Currently in Product Test phase; to be completed in August.
  • Total market volume has increased from prior months in 2009 but continues to be lower than 2008. Natural gas prices remain at significantly lower levels than seen in 2008.
  • June prices showed significant increase from prior months due to congestion in the South and Houston zones.
  • Added three Qualified Scheduling Entities: Eagle Industrial (SQ2), JPMorgan Ventures Energy Corp. (SQ3), and QSE Group, LLC; and terminated Reliant Energy Services, Inc., Reliant Energy Electric Solutions, and Texas Star Energy (SQ1) 

Grid Operations and Planning Report

  • Monthly peak demand of 62,297 MW on June 25 was less than the forecasted peak of 62,597 MW; Day-ahead load forecast error for June was 2.89 percent; one Advisory for Adjusted Responsive Reserves below 3000 MW and 16 transmission watches in June.
  • July 2009 peak demand on July 13 of 63,453 MW was 1,114 MW higher than all-time peak demand of 62,339 MW set in August 2006.
  • 8,135 MW wind on line July 31; no change from June.
  • 235 active generation interconnection requests totaling more than 87,000 MW, as of July 31.
  • Regional Planning is currently reviewing proposed transmission improvements with a total cost of $1.166 billion.
  • Graphs of: Wind output, plus curtailment, versus day-ahead resource plans; Wind generation correlation with demand by zone; Monthly peak demand and minimum demand compared to 2008; Day-ahead load forecast performance in June; Breakdown of capacity purchased to manage local congestion in June; Maps of county location of all projects under interconnection study and of wind-only; Generation interconnection activity by fuel type and by project phase.

Emergency Interruptible Load Service Update

  • Since February 2008, ERCOT has procured 150-310 MW at $8-11/megawatt-hour for a total cost of $27 million.
  • The report concludes that the EILS program cost would not be justified based solely on a Value of Lost Load analysis (a mathematically-calculated estimation of direct economic loss due to loss of electric service), but that EILS can be viewed in a broader context as an additional hedge against firm load shed.

Information Technology Service Availability Metrics Report

All board meeting documents are available at this link.

Market Monitor Report Finds ERCOT Markets Competitive

Potomac Economics, independent market monitor for the ERCOT wholesale market, released its 2008 annual state of the market report last week, reporting that the ERCOT wholesale market “performed competitively in 2008.”

The report confirmed prior findings in six previous annual reports that ERCOT’s current zonal market is causing “systemic inefficiencies” affecting management of transmission congestion and effectiveness of the scarcity pricing mechanism. The executive summary states that the wholesale market should function more efficiently under the nodal market design, scheduled for a late 2010 launch, by providing better incentives to market participants, facilitating more efficient commitment and dispatch of generation, and improving ERCOT’s operational control of the system.

Under the nodal market, congestion on all transmission paths and facilities will be managed through a market-based mechanism which “will produce price signals that better indicate where new generation is most needed for managing congestion and maintaining reliability,” the report states, and adds, “ In the long-term, these enhancements to overall market efficiency should translate into substantial savings for consumers.”

The report reviews the high price excursions that occurred in the South and Houston zones during April, May and early June of 2008 until an expedited market rule change was implemented, modifying ERCOT congestion management procedures. While the market rule change resolved the issues within the zonal market model framework, the report says, the implementation of the nodal market will eliminate the current bifurcated congestion management process and provide “simultaneous, unit-specific solutions that will always present the most effective and efficient congestion management alternatives.”

The report presents an analysis that estimates a savings of $87 to $175 million could have occurred through more efficient congestion management had the nodal market been in place during the spring congestion.

Other findings in the executive summary included:

  • The monthly average all-in energy prices for 2005-2008 indicate that natural gas prices were the primary driver.
  • The continued increase in wind production in 2008 served to displace more costly generation resources when the wind was producing, which tended to lower average prices across the market.
  • The hourly average balancing energy market price in the West Zone was less than zero in more than 1,100 hours during 2008. Because wind generators have zero fuel costs and economic incentives to operate – earning federal production tax credits and state renewable energy credits – negative prices (essentially, offering payment to generate) often result when transmission congestion requires some wind generators to curtail output.
  • Electricity demand will continue to grow and a significant number of generating units will soon reach or are already exceeding their expected lifetimes; without major capacity additions, resource margins could diminish over the next three to five years.
  • Increasing penetration of intermittent resources such as wind and solar facilities will likely create the reliability need for additional operationally flexible resources, such as modern gas turbines.
  • An analysis of price spikes versus remaining up-balancing capacity indicates “very competitive market outcomes in 2008,” showing “significant improvement over 2005 and 2006.

The 121-page report is posted on the Public Utility Commission website at:  

 2008 State of the Market Report

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.