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Economic Planning Criteria Question 1 1/7/2011 Joint CMWG/PLWG Meeting

Economic Planning Criteria Question 1 1/7/2011 Joint CMWG/PLWG Meeting. March 4, 2011.

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Economic Planning Criteria Question 1 1/7/2011 Joint CMWG/PLWG Meeting

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  1. Economic Planning CriteriaQuestion 1 1/7/2011 Joint CMWG/PLWG Meeting March 4, 2011

  2. Question 1 Assignment: Modeling issues to consider uncertainties as well as validate/refine models to ensure that they reflect reasonable expectations.A) Load VariationsB) Generator Short-Term Outages and DeratingsC) Generator Schedules of Ancillary ServicesD) Outage of Key Transmission FacilitiesE) Fuel Price VariationsF) Emissions Rule ChangesG) Other ConsiderationsOperating Guide Section 5.3(2): The contingency studies will be performed for reasonable variations of Load level, generation schedules, planned transmission line Maintenance Outages, and anticipated power transfers….

  3. A) Load Variations Applying “reasonable variations of load levels” allows for a more appropriate assessment of congestion associated costs. This table depicts the historical distribution of loads1 during peak load hours from 2003 (earliest available) to 2010, adjusted for average growth. Peak load hours include 4:00PM – 8:00PM in July and August of each year. The table above may provide guidance on the magnitude of load variations to model while performing transmission planning studies. ERCOT demonstrated load sensitivity impact during the Houston Import Project Study by performing sensitivities of +/- 10% of the Coastal Weather Zone. 1. Source: Load by Weather Zone (ERCOT yyyy D&E Report), where yyyy indicates the individual year between 2003 and 2010

  4. B) Generator Short-Term Outages and Deratings Historical generation unavailability data as described in the Potomac Economics Report “2009 State of the Market Report for the ERCOT Wholesale Electricity Market” is illustrated below and can be used as a guide to develop “reasonable variations of generation schedules”. Historically Typical June – September Generator Unavailability De-rates Forced Outage: ~2% Planned Outage: ~1 % Other Derations: ~10% Total Unavailable: ~13% Source: 2009 State of the Market Report for the ERCOT Wholesale Electricity Markets, page 56. A summary of Potomac Economics reports (2003 – 2009) pertaining to this data is shown in Appendix 1. Transmission planning studies can best represent anticipated power transfers when appropriately recognizing historical generator unavailability.

  5. C) Generator Capacity Committed to Ancillaries During high load periods, there is a higher risk of congestion and reliance on generators that have a portion of their capacity committed to the ancillary market. To demonstrate this, the most recent data available for high load conditions (July - August 2010) was analyzed and a summary of the findings is presented below1. Data from highest 5 peak load days in July and August 2010, looking at 3 peak hours (1600-1800). The QSE level data available makes it unclear in which zone this deployment took place A review of historical gneration schedules has shown that a specific set of generators typically have material amounts of their capacity committed to ancillary services such as Responsive Reserve, Up Regulation and Non Spin. Transmission planning studies will better reflect reasonable expectations of future constraints when appropriately considering that generation capacity cannot simultaneously be available to both congestion management and ancillary services. 1. Detailed results of this analysis are provided in Appendix 2

  6. D) Outage of Key Transmission Facilities Detail Flows, CSC Limit and Congestion on North – Houston CSC in April 2008 As illustrated above, planned and long-term transmission outages may contribute materially to transmission congestion. Transmission planning studies that appropriately recognize the reality of planned transmission outages (e.g. maintenance & construction) will better reflect reasonable expectations of future constraints.

  7. D) Outage of Key Transmission Facilities (continued) Illustrated on prior slide 76% of congestion occurred during derated conditions From 2008 – 2010, the North – Houston CSC limit was at or above ~3,000 MW during periods where there were no nearby, impactful transmission planned or long-term forced outages. Limits below ~3,000 MW typically indicate that a nearby key transmission facilities was out-of-service, that reduce the CSC limit. The planning criteria has always given consideration to the importance of recognizing the need for planned transmission outages and sought to ensure adequate provision of transmission facilities to accommodate this. Current modeling practices ignore planned and long-term forced outages of transmission elements, contributing to the under-projection of congestion costs.

  8. E) Fuel Price Variations Modeling natural gas forward market prices along with appropriately weighted natural gas price sensitivities, provides a reasonable expectation of project viability in a varying gas price environment. • Natural Gas Price modeling changes: • Apply weightings to the study results of scenarios modeling “expected”, “+1 SD” and “- 1 SD” gas prices. Assume a standard distribution, resulting in weightings of 68% “expected” and 16% for “+1 SD” and 16% for “-1 SD”. • Set curves to actual forward pricing, updating every six months. This chart depicts the gas price assumptions that would have been used for 2012 UPLAN studies since the height of the gas price market in summer 2008, with the price resetting every six months. ERCOT demonstrated the sensitivity of project benefit associated with gas price changes during the Houston Import Project Study by performing sensitivities of +/- $3 to the base price of $7/mmBTU

  9. E) Emissions Rules Changes • The Long-Term Study Study Task Force* is in the scenario building process that gives consideration to several potential environmental regulations including: • Mercury – Title 1 of Clean Air Act MACT • NOx, SO2 – Clean Air Transportation Rule • Water Intake – Clean Water Act 316 (b) • Coal Combustion Residuals CCR – Ash and scrubber byproducts • It’s unknown if, or when, any of these will become law, or what the actual emission limits will be, or how the limits will be applied. • Given the high degree of uncertainty of the items listed above, along with the possibility of carbon legislation, it seems prudent to continue performing transmission planning studies consistent with current laws and regulations. If a new environmental law or regulation is passed, at that time it should be appropriately modeled in all subsequent transmission planning studies. Recommendation – Continue performing transmission planning studies consistent with current environmental laws and regulations * Data listed was found in the ERCOT Presentation: “Environmental Issues and Potential Impacts” presented at the December 2, 2010 Long-Term Study Task Force Meeting.

  10. F) Other Considerations • DC Ties – Model DC Tie flows consistent with historical actual flows. • Hydro – Model Hydro generation output as unavailable for congestion redispatch consistent with their principal mode of operation in providing RRS1. • Wind Variations – At this time, the CREZ 2 Scenario level of wind generation seems to be a reasonable high-end bookend for studies. Items A) and B) above are consistent with current practices and should be monitored periodically and updated as needed. Item C) CREZ 2 Scenario level generation has been used for lines that impact specific CREZ lines. Recommendation – Continue with current transmission planning study practice, monitor and update as warranted

  11. Summary • With the exception of Load and Gas Prices, each item explored in this presentation, can be applied to all cases, and will not increase the number of study scenarios. • To perform Probabilistic Studies with load and gas prices variations, it is necessary to appropriately statistically weight the study results. • For example if, for 3 scenarios of load and gas price (e.g. -1SD, Expected, and +1SD), the weighting given to each simulation would be: • For example, utilizing the several sensitivities performed by ERCOT during the Houston Import Study The Houston Import Project, has an expected Consumer Benefit of $46.5M. Applying the scenario weighted method (as best possible with the detail available), results in a probability weighted Consumer Benefit of $52.8M (i.e. 13.5% higher than the Expected Case). 10

  12. Appendix

  13. Appendix 1) Potomac Economics 2003 – 2009 annual report related to generator Short-Term Outages and Deratings Generating capacity that has historically been unavailable during summer months ranges from 7.9% to 14.8%, with an average of 10.2%

  14. Appendix 2) Details of Generation Capacity Committed to Ancillary Services Table Continued on next page

  15. Appendix 2) Details of Generation Capacity Committed to Ancillary Services (continued) The generation capacity committed to ancillary services was approximated by collecting data for the five highest peak load days in July and August 2010, for Hours Ending 16-18. Additional sources include the Resource Plans, QSE AS Schedules, ERCOT dispatch instructions for AS and BES, and MCPE

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