Long-Term System Assessment Project Update

1. Long-Term System AssessmentProject Update Warren Lasher Manager, System Assessment Regional Planning Group

2. Purpose • To Inform Near-Term Planning with Potential Solutions that Meet Long-Range System Needs • Intent is not to select new circuits to recommend • Rather, the intent is to provide a selection of alternatives through scenario analysis that can be considered when developing solutions for near-term congestion or reliability needs Regional Planning Group

3. Specific Focus • The focus of this study is to look for: • Long-Lead-Time Projects – projects that may require 5 or more years to bring on-line • Large Projects – projects that both solve short-term issues but also meet long-term system needs. Regional Planning Group

4. Scope • Study Year: 2018 • All generation currently on-line (and expected to maintain operation) plus all units with signed IAs as of 7/1/2008 • Base Case will include the CREZ Scenario 2 (selected by PUCT on 7/17/08) • Generation Expansion – by scenario • Gas price – by scenario • Emissions allowance prices – by scenario • A report will be submitted to PUCT by end of 2008 • Analysis will continue next year Regional Planning Group

5. Methodology • Study Consists of Two Components • Evaluation of Regional System Needs • A/C contingency steady-state analysis • SC-UC Model Development • Evaluation of Economic Projects Regional Planning Group

6. A/C Contingency Analysis • Evaluated Five Areas • Northeast Region • Houston • South-Central • Valley • Using different local generation dispatches, evaluated the reliability needs of these areas under increasing amounts of import • Looked for thermal limit and voltage violations under contingency, primarily on the 345-kV network • Did not evaluate transient stability limits Regional Planning Group

7. A/C Contingency Analysis Example: Northeast Region Under peak load conditions, generation availability was reduced by up to 2,800 MW to determine import constraints (resulting in a net import of 2,550 MW) Regional Planning Group

8. A/C Contingency Analysis • Example: Houston Region Under peak load conditions, generation availability was reduced by up to 1,100 MW to determine import constraints (resulting in a net import of 6,760 MW) Regional Planning Group

9. A/C Contingency Analysis • Example: South-Central Region Under peak load conditions, generation availability was reduced by up to 1,900 MW to determine import constraints Regional Planning Group

10. A/C Contingency Analysis • Example: Valley Region Under peak load conditions, generation availability was reduced by up to 1,000 MW to determine import constraints (resulting in an import of 2,700 MW) Regional Planning Group

11. A/C Contingency Analysis • Results: • No reliability need for additional import capacity in the Northeast and South-Central Regions • At high levels of unavailable generation, import restrictions are noted in these areas • A new import pathway into Houston will be required by the summer peak season of 2018 • Current connections to the Valley region appear to be adequate although imports over existing interconnections with CFE may be required Regional Planning Group

12. SC-UC Analysis • In order to build a 2018 model for economic analysis, small load-serving projects had to be added to the SCUC base-case model • Projects required to reliably serve load • Analyzing 8,760 hours using DC loadflows • These projects are not in the base-case, which is built off of the last year of the latest 5-Year Plan • In areas where several of these projects were required, a more cost-effective solution might be to build one larger (345-kV) project, rather than several smaller 138-kV upgrades Regional Planning Group

13. SC-UC Analysis • Based on this analysis, four areas were selected for further analysis: • Houston Import • Western Williamson County • West of Waco • North of Dallas (Cooke and Grayson County) • In addition, these areas were reviewed for reliability needs: • Brenham Area • Columbus Area Regional Planning Group

14. Options for Houston Import • The following options were evaluated for new pathways into the Houston area: • Fayette to Zenith • Salem to Zenith • Lufkin to Canal • Hillje to Parish, O’Brien or Zenith • Choice may depend on future base-load generation additions • Options further evaluated in the analysis of economic projects Regional Planning Group

15. North Dallas Area • Area around Cooke and Grayson Counties (north of Dallas near the Oklahoma border) • Load growth may stress existing 138-kV service • 345-kV Option: Tap into the CREZ line connecting Oklaunion and West Krum, and build a new 345-kV right-of-way to the Valley substation. Potential new 345-kV substations at the Payne and Valley View substations with 345-kV/138-kV autos. Regional Planning Group

16. West Waco Area • Area west of Waco, in McLennan, Coryell, and Bosque County • Again, limited 345-kV service in this area • 345-kV Option: New 345-kV right of way from Comanche Peak, south to the new Newton substation included in the CREZ plan. This would allow a new connection(s) into this area from the west. This option provided significant economic benefits if additional nuclear generation is developed at Comanche Peak. Regional Planning Group

17. Western Williamson County • Load growth around Leander up to Lampasas will require several 138-kV upgrades • Flow is generally from 345-kV lines in the east and southeast • Potential solution: • New 345-kV substation at Lampasas, connecting to the CREZ line from Gillespie to Newton • Upgrade the 138-kV circuits from Lampasas to Burnet13 • New 138-kV right-of-way from Burnet13 to Leander Regional Planning Group

18. Other Areas • The Brenham area is generally served radially from the Fayette to the Salem substations. Options were evaluated to provide network service for the Salem substation, including new right-of-way from Salem to Zenith, or from Salem to Sandow. These solutions were generally not cost-effective. • There is congestion in the Columbus area due to flows on the 69-kV system. One possible solution would be to convert some of the 69-kV circuits to 138-kV. This solution appears to be effective in eliminating congestion in the base-case, but with added base-load generation to the south (such as new nuclear units at STP or Victoria), a better solution may be to break the 69-kV system, reinforce the two ends and add reactive support. Regional Planning Group

19. Economic Analysis • Using Scenario Analysis, evaluate projects that increase system efficiency under potential future conditions. Scenarios include: • Additional Nuclear Generation (3 units, 6 units) • Natural Gas Prices ($7, $11, $15/MMBtu) with Coal Gasification/IGCC • Carbon Constraints (Up to $100/ton) • Changes in Load Shape (Plug-In Hybrids, Energy Storage) • Additional Renewable Generation (Wind, Solar) Regional Planning Group

20. Economic Analysis – Generation Expansion • Generation development will be driven by profit expectations. • Bus-bar analysis shows type of generation options that will be most cost-effective. Regional Planning Group

21. Economic Analysis – Generation Expansion • Impact of Carbon Tax shown on this chart. Regional Planning Group

22. Economic Analysis – Generation Expansion • ERCOT system has a significant amount of intermediate generation Regional Planning Group

23. Economic Analysis – Generation Expansion • At gas prices of $11/MMBtu or $15/MMBtu, additional base-load generation will likely be profitable. • Additional generation expansion, to meet 12.5% target reserve margin, will likely come from quick-start combustion turbines or very flexible combined-cycle plants. • Hourly marginal cost unit-commitment models will often underestimate the benefits from quick-start combustion turbines • Ancillary services (Non-spin) • Short-term price spikes Regional Planning Group

24. Economic Analysis – General Observations • Evaluating two levels of nuclear and coal (IGCC) expansion indicates that economic projects were generally not cost-effective unless they were specifically designed for scenario generation expansion (except in certain scenarios) • Backbone projects (such as 765-kV Navarro to Hillje, and Fayette to Zenith) were generally not cost-effective unless new generation was directly connected to the backbone • Carbon constraints did not significantly alter the locations of system congestion, although they change the congestion costs and likely generation expansion options Regional Planning Group

25. Economic Analysis – General Observations • No large projects in ERCOT between Dallas and Houston were found that were economically justified due to presence of CREZ wind. Import pathway into Houston from the west was cost-effective. • Analysis of up to 2,000 MW of solar generation in the McCamey area indicates limited increase in curtailment to wind or solar projects • Analysis of conventional Compressed Air Energy Storage indicates that 2,000 MW of CAES capacity can increase wind generation by 830 GWh (reducing wind generation curtailment by 1%); production costs reduced by $10 million Regional Planning Group

26. Conclusions • Reliability analysis indicates a need for additional import pathway into Houston area by 2018. Selection of most cost-effective solution will likely depend on generation expansion. • Options have been presented for additional reliability projects north of Dallas, near Waco, and north of Austin • Scenario analysis indicates that cost-effectiveness of economic projects depends heavily on locations of future generation development • Long-term analysis will continue in the new year: • CREZ implementation • > 10 year analysis Regional Planning Group

27. Questions? Regional Planning Group