2010/2011 ISO Transmission Plan

1. 2010/2011 ISO Transmission Plan Neil Millar Executive Director, Infrastructure Development SSPG Meeting July 1, 2011

2. Approving the plan meant approving determinations and recommendations contained in the plan including: • 4 new transmission reliability projects over $50 million each; • 1 new policy-driven transmission upgrade element.

3. This was the first transmission plan developed under the revised transmission planning process. • Enhanced collaboration - statewide conceptual transmission plan; • New “policy-driven” category of transmission - state and federal public policy; • Greater opportunity for independent transmission developers – compete to build certain elements; • More opportunities - stakeholder participation and input.

4. Development of Annual Transmission Plan December 31, 2010 May 18, 2011 December 31, 2011 Coordination of Conceptual Statewide Plan Transmission Plan Presented to ISO Board for Decision Phase 1 assumptions and study plan Phase 2 Technical Studies and Board Decision Phase 3 Competition - policy and economic projects. Continued regional and sub-regional coordination

5. Development of 2010/2011 Annual Transmission Plan Reliability Analysis (NERC Compliance) • 33% RPS Portfolio Analysis • - Incorporate GIP network upgrades • Identify policy transmission needs Results Economic Analysis - Congestion studies - Identify economic transmission needs • Other Analysis including 2008 and 2009 request window projects

6. Identified reliability projects by service territory:

7. Reliability projects over $50 million each • Cottonwood-Red Bluff: • New span of 60 kV line • New 230/60 kV substation near Red Bluff • $43 million - $57 million • South of Palermo 115 kV Reinforcement Project: • Reconductor 115 kV lines • $80 million - $100 million • Vaca Dixon-Davis Project: • Convert the 60 kV facilities to 115 kV • $70 million - $107 million • Southern Orange County: • Reconfiguration and upgrade of Talega 138kV system • Re-build Capistrano substation • New 230 kV lines • $364.8 million

8. Policy driven analysis was based on renewable energy zones and resources. • Solar • Wind • Geothermal

9. Transmission underway will meet 33% RPS in 2020. Total cost = $7.2 billion * Petition to modify CPCN pending. ** Large Generator Interconnection Agreement

10. Stakeholder Feedback • Support for individual reliability and policy projects; • Generation modeling assumptions; • Treatment of LGIP network upgrades; • Treatment of 2008 and 2009 request window submissions • Role of independent transmission companies • Consistent treatment of load shedding for extreme contingency events.

11. Conclusions • Transmission approved to date within ISO footprint can accommodate a diverse range of 33% resource portfolios for meeting the 33% RPS. – No new major projects needed at this time. • As assumptions change going forward, the ISO will reassess transmission needs through its annual planning process. • The ISO is relying on the CPUC portfolios in the 2011/2012 planning cycle. • Focus within the state now should be on permitting the identified transmission.

12. Looking ahead to 2011/2012 Transmission Plan May 2011 March 2012 October 2012 ISO Board Approval of Transmission Plan Coordination of Conceptual Statewide Plan • Phase 1 • Development of ISO unified planning assumptions and study plan • Incorporates State and Federal policy requirements and directives • Demand forecasts, energy efficiency, demand response • Renewable and conventional generation additions and retirements • Input from stakeholders • Ongoing stakeholder meetings Phase 3 Receive proposals to build identified policy and economic transmission projects. Phase 2 • Technical Studies and Board Approval • Reliability analysis • Renewable delivery analysis • Congestion analysis • Publish comprehensive transmission plan • ISO Board approval Continued regional and sub-regional coordination

13. Integrating Renewable Resources – Key Challenges • Transmission • Transmission to support a 33% RES by 2020 • Comprehensive plan for all drivers • 33% RES by 2020 • Renewable integration • Once-through cooling • South Coast air emission credits • Very active generation development community • Integration • Resource fleet requirements • Operational readiness • Market products/rules

14. ISO Queue Renewable Projects Locations & Type as of May 24, 2011

15. Managing renewable energy variability. Data based on summer production profiles

16. Needs for reliability services increase substantially with increasing levels of variable generation. • To maintain reliability the ISO must have the operating capability this describes. • It remains to be seen the extent to which these services will be met by: • Demand Response • Energy Storage • Conventional Generation • Flexibility is essential. Source: ISO 20% RPS Study, August 31, 2010, http://www.caiso.com/2804/2804d036401f0.pdf

17. Flexible capacity in existing ISO generation fleet. Flexible fleet capability that may retire or repower Slide 17

18. What is the business/market model for conventional generation and other needed resources? Aggregate Operational, Emissions and Revenue Changes for Combined Cycle Units in 2012 (under simulation assumptions)

19. Initiatives to support renewable integration • Resource adequacy and planning • Resource adequacy rules reflecting operational characteristics • Long-Term Procurement Plan supporting renewable integration • Operational Readiness • Wind & solar forecasting tools (output, ramping requirements) • More sophisticated grid monitoring systems • Market/Policy Enhancements • New market products & changes to market rules • Intra-hour scheduling and dynamic transfers • Increased regulation and reserve requirements • More sophisticated day-ahead unit commitment algorithms • Key challenges • Renewable integration cost allocation • Centralized market for longer-term market needs • Alignment between wholesale pricing and retail rates