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2012 LTPP Updates

Learn about the 2012 Long-Term Procurement Planning process for grid reliability and resource procurement in California, involving coordination between CEC, CAISO, CPUC. Detailed analysis for 10-year to 20-year planning horizons. Tracks on local capacity needs, planning assumptions, bundled IOU plans. Details on distributed generation modeling and demand-side resource comparisons.

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2012 LTPP Updates

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  1. 2012 LTPP Updates Generation & Transmission Planning Section Nat Skinner, Patrick Young California Public Utilities Commission 12/10/2012

  2. LTPP Overview • Biennial planning process • Determines rules and guidelines for utility procurement and cost recovery • Establish long-term local area and system needs to ensure grid reliability and authorize any needed procurement • Involves coordination between CEC/CAISO/CPUC • Detailed analysis with 10 year planning horizon to make procurement decisions • Broad analysis with 20 year planning horizon to inform policy discussions

  3. 2012 LTPP Components • Currently has three tracks • Track 1: Local Capacity needs for LA Basin & Big Creek / Ventura • Track 2: Planning assumptions, operating flexibility (i.e. renewable integration), system need • Track 3: Bundled IOU plans and procurement rules

  4. Track 1 - Local Areas • Considers authorizing new resources for local reliability purposes over a 10 year horizon • Driven by state’s policy on phasing out once-through-cooled (OTC) technology • Informed by CAISO reliability studies given expected OTC retirements in local transmission-constrained areas • Proposed Decision authorizing procurement, if any is needed, expected December2012

  5. Track 2 - System • Establishes assumptions for use in resource planning • Establishes scenarios to be modeled by CAISO to examine operating flexibility and system reliability needs • Proposed Decision establishing assumptions and scenarios was issued November 20, 2012 • Modeling results (expected spring 2013) will inform system need determination • Decision authorizing procurement, if any is needed, expected end of 2013

  6. Track 3 - Bundled • Assesses and adopts (typically with modifications) the IOUs’ bundled procurement plans pursuant to AB 57 • Looks at any new bundled procurement rules that may be needed • IOUs file Bundled Plans in March 2013 (tentative)

  7. Distributed Generation in LTPP Generation & Transmission Planning Section Nat Skinner, Patrick Young California Public Utilities Commission 12/10/2012

  8. 2012 LTPP Track 1 • CAISO power flow modeling in local areas • Uses 2009 California Energy Demand forecast (CED) • Only one of five modeling scenarios included any level of uncommitted DG projected by the CEC • Committed DG projections are embedded in the CED and include funded, established programs • Uncommitted DG projections are incremental to the CED and include unfunded or not yet established programs with a reasonable expectation of future implementation • Assumptions needed at the busbar level to sufficiently model grid within local areas

  9. 2012 LTPP Track 2 • Aggregates different combinations of demand and supply assumptions to create several scenarios • The scenarios serve as basic inputs to advanced modeling that will study system reliability and operating flexibility needs • In general, each demand and supply assumption has a low, mid, and high forecast value • Assumptions needed at the zonal level • The demand assumption starts with the 2011 California Energy Demand forecast (CED) • Committed DG (self-generation) is embedded in the CED

  10. Managed demand forecast • The LTPP analysis creates a “managed” forecast assumption by adjusting the CED by a projection of programs or expectations not accounted for in the CED • Example: The CED was released before a Commission decision this year that effectively raised the Net Energy Metering cap. The projected impact is further small PV growth beyond that embedded in the CED. • Managed forecast calculation: 53,674 CED – 4,506 incremental EE – 1,803 incremental small PV – 531 incremental demand side CHP = 46,833 MW

  11. Demand side DG assumptions • Incremental small PV • Based on an extrapolation of the effects of Net Energy Metering cap definition described by D.12-05-036 • Peak demand impact assumptions in 2020: • Low = 0 MW : assumes no effect from the NEM cap increase • Mid = 710 MW : assumes about 50% of the NEM cap increase is filled out by additional small PV installations • High = 1803 MW : assumes the NEM cap is reached

  12. Demand side DG assumptions • Incremental demand side CHP • Based on CEC sponsored consultant report on CHP potential • http://www.energy.ca.gov/2012publications/CEC-200-2012-002/CEC-200-2012-002-REV.pdf • Peak demand impact assumptions in 2020: • Low = 0 MW : assumes any new CHP replaces retiring CHP • Mid = 452 MW : reflects the “base” case of the report on CHP potential, which assumes SGIP expiration in 2016 • High = 531 MW : reflects the “mid” case of the report on CHP potential, which assumes SGIP extension beyond 2016

  13. Demand side resources comparison Tracking DG goals

  14. Demand side DG modeling • For advanced modeling, demand side DG will be modeled as supply resource to quantify its effects/benefits to grid reliability • Modeling types: • Production cost simulation, operational flexibility studies • System reliability, planning reserve margins • Powerflow modeling used in Transmission Planning Process (TPP), and stability and local reliability studies • Current self generation data is disaggregated by service area which is adequate for operational flexibility and system studies • Current LTPP modeling underway in January 2013 • TPP modeling expected to start mid 2013

  15. DG data requirements • Have limited data: • Installed capacity (aggregate MW) • Peak demand impact (aggregate MW) • Energy production (aggregate GWh) • Technology type (rooftop PV, CHP, others) • Need: • More granularity (disaggregation) of the current data, e.g. : • Locational (@ busbar) • Technology characteristics (includes smart inverter?)

  16. Questions • CEC and CAISO to specify exact data needs? • (Currently, they do a lot of the advanced modeling requiring granular data) • How do we forecast where DG will be sited? • Is sufficient technical data on DG installations being collected and by whom? • What data can CPUC’s Customer Generation group provide, now and in the future? • To what extent can DG data be included in the IEPR? • (IEPR may not need the granular data, but LTPP and TPP do)

  17. Thank you! For Additional Information: www.cpuc.ca.gov www.GoSolarCalifornia.ca.gov www.CalPhoneInfo.com

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