R.09-10-032 Workshop

R.09-10-032 Workshop January 27-28, 2010

Structure • CPUC staff will introduce each topic • Advocates of each proposal may briefly clarify the proposal and note any special considerations (e.g. changes in position) • Open discussion, seeking consensus

Proposed Changes to Agenda • Clarify that relevant CAISO proposal is included in the “DR counting” section • Reverse order of “SCP – exempt resources” and “SCP – replacement obligation” sections

Day 1 Topics • QC Report and non-DR NQC proposals • SCP – replacement obligation • SCP – exempt resources • DR counting • Staff implementation proposals

Day 2 Topics • Continuation of LCR practices • Local true-up, current customer load forecasting, and unbundling of local • Counting distribution resources

Role of the QC Report • To include all rules related to calculating NQC in 1 place • Comment on the report and included proposals • Adopt a complete version in June

Proposals - Hydro • Eliminate “hydro” methodology: • Dispatchable hydro uses “dispatchable generation” methodology • Non-dispatchable hydro uses “non-dispatchable generation”

Proposals – Wind & Solar • For wind & solar, use 1% exceedance as a measure of maximum capacity • QC cannot exceed 100% of maximum capacity

Proposals – Non-dispatchable • Change to these hours: • New resources: • With 1 or more complete summers, use that data • With 0 complete summers: NDC*(average QC/NDC)

CAC Proposals for CHP • CAISO changes: • classification of QF PGAs as non-dispatchable ULRs • eliminate “non-ambient de-rate” from SCP tariff

CAC Proposals for CHP (2) • Firm vs As-available CHP • “Hybrid” CHP • QC for “firm” based on contract, subject to CAISO tests • Monthly NQC values • Extend new unit methodology to expansions • Clarify which existing resources are in calculation • Q: How does CPUC know about a resource expansion?

NQC COUNTING METHODOLOGY FOR COMBINED HEAT AND POWER Tim Lindl, Alcantar & Kahl On behalf of the Cogeneration Association of California

CHP: An Exceptional Puzzle Piece 14 CHP is the only generation type with a business purpose other than producing electricity. CHP’s unique operational characteristics do not easily fit within the RA SCP. 6/9/2014

Solution: Coordinated effort in CPUC and CAISO proceedings 15 • CAISO SCP Phase II: • Normal CHP operations are not “non-ambient de-rates” and will not count against availability standards. • CHP generators with QF PGAs are Non-Dispatchable Use-Limited Resources. • CPUC R. 09-10-032: Approve CAC-proposed NQC counting methodology. 6/9/2014

CAC’s NQC Counting Methodology Proposal 16 • Separate CHP generators on a firm/as-available basis instead of dispatchable/non-dispatchable basis. • As-available: • Monthly NQC • Historical correction for forced outages and temperature-related ambient de-rates 6/9/2014

CAC’s NQC Counting Methodology Proposal (2) 17 • Firm: • Similar method to that for dispatchable resources • Small changes since CHP is not a dispatchable resource • New and added capacity: • As-available: Use ED-proposed equation for all additions of capacity, not just new capacity. • Firm: Use similar method to that for dispatchable resources. 6/9/2014

SCP-Replacement Rule Obligation Background: • CPUC requires LSE’s to replace capacity that will be on planned outage • Many stakeholders have proposed that the CPUC eliminate this rule and replace it within the ISO tariff (This would shift the replacement obligation to the supplier).

Replacement Rule Obligation Proposals • ISO proposes: Supplier provide replacement capacity, else the ISO will: • Deny or Reschedule the outage • Approve the outage and procure replacement through ICPM • Approve the outage and not procure replacement capacity • PG&E, Calpine and AReM support a change to the CAISO tariff that would shift the obligation from the LSE to the supplier. • SCE proposes that the elimination of the scheduled outage counting rule be thought out a bit more. The PRM includes expected outages in its calculation. • CalWEA proposes to apply SCP penalties only to outages with production w/in 2.5% of QC-div benefit. • CAC proposes CHP resources be exempt

SCP for Exempt Resources Background: • On December 14, 2009 Energy Division hosted a workshop on the SCP II which seeks to extend the existing SCP to currently exempt resource types. • On January 26, 2010 California ISO hosted a two hour stakeholder meeting on SCP II Straw Proposal

SCP for Exempt Resources • SCP for Intermittent Resources • Includes: wind, solar, non-dispatahcable cogeneration, non-dispatachable biomass, and non-dispatchable geothermal. • During the December SCP II workshop Energy Division staff suggested that the “Historical Outage Correction” methodology, adopted by D.09-06-028, may be a reasonable approach to ending this exemption. Most parties expressed support for this idea.

SCP for Exempt ResourcesProposals • SCE support ED’s proposal to apply the method described in D.09-06-028 to remove outages from the historical data used for calculation NQC of certain resources. • CAISO proposes CPUC modify the RA counting rules to eliminate forced outages and derate hours or to use proxy energy output values for those hours. • CalWEA proposes to notextend SCP to all resources that are paid on the basis of MWh produced (most RPS) with the exception of UOG RPS • CAC proposes that the CPUC adopt a new counting methodology before adopting including CHP in the SCP

SCP for Exempt Resources • SCP for Demand Response (DR) • In the SCP II Straw Proposal, the ISO deferred DR to another stakeholder process that is more specific to deal with DR issues in relation to RA and SCP.

Changing Hours for DR • Staff proposes changing counted hours • PG&E, SCE oppose this • some DR programs are based on current hours (2-6pm) • Q: When could program designs change?

Avoided Line Losses • PG&E, SCE propose “grossing up” DR for avoided line losses • PUC decisions - 3% gross up to load forecasts

“Supply Side” DR • EnerNOC - Load Impact Protocols (LIPs) cannot measure all DR (e.g. PDR) • Seasonal contract capacity verified by test • What types of DR not handled by LIPs? PDR only?

AC Cycling and Local RA • CAISO - AC cycling should not count for year-round local • Is this unique to AC cycling? • Is this a larger RA structural issue?

Modification to Penalties • An explicit incentive for the timely correction of both RA procurement deficiencies into the RA program rules.

Records Retention • Energy Division shall keep all RA filings and related materials for three calendar years after the end of the compliance year. Staff will generally destroy records past their records retention date, but may retain records for statistical, enforcement or other purposes at Staff discretion.

Load Forecast Adjustments • LSEs may, at the discretion of CEC staff, file changes to their load forecast up to 25 days before the due date of the month-ahead compliance filings.

Continuation of: • Blanket waiver for deficient local areas • PG&E local area aggregation

Local True-up • SES proposal: • Begin quarterly true-ups for changes >5MW in summer 2011 • NP26 v SP26 only • (Customer peak / LSE peak) * LAR • All customer obligations sent to CPUC in Oct.

TURN variations • Use service area local-to-peak ratio for all customers • Current customer forecasting • Unbundle local attribute

What is the Local RA Obligation of a Migrating Customer? 1. Calculate Local-to-Peak Ratio (LPR) for Each IOU Service Territory: LPR = Total Service Territory Local Capacity Requirement (LCR) in MW for Year X + 1, divided by Service Territory Coincident Peak Demand (CPD) in MW at Time of CAISO System Peak in Year X. Published by Energy Division in Fall of Year X for each IOU. Customer Local Obligation (LCR) Equals LPR times Customer Coincident Peak Load in MW at Time of CAISO System Peak in Year X. Potential Need for CEC to make adjustments if calculated values do not mesh well with historical data. Data Sources: LCR comes from CPUC June Decision Setting Next Year’s Local Requirements. Service Territory CPD at Time of CAISO Peak from IOU or CAISO. Customer CPD at Time of CAISO Peak from LSE’s Billing Records

Steps for the Annual Forecast of Local RA Obligations LSEs Submit Load Forecasts for Year X+1 to CEC Early in Year X, Based on Each LSE’s Then-Current Customer Base. CEC Reviews Forecasts, Makes Adjustments As Necessary, and Provides “Final” Forecasts to LSEs by Mid-Year of Year X. Customer In- or Out-Migration for Year X+1 That Is Known by August 1 (?) of Year X Reported to CEC to Adjust Final LSE Forecasts. LSEs Make RA Compliance Filings in October of Year X for Year X+1. Additional Customer In- or Out-Migration for Year X+1 That Is Known by the Start of Year X+1 Results in LSE Local RA Adjustments per Prior Slide. During Year X+1, Additional Customer In- or Out-Migration Is Reported (Monthly/Quarterly) and Results in Additional LSE Local RA Adjustments, also per Prior Slide. LSEs Submit Load Forecasts for Year X+2 to CEC Early in Year X+1 and Process Begins Again.

Distribution Resources • All distribution resources should count • Use same counting rules • “deemed deliverable” • Q: What resources are in this category? What resources are in load forecast? • Q: Is deliverability study possible?

Backup Slides

Summer (May through September)- Any month where days of scheduled outages exceed 25% of days in the month, the resource does not count for RAR. If scheduled outages are less than or equal to 25% the resource does count for RAR. Non-Summer Months (October through April) - For scheduled outages less than 1 week, the resource counts for RAR.For scheduled outages 1 week to 2 weeks, the amount counted for RAR is prorated using the formula:[1 - (days of scheduled outage/days in month) - 0.25] * MW = RARThe formula will allow resources to count between 50% and 25%. For scheduled outages over 2 weeks, the resource does not count for RAR. Scheduled Outages D.06-07-031

R.09-10-032 Workshop