Monthly average of RTD Intervals with insufficient down ramping capacity followed an upward trend in the past four months. 5.00% 500 4.50% 4.00% 400 3.50% Number of Intervals 3.00% 300 2.50% 2.00% 200 1.50% 1.00% 100 0.50% 0 0.00% Jan-11 Feb-11 Mar-11 Apr-11 May-11 Jun-11 Jul-11 Aug-11 Sep-11 Oct-11 Nov-11 Dec-11 Jan-12 Feb-12 Mar-12 Apr-12 May-12 Jun-12 Jul-12 Aug-12 Sep-12 Oct-12 Nov-12 Dec-12 Jan-13 Feb-13 Mar-13 Apr-13 May-13 5-minute intervals with insufficient downward ramping capability percent of intervals with insufficient downward ramping capability Page 23
$Millions Real-time congestion offset costs increased in May. -10 10 20 30 40 50 60 0 Jan-11 Feb-11 Mar-11 Apr-11 May-11 Jun-11 Congestion Imbalance Offset Jul-11 Real-time Congestion and Energy Imbalance Offset Cost Aug-11 Sep-11 Oct-11 Nov-11 Dec-11 Jan-12 Feb-12 Mar-12 Apr-12 Energy Imbalance Offset May-12 Jun-12 Jul-12 Aug-12 Sep-12 Oct-12 Nov-12 Dec-12 Jan-13 Feb-13 Mar-13 Slide 24 Apr-13 May-13
Exceptional dispatch volume stayed low relative to last year. Total Exceptional Dispatch as Percent of Load 0.025 0.02 % of Total Load 0.015 0.01 0.005 0 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 2009 2010 2011 2012 2013 Page 25
Daily exceptional dispatches – by reason 3.00% 2.50% 2.00% % of Total Load 1.50% 1.00% 0.50% 0.00% 1-Mar 3-Mar 5-Mar 7-Mar 9-Mar 11-Mar 13-Mar 15-Mar 17-Mar 19-Mar 21-Mar 23-Mar 25-Mar 27-Mar 29-Mar 31-Mar 2-Apr 4-Apr 6-Apr 8-Apr 10-Apr 12-Apr 14-Apr 16-Apr 18-Apr 20-Apr 22-Apr 24-Apr 26-Apr 28-Apr 30-Apr Unit Testing COI Mitigation Software Limitation Path 15 Load Forecast Uncertainty Communication Outage Transmission Outage 7820 Other Page 26
$Millions driven by the increase in IFM. Bid cost recovery (BCR) costs rose in May, mainly 10 12 14 16 18 20 0 2 4 6 8 Jan-11 Feb-11 Mar-11 Apr-11 May-11 Jun-11 Jul-11 Aug-11 Sep-11 Oct-11 Nov-11 IFM Dec-11 Jan-12 RT Feb-12 Mar-12 Apr-12 RUC May-12 Jun-12 Jul-12 Aug-12 Sep-12 Oct-12 Nov-12 Dec-12 Jan-13 Feb-13 Mar-13 Page 27 Apr-13 May-13
Mip Gap ($) MIP gap performance was good in April and May. 100,000 10,000 20,000 30,000 40,000 50,000 60,000 70,000 80,000 90,000 0 1/1/11 2/1/11 3/1/11 4/1/11 5/1/11 6/1/11 7/1/11 8/1/11 9/1/11 Daily Dollar 10/1/11 11/1/11 12/1/11 1/1/12 2/1/12 3/1/12 30 Day Moving Average 4/1/12 5/1/12 6/1/12 7/1/12 8/1/12 9/1/12 10/1/12 11/1/12 12/1/12 1/1/13 2/1/13 3/1/13 Page 28 4/1/13 5/1/13
$Millions Flexi-ramp constraint costs declined since March. 0 1 2 3 4 5 6 Dec-11 Jan-12 Feb-12 Mar-12 Apr-12 May-12 Monthly Flexi-Ramp Cost Jun-12 Jul-12 Aug-12 Sep-12 Oct-12 Nov-12 Dec-12 Jan-13 Feb-13 Mar-13 Apr-13 Slide 29 May-13
Price corrections decreased in April. Page 30
Price corrections decreased in April. Page 31
GHG Update Amelia Blanke Market Monitoring Analyst, Department of Market Monitoring Slide 32
Greenhouse gas update • Greenhouse gas costs were included as part of resource commitment costs, default energy bids and generated bids starting in January 2013. – These costs were added as part of the commitment cost refinement process in 2012. – The ISO greenhouse gas index price uses an average of two indices and primarily has ranged from $14 - $16/mtCO 2 e in the first quarter. • Most bids for units subject to greenhouse gas increased by less than $10/MWh, which is in line with emissions rates and allowance prices. • Wholesale energy prices increased by $6.15 - $6.21/MWh in the first quarter due to GHG costs (statistically estimated). • Imports increased 10 percent compared to the same period last year, but the mix of importers has changed. • Further detail can be found in the Department of Market Monitoring’s Q1 2013 Report on Market Issues and Performance : http://www.caiso.com/Documents/2013FirstQuarterReport-MarketIssues_Performance-May2013.pdf Page 33
ISO greenhouse gas price index Greenhouse gas allowance price index ($/mtCO2e) $20.00 $19.00 $18.00 $17.00 $16.00 $15.00 $14.00 $13.00 $12.00 $11.00 $10.00 01-Jan 15-Jan 29-Jan 12-Feb 26-Feb 12-Mar 26-Mar Page 34
Implied heat rate = electricity price / gas price 12 Implied heat rate Average implied heat rate Implied heat rate (mmBTU/MWh) 11 10 9 8 Difference in implied heat rate = 10.03 - 8.57 = 1.47 7 Average gas price: = 4.23 Greenhouse gas price effect = 1.47 * 4.23 = $6.21/MWh 6 5 1-Nov 4-Nov 11-Nov 18-Nov 25-Nov 2-Dec 9-Dec 16-Dec 23-Dec 30-Dec 1-Jan 6-Jan 13-Jan 20-Jan 27-Jan 3-Feb 10-Feb 17-Feb 24-Feb 3-Mar 10-Mar 17-Mar 24-Mar 31-Mar 2012 2013 Page 35
Estimated greenhouse gas price impact: first quarter regression results • Average electricity price = β 0 + β 1 Gas PGE + β 2 Gas SCE1 + β 3 Gas SCE2 +β 4 Load + β 5 Load 2 + β 6 Peak + B 7 Peak ∗ Gas PGE + β 8 Peak ∗ Gas SCE1 + β 9 Peak ∗ Gas SCE2 + β 10 Peak ∗ Load + β 11 Peak ∗ Load 2 + β 12 GHG + ε • Dependent variable: daily average day-ahead market system marginal energy prices for peak and off-peak. • Time period covered: November 1, 2012 through March 31, 2013 • Regression Statistics: N = 300, R 2 = 0.83 • Estimated GHG impact: – Indicator: β 12 estimate = $6.15/MWh (SE = 0.47) – Index price: β 12 estimate = $0.421/ per $/MWh (SE = 0.03) Page 36
Policy Update Brad Cooper Manager, Market Design and Regulatory Policy Slide 37
Market design initiatives coming soon • Multi-year forward reliability capacity pricing mechanism − Upcoming FERC Technical Conference • Load Granularity Refinements − Targeted to start June • Full Network Model Expansion − Targeted to start June • Reliability Demand Response and PDR - Order 745 Compliance Mod − Targeted to start September Page 38
Market initiatives going to the Board for approval Initiative Board Presentation Contingency Modeling Enhancements September Revision of Price Corrections Process September Energy Imbalance Market November Full Network Model Expansion November Flexible Resource Adequacy Criteria November and Must Offer Obligations Load Aggregation Point Granularity December Interconnection Process December Enhancements Page 39
Infrastructure Update Debi Le Vine Director, Infrastructure Contracts & Management Slide 40
Transmission Overview • Red Bluff 500/220 kV Substation completed 5/22 • Devers – Mirage Split completed 6/1 • SCE-Owned Eldorado 220 kV Switchyard completed 6/3 • Colorado River 500/220 kV Substation • Energize Colorado River - Red Bluff 500 kV line • Drew Substation • Four Corners Entitlement Termination – 7/1 Page 41
Four Corners Transition – Big Picture • Effective 7/1/2013, SCE entitlement on Eldorado-Moenkopi east of the Colorado River and Moenkopi-Four Corners is terminated – New scheduling point between APS and CAISO is WILLOWBEACH versus MOENKOPI500 or FOURCORNE345 • APS Balancing Area will include: – Four Corners – Moenkopi – Moenkopi – Willow Beach • CAISO Balancing Area will include: – Willow Beach – Eldorado 500 kV • ISO’s markets will implement the new scheduling point and MSL effective 7/1/2013 • This is not a BAA boundary change, only a scheduling point change Page 42
Existing Network topology 4/1/2009 – 6/30/2013 Navajo Crystal 500 kV 500 kV 6123 McCullough X 500 kV 6047 FCORNER5_MSL FCORNER3_MSL McCullough MCCULLGH_MSL 500 kV 26048 Moenkopi 4 Corners 4 Corners 500 kV 500 kV 345 kV 14002 El Dorado 500 kV 24042 ELDORADO_MSL CAISO Boundary
Network topology changes effective 7/1/2013 Navajo Crystal 500 kV 500 kV Scheduling points deactivated 6123 McCullough X 500 kV 6047 McCullough MCCULLGH_MSL 500 kV 26048 ELDORADO_MSL Moenkopi 4 Corners 4 Corners 500 kV 500 kV 345 kV 14002 Willow Beach 500 kV El Dorado 500 kV 24042 Active scheduling point is WILLOWBEACH CAISO Boundary
Tag and Bidding Examples - Today TAGS Transmission Point of Receipt Point of Delivery Scheduling Provider Entity CISO MOENKOPI500 ELDORADO500 AZPS CISO ELDORADO500 SP15 CISO BIDS SC_MOENKOPI500_I_F_xxxx SC_MOENKOPI500_E_F_xxxx
Tag and Bidding Examples – Trade Date 7/1/2013 TAGS Transmission Point of Receipt Point of Delivery Scheduling Provider Entity AZPS MOENKOPI500 WILLOWBEACH AZPS CISO WILLOWBEACH SP15 CISO BIDS SC_WILLOWBEACH_I_F_xxxx SC_WILLOWBEACH_E_F_xxxx
Next Steps • SCs must register for the new WILLOWBEACH scheduling point (ITIE and ETIE) – Registration is currently available – Effective date will be in accordance with regular MasterFile update timelines • WILLOWBEACH is already registered in TSIN and EIR • SC will need to obtain transmission service from APS for MOENKOPI500 - WILLOWBEACH Page 47
System Operations 2013 Summer Assessment Nancy Traweek Director, System Operations Slide 48
Topics 2012 Recap 2013 Summer Operations Assessment Hydro & Fire predictions Resources at System Peak Reserves Local Reliability Concerns without San Onofre Page 49
2012 Review Instantaneous Peak Demand – 8/13/2012 at 15:53:11 ISO – 46,847 MW (Hourly Average – 46,675 MW) NP 26 – 19,883 MW SP 26 – 26,964 MW Generation at ISO Instantaneous Peak – 8/13/2012 at 15:53:11 Hydro – 4,963 MW Thermal – 36,869 MW Peakers – 1,596 MW Solar – 692 MW Wind – 801 MW Qualified Facilities – 4,213 MW Net Interchange at ISO Instantaneous Peak Imports – 9,389 MW Page 50
2013 Summer Operations Assessment Page 51
2013 Hydrologic Conditions: Key Reservoir Storages As of date: 5/2/2013 Page 52
California Snow Water Content:15%of April 1 Average As of date: 5/2/2013 Statewide Percent of April 1: 15%
Precipitation Cal Fire presentation 5-22-2013
Cal Fire presentation 5-22-2013
Live Fuel Moisture Cal Fire Presentation 5-22-2013
Cal Fire presentation 5-22-2013
ISO 2013 1-in-2 peak demand forecast is 47,413 MW ISO 1-in-2 Peak Load Forecasts based on Economic Base Case & 4 Scenarios 52,000 Annual Peak Demand (MW) 51,000 50,000 49,000 47,413 MW 48,000 47,000 46,000 45,000 44,000 43,000 42,000 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 Historical Forecast Economic Scenario-1 Economic Scenario-2 Economic Scenario-3 Economic Scenario-4 Economic Base Case Slide 58
Historical and Projected ISO Peak Demand ISO, SP26 and NP26 Monthly Peak Demand (MW) (Actual Peak from Jan/06 to Apr/13 and Projected 2013 Annual Peak) 47,413 - 2013 50,085 - 7/24/06 45,809 - 9/3/09 46,675 - 8/13/12 52,000 Monthly Peak Demand (MW) 44,000 36,000 27,253 - 2013 22,632 - 7/25/06 26,712 - 8/13/12 28,251 - 8/31/07 20,136 - 8/13/12 28,000 20,000 21,328 - 2013 12,000 Jan-06 Sep-06 Jan-07 Sep-07 Jan-08 Sep-08 Jan-09 Sep-09 Jan-10 Sep-10 Jan-11 Sep-11 Jan-12 Sep-12 Jan-13 May-06 May-07 May-08 May-09 May-10 May-11 May-12 May-13 SP26 NP26 ISO 0 1 2 Page 59
Estimated On-peak Generation 2013 ISO Summer On-Peak NQC by Fuel Type Natural Gas 71.2% Coal 0.5% Hydro 15.4% Nuclear 4.4% Geothermal Oil 2.2% Solar 0.7% Wind Biogas Biomass 2.0% 2.3% 0.5% 0.9% The existing generation of 50,177 MW NQC did not include SONGS unit 2& 3 as well as Huntington Beach Units 3 & 4. The NQC is the maximum capacity eligible and available for meeting the CPUC resource adequacy requirement counting process. Page 60
Generation additions from April 2 to June 1, 2013 Page 61
Projected moderate import Imports (MW) ISO SP26 NP26 High 11,400 11,300 3,000 Moderate 9,800 9,800 2,100 Low 8,600 9,200 1,300 Page 62
Interruptible Loads and Demand Responses Interuptible & DRs (MW) ISO SP26 NP26 Demand Response 810 536 274 Interruptible Load 1,512 1,245 267 Total Amount 2,322 1,781 541 Page 63
Normal Scenario: On-Peak Resources (MW) ISO SP26 NP26 Existing Generation 50,177 23,380 26,797 Retirement 0 0 0 High Probability Additions 891 735 156 Hydro Derate (1,022) (239) (782) Outages (1-in-2 Generation) (5,067) (1,866) (2,994) Net Interchange (Moderate) 9,800 9,800 2,100 2,322 1,781 541 DR & Interruptible Programs 57,101 33,591 25,818 Total Resources Demand (1-in-2 Summer Temperature) 47,413 27,253 21,328 Operating Reserve Margin 20.4% 23.3% 21.1% The outage calculation excluded SONGS units 2 and 3 because the existing generation did not include them. Page 64
Extreme Scenario: On-Peak Resources (MW) ISO SP26 NP26 50,177 23,380 26,797 Existing Generation 0 0 0 Retirement 891 735 156 High Probability Additions (1,022) (239) (782) Hydro Derate (6,704) (3,500) (4,132) High Outages (1-in-10 Generation ) 8,600 9,200 1,300 Net Interchange 2,322 1,781 541 DR & Interruptible Programs 54,264 31,357 23,880 Total Resources High Demand (1-in-10 Summer Temperature) 49,168 29,519 22,290 Operating Reserve Margin 10.4% 6.2% 7.1% 2013 extreme scenario operating reserve margins are above 3% firm load shedding threshold for ISO, SP26 and NP26.
Operating Reserve Margins are greater than 15% under Normal Scenario and 3% under Extreme ISO, SP26 and NP26 Operating Reserve Margins at 2013 Summer Peak ISO 25% SP26 23.3% NP26 21.1% Operating Reserve Margin (%) 20.4% 20% 15% 10.4% 10% 7.1% 6.2% 5% 3% Firm Load Shedding 0% Normal Scenario Extreme Scenario Page 66
Local Reliability Concerns due to SONGS Outage Page 67
LA Basin and San Diego is at risk under Category C Contingency without SONGS Based on the most critical Category C contingency • Either 1,241 MW shortfall in Los Angeles Basin, or • 467 MW shortfall in San Diego sub-area. Category C Contingency: Overlapping outage of Sunrise 500 kV line followed by outage of Southwest Powerlink 500 kV line Page 68
Status of Key Actions to Mitigate Local Reliability Concerns in Southern Orange and San Diego County: • Convert Huntington Beach units 3 & 4 into synchronous condensers • expected to be completed by June 26 • Install 80 MVAR capacitors at Santiago and Johanna substations, and 2x80 MVAR capacitors at Viejo • upgrades should be on line by June 1, 2013 • Reconfigure Barre – Ellis 220 kV lines from existing two circuits to four circuits • expected to be completed by June 15, 2013 • Work with generation developers to get new generation resources on-line as scheduled for this summer • Dispatch Demand side resources
Overview of the mitigation plan in LA Basin and San Diego Page 70
Conclusion : • Local Reliability Concern in LA Basin and San Diego The mitigation plan is underway to address the LA Basin and San Diego LCR issue • No Reliability Concern at System and Zonal Levels Ample supply is available to meet a broad range of operating conditions at the system and zonal levels Slide 71
Questions ?
Technical Updates Khaled Abdul-Rahman, Executive Director George Angelidis, Principal Li Zhou, Senior Advisor Power Systems Technology Development Page 73
RIMPR Phase 1 and BCR Mitigation • Expected Energy Calculation – Posted as Draft http://www.caiso.com/informed/Pages/StakeholderProcess es/RenewableIntegrationMarketProductReviewPhase1.a spx Final version will be posted as BPM change Page 74
RIMPR Phase 1 and BCR Mitigation… continued • Expected Energy Algorithm – Residual: To detect, Ramping from more than one hour before or after; Ramping due to Pmin re-rate; Ramping due to Exceptional Dispatch – Optimal Energy: To detect, Ramping due to Pmin re-rate; Ramping due to Exceptional Dispatch; ; Page 75
RIMPR Phase 1 and BCR Mitigation… continued • How to address the ramping energy due to the exceptional dispatch (BRQ0025) – A binding exceptional dispatch instruction will be extended forward/backward with the ramping direction; – Once it is extended, the exceptional dispatch energy is calculated in current method for extended intervals; As such, previously classified OE or RIE could be changed to EDE Page 76
RIMPR Phase 1 and BCR Mitigation… continued • How to address the ramping energy due to the Pmin re-rate (BRQ0026, BRQ0027) – A Pmin re-rate will be extended forward/backward with the ramping direction; – Once it is extended, the de-rate energy is calculated in current method for extended intervals; As such, previously classified OE or RIE could be changed to SLIC energy and hence settle as LMP Page 77
RIMPR Phase 1 and BCR Mitigation… continued • How to address the proper reference price used in RIE (BRQ0024) – Reference hour will include the forward terminating time going beyond hourly boundaries; – Done by looking at the ramping direction, economic level and exceptional dispatch MW; As such, the reference price can be a bid price from a trading hour a few hours before or after. Page 78
RIMPR Phase 1 and BCR Mitigation… continued • Questions? Page 79
FERC 764 External Impact • External Business Requirement Specification http://www.caiso.com/informed/Pages/StakeholderProcess es/FERCOrderNo764MarketChanges.aspx Page 80
FERC 764 External Impact - Inter-tie Transmission • Forward Transmission Capacity and Outage continues to be posted in hourly interval on OASIS; • Market used transmission usages will be posted per Day- ahead, Hourly Process and RTPD (15-minute); • Inter-tie shadow prices are already posted per DA, Hourly Process and RTPD. Page 81
FERC 764 External Impact - MF Registration • Static Inter-tie Resource ID still used; • Variable Energy Resource; – Dynamic Scheduling/Pseudo Tie Generator; Alternative inter-tie constraint indication; – Election to use ISO versus own forecast; – PIRP contract indication Page 82
FERC 764 External Impact - MF Registration • Aggregated Dynamic Scheduling/Pseudo Tie Generator – Similar impacts on the ISO, such as being within the same unscheduled flow zone; – Each physical generator model at a substation representing its physical location; – Approvals from both the native BAA and the attaining BAA Page 83
FERC 764 External Impact - MF Registration • ETC/TOR Contract – Revisit of the ETC/TOR to ensure contract rights; – Contract associated with the highest inter-tie constraint – No more MSL association Page 84
FERC 764 External Impact - SIBR • Inter-tie Hourly Bidding Options (Current Static Tie Import/Export) – Hourly block schedule; – Single schedule change per hour for accepted block schedule; – 15-minute market dependence on acceptance in the hourly process; – Ancillary service import can use the hourly block option Page 85
FERC 764 External Impact - SIBR • Eligible Variable Energy Resources – Submission of 5-min forecasts over a rolling horizon; • Generation Resources including TGs – Hourly bid of Capacity Limit; – Capacity Limits will limit the energy/AS Page 86
FERC 764 External Impact - Combined ADS/CMRI • Advisory hourly schedules and prices; • Binding 15-minute schedules and prices; • RTM recognized 5-minute VER forecasts; • Advisory Energy and AS schedules for RTPD horizon; • Partial Accept/Decline functions for both hourly and 15- minute schedules; Page 87
FERC 764 External Impact - Tagging • Follow the tagging rules for transmission and energy profile; Draft Final Proposal FERC 764 - Section 5.2; • Transmission profiles in tags used as capacity limits in both hourly process and 15-minute market; • 15-minute market schedules will be used to automatically update the energy profile of existing tags; • Partial Accept/Decline functions for both hourly and 15- minute schedules. Page 88
FERC 764 External Impact - Metering • 5-minute revenue meter for generation resources; • Load metering continues to be hourly. ISO will divide by 12; • Logical metering will be changed to 5-minute base. Page 89
FERC 764 External Impact - Settlement • Real-time settlement separately using 15-minute and 5- minute LMPs; • 15-minute instructed energy is difference between the 15- minute market and the day-ahead; • 5-minute instructed energy is difference between the 15- minute market and the 5-minute; • Hourly block decline charge applies; • Bid cost recovery calculated on 5-minute base. Page 90
FERC 764 External Impact • Questions? Page 91
Technical User Group Updates Douglas Walker, Lead Enterprise Architect Architecture Slide 92
Technical User Group • Online meetings have moved to a bi-weekly schedule – Scheduled to not conflict with RUG • Roadmaps – Annual review of technical roadmaps • Technical Proof of Concepts – MTOM service payload structure – Federated Security • Acceptable Use – Definition and identification of service issues Slide 93
Release Plan Updates Janet Morris, Director June Xie, Sr. Advisor Program Office Eureka Cullado, Business Solutions Manager, IT Product Development Slide 94
The ISO offers comprehensive training programs Date Training June 11 Introduction to ISO Markets June 12-13 Market Transactions June 20 Welcome to the ISO Web Training Training calendar - http://www.caiso.com/participate/Pages/Training/default.aspx Contact us - markettraining@caiso.com Page 95
Release Plan – 2013 • June 2013 • FERC Order 755 – Pay for Performance activation on June 1, 2013 • CMRI “CRN” Report New API • Fall 2013 • Post Emergency Filing BCR changes / Mandatory MSG is combined with RIMPR-Phase 1 / BCR Mitigation Measures / Bid Floor Cap • Circular Scheduling • Commitment Cost Refinements (remaining scope) • Ancillary Services Buy-Back • PIRP Logic Change • Replacement Requirements for Scheduled Generation Outages Phase 2 • TBD • RIMS Generation (independent effort) • Contingency Modeling Enhancements • DRS API Deployment • Access and Identity Management (independent effort) Page 96
Release Plan – 2014 (proposed) • Spring 2014 • FERC Order 764 Compliance / 15 Minute Market / Dynamic Transfers • Fall 2014 • Energy Imbalance Market (EIM) • Subject to further release planning : • Flexible Ramping Product • iDAM (simultaneous IFM and RUC) • Outage Management System Replacement • Enterprise Model Management System • Subset of Hours • Flexible Resource Adequacy Criteria and Must Offer Obligation Page 97
2013 Release Schedule http://www.caiso.com/Documents/ReleaseSchedule.pdf *Mandatory MSG Market Sim occurs one week per month through October 1 st 2013. Note: SIBR-Lite is no longer available.
Spring 2013 – FERC Order 755 pay for performance Milestone Description/Date SLIC – Provide a regulation outage flag CMRI : provide DA and RT regulation up/down mileage price and awards (DM, UM) DAM/RTM : include mileage bids and requirements into the optimization and generate mileage price and awards Master File : regulation certification based on 10 min ramping capability; provision Application Software Changes of compare and validate reports, ability to cancel batches OASIS : provide DA regulation up/down mileage price (DMR, UMR, DDMP, DUMP, RDMP, RUMP) Settlements : calculate mileage payment, mileage cost allocation and GMC for mileage bids SIBR : receive and validate regulation up/down mileage bid Market Operations Market Instruments Settlements & Billing BPM Changes Definitions & Acronyms Outage Management Maintain Master File, Day Ahead Process, Manage Billing and Settlements, Business Process Changes Manage Analysis Dispute and Resolution, Market Performance (MAD),Market Performance (DMM), Manage AS Certification and Testing External Business Requirements June 7, 2012 May 14,2013 (last update) Nov 16, 2012- MasterFile technical specifications, SIBR rules, charge code list Jan 15, 2013 – Settlements configuration guides Jan 7, 2013 – SLIC, OASIS and CMRI technical specifications Technical Specifications April 4, 2013 – SLIC market Notice V5.0.4 release April 29, 2013 - Updated OASIS Application Release Version 6.3.1 Technical Specifications February 14, 2013 http://www.caiso.com/Documents/Pay- External Training PerformanceRegulationFERC_Order755Presentation.pdf Structure scenario Trade Date 3/14 Market Simulation Structure scenario rerun Trade Date 3/18 Structure scenario rerun Trade Date 5/16 Page 99 Production Activation June 1, 2013
June 2013 Release - CMRI “CRN” Report New API Sample CMRI User Interface Screen Page 100
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