Market Performance and Planning Forum. June 5, 2013

Transcription

1 Market Performance and Planning Forum June 5, 2013

2 Objective: Enable dialogue on implementation planning and market performance issues Review key market performance topics Share updates to release plans, resulting from stakeholders inputs Provide information on specific initiatives to support Market Participants in budget and resource planning Focus on implementation planning; not on policy Clarify implementation timelines Discuss external impacts of implementation plans Launch joint implementation planning process Slide 2

3 Agenda Agenda 10:00-10:05 Introduction, Agenda Mercy P. Helget 10:05 11:30 Market Performance and Quality Update Guillermo Bautista Alderete, Nan Liu, Mark Rothleder GHG Update Amelia Blanke 11:30 11:45 Policy Updates Brad Cooper 11:45 12:15 Infrastructure Updates Debi Le Vine 12:15 1:00 Lunch 1:00 1:30 System Operations 2013 Summer Assessment Nancy Traweek 1:30 2:15 Technical Updates Khaled Abdul-Rahman, Li Zhou, George Angelidis 2:15 2:30 Technical User Group Update Doug Walker 2:30 3:00 Release Plan Updates CMRI CRN API availability Janet Morris, June Xie, Eureka Cullado Slide 3 Note: Agenda is subject to change.

4 Market Performance and Quality Update Market Quality and Renewable Integration Mark Rothleder Dede Subakti Guillermo Bautista-Alderete Nan Liu Slide 4

5 1. Hot topics and follow-up items 2. Market Metrics Price volatility and market convergence RT energy/congestion imbalance offset Convergence bidding Exceptional dispatch Bid cost recovery MIP gap Flex-ramp cost 3. Price Corrections Slide 5

6 Hot topic and follow up items SDGE+CFE+IV_IMP Nomogram Wind schedules: day ahead vs. real-time SP price differentials between RTD and IFM RUC load adjustments Exceptional dispatch reporting Summer outlook Circular schedules Page 6

7 SDGE+CFE+IV_IMP Nomogram In Summer 2012, Hoodoo Wash North Gila 500kV flowgate was binding and congested The Hoodoo Wash North Gila 500kV flowgate was enforced to ensure acceptable voltage performance in Pacific Southwest for N-1 loss of Hoodoo Wash North Gila 500kV line In Summer 2013, infrastructure additions are installed to increase transfer capability across Hoodoo Wash North Gila 500kV In order to continue to ensure voltage performance criteria is met for Orange County, San Diego County, Imperial County and Northern Baja portion for Mexico (CFE) following N-1 contingency of the Hoodoo Wash-North Gila 500kV line, a new nomogram is needed. Page 7

8 Nomogram Definition Posted in CMRI Page 8

9 Summary of Major Nomogram around San Diego and Pacific Southwest

10 1-Jan 5-Jan 9-Jan 13-Jan 17-Jan 22-Jan 26-Jan 30-Jan 3-Feb 7-Feb 12-Feb 16-Feb 20-Feb 24-Feb 28-Feb 5-Mar 9-Mar 13-Mar 17-Mar 22-Mar 26-Mar 30-Mar 3-Apr 7-Apr 12-Apr 16-Apr 20-Apr 24-Apr 28-Apr 3-May 7-May 11-May 15-May 19-May 24-May 28-May MW Wind Schedules in HASP and DA 4,000 3,500 3,000 2,500 2,000 1,500 1, HASP IFM Slide 10

11 1-Jan 5-Jan 9-Jan 13-Jan 17-Jan 22-Jan 26-Jan 30-Jan 3-Feb 7-Feb 12-Feb 16-Feb 20-Feb 24-Feb 28-Feb 5-Mar 9-Mar 13-Mar 17-Mar 22-Mar 26-Mar 30-Mar 3-Apr 7-Apr 12-Apr 16-Apr 20-Apr 24-Apr 28-Apr 3-May 7-May 11-May 15-May 19-May 24-May 28-May $/MWh No change in trend for NP prices between RTD and IFM. NP15 Hourly Price Difference (RTM less IFM) Slide 11

12 1-Jan 5-Jan 9-Jan 14-Jan 18-Jan 22-Jan 27-Jan 31-Jan 4-Feb 9-Feb 13-Feb 17-Feb 22-Feb 26-Feb 2-Mar 7-Mar 11-Mar 15-Mar 20-Mar 24-Mar 28-Mar 2-Apr 6-Apr 10-Apr 15-Apr 19-Apr 23-Apr 28-Apr 2-May 6-May 11-May 15-May 19-May 24-May 28-May $/MWh No change in trend for SP prices between RTD and IFM. 1,200 SP15 Hourly Price Difference (RTM less IFM) 1, Slide 12

13 1-Jan 3-Jan 5-Jan 7-Jan 9-Jan 11-Jan 13-Jan 15-Jan 17-Jan 19-Jan 21-Jan 23-Jan 25-Jan 27-Jan 29-Jan 31-Jan 2-Feb 4-Feb 6-Feb 8-Feb 10-Feb 12-Feb 14-Feb 16-Feb 18-Feb 20-Feb 22-Feb 24-Feb 26-Feb 28-Feb % of Load Forecast RUC Load Adjustment increased in the second half of February. 4.0% 3.5% 3.0% 2.5% 2.0% 1.5% 1.0% 0.5% 0.0% RUC Daily Load Adjustment Slide 13

14 Summer outlook Process is in place to align DA and RT conditions to mitigate price differentials and offset costs. Transmission enhancements are expected to reduce real-time congestion. TRM in place since late summer last year has proven to be beneficial in reducing real-time congestion related to loop flow. Slide 14

15 Exceptional dispatch reporting OASIS reports EDE or exceptional dispatch energy. EDE is the out of sequence or uneconomic energy resulted from exceptional dispatch which is the settled exceptional dispatch amount. Monthly report and MPPF include minimum load energy and EDE. FERC report on exceptional dispatch provides the following: The total volume column: total MWh dispatch quantity dispatched. The ED Volume MWh (MWh INC/DEC) column shows the incremental or the decremental portion of the real-time exceptional dispatch MWh. The MW column shows the range of exceptional dispatch instruction in MW (or the go to MW). Slide 15

16 Circular schedules Implemented circular schedule on 2/1/2013. Identifies circular schedules within the same SC, compares import and export prices and neutralizes the profit if the import price is higher than export price unless exempted. In February, 20 instances of circular schedules detected. No claw back. In March, out of 620 instances detected, only 2 instances of circular schedule profits were neutralized. Slide 16

17 Higher DA monthly average DLAP LMP than RTD LMP in May. Page Jan-11 Mar-11 May-11 Jul-11 Sep-11 Nov-11 Jan-12 Mar-12 May-12 Jul-12 Sep-12 Nov-12 Jan-13 Mar-13 May-13 $/MWh IFM HASP RTD PG&E Jan-11 Mar-11 May-11 Jul-11 Sep-11 Nov-11 Jan-12 Mar-12 May-12 Jul-12 Sep-12 Nov-12 Jan-13 Mar-13 May-13 $/MWh IFM HASP RTD SCE Jan-11 Mar-11 May-11 Jul-11 Sep-11 Nov-11 Jan-12 Mar-12 May-12 Jul-12 Sep-12 Nov-12 Jan-13 Mar-13 May-13 $/MWh IFM HASP RTD SDG&E Jan-13 Feb-13 Mar-13 Apr-13 May-13 $/MWh IFM HASP RTD VEA

18 DLAP LMP Monthly Average (On Peak) Page Jan-11 Mar-11 May-11 Jul-11 Sep-11 Nov-11 Jan-12 Mar-12 May-12 Jul-12 Sep-12 Nov-12 Jan-13 Mar-13 May-13 $/MWh IFM HASP RTD PG&E Jan-11 Mar-11 May-11 Jul-11 Sep-11 Nov-11 Jan-12 Mar-12 May-12 Jul-12 Sep-12 Nov-12 Jan-13 Mar-13 May-13 $/MWh IFM HASP RTD SCE Jan-11 Mar-11 May-11 Jul-11 Sep-11 Nov-11 Jan-12 Mar-12 May-12 Jul-12 Sep-12 Nov-12 Jan-13 Mar-13 May-13 $/MWh IFM HASP RTD SDG&E Jan-13 Feb-13 Mar-13 Apr-13 May-13 $/MWh IFM HASP RTD VEA

19 DLAP LMP Monthly Average (Off Peak) Page Jan-11 Mar-11 May-11 Jul-11 Sep-11 Nov-11 Jan-12 Mar-12 May-12 Jul-12 Sep-12 Nov-12 Jan-13 Mar-13 May-13 $/MWh IFM HASP RTD PG&E Jan-11 Mar-11 May-11 Jul-11 Sep-11 Nov-11 Jan-12 Mar-12 May-12 Jul-12 Sep-12 Nov-12 Jan-13 Mar-13 May-13 $/MWh IFM HASP RTD SCE Jan-11 Mar-11 May-11 Jul-11 Sep-11 Nov-11 Jan-12 Mar-12 May-12 Jul-12 Sep-12 Nov-12 Jan-13 Mar-13 May-13 $/MWh IFM HASP RTD SDG&E Jan-13 Feb-13 Mar-13 Apr-13 May-13 $/MWh IFM HASP RTD VEA

20 $/MWh $/MWh $/MWh $/MWh More volatile RT DLAP LMP on average in May PG&E IFM HASP RTD SCE IFM HASP RTD Hour SCE IFM HASP RTD VEA IFM HASP RTD Page 20

21 Percent of Real Time Intervals Monthly price distributions: Price volatility increased in both positive and negative direction in May. 4.0% 2.0% 0.0% -2.0% Jan-11 Mar-11 May-11 Jul-11 Sep-11 Nov-11 Jan-12 Mar-12 May-12 Jul-12 Sep-12 Nov-12 Jan-13 Mar-13 May % -6.0% -8.0% -10.0% -$30 to -$5 -$100 to -$30 -$300 to -$100 <-$300 $250 to $500 $500 to $750 $750 to $1000 >$1000 Page 21

22 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 Count of Intervals Percent of Intervals Monthly average of RTD intervals with insufficient up ramping capacity continued the downward trend % 1.80% 1.60% 1.40% 1.20% 1.00% 0.80% 0.60% 0.40% 0.20% 0.00% 5-minute intervals with insufficient upward ramping capability percent of intervals with insufficient upward ramping capability Page 22

23 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 Number of Intervals Monthly average of RTD Intervals with insufficient down ramping capacity followed an upward trend in the past four months. 5.00% % 4.00% 3.50% 3.00% 2.50% 2.00% 1.50% 1.00% % 0.00% 5-minute intervals with insufficient downward ramping capability percent of intervals with insufficient downward ramping capability Page 23

24 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 $Millions Real-time congestion offset costs increased in May. 60 Real-time Congestion and Energy Imbalance Offset Cost Congestion Imbalance Offset Energy Imbalance Offset Slide 24

25 % of Total Load Exceptional dispatch volume stayed low relative to last year Total Exceptional Dispatch as Percent of Load Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Page 25

26 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 % of Total Load Daily exceptional dispatches by reason 3.00% 2.50% 2.00% 1.50% 1.00% 0.50% 0.00% Unit Testing COI Mitigation Software Limitation Path 15 Load Forecast Uncertainty Communication Outage Transmission Outage 7820 Other Page 26

27 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 $Millions Bid cost recovery (BCR) costs rose in May, mainly driven by the increase in IFM IFM RT RUC Page 27

28 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 10/1/11 11/1/11 12/1/11 1/1/12 2/1/12 3/1/12 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 4/1/13 5/1/13 Mip Gap ($) MIP gap performance was good in April and May. 100,000 90,000 80,000 70,000 60,000 50,000 40,000 30,000 20,000 10,000 0 Daily Dollar 30 Day Moving Average Page 28

29 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 $Millions Flexi-ramp constraint costs declined since March. 6 Monthly Flexi-Ramp Cost Slide 29

30 Price corrections decreased in April. Page 30

31 Price corrections decreased in April. Page 31

32 GHG Update Amelia Blanke Market Monitoring Analyst, Department of Market Monitoring Slide 32

33 Greenhouse gas update Greenhouse gas costs were included as part of resource commitment costs, default energy bids and generated bids starting in January These costs were added as part of the commitment cost refinement process in 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 $ $6.21/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 Q Report on Market Issues and Performance: Page 33

34 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 $ Jan 15-Jan 29-Jan 12-Feb 26-Feb 12-Mar 26-Mar Page 34

35 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 Implied heat rate (mmbtu/mwh) Implied heat rate = electricity price / gas price Implied heat rate Average implied heat rate Difference in implied heat rate = = 1.47 Average gas price: = 4.23 Greenhouse gas price effect = 1.47 * 4.23 = $6.21/MWh Page 35

36 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

37 Policy Update Brad Cooper Manager, Market Design and Regulatory Policy Slide 37

38 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

39 Market initiatives going to the Board for approval Initiative Contingency Modeling Enhancements Revision of Price Corrections Process Energy Imbalance Market Full Network Model Expansion Flexible Resource Adequacy Criteria and Must Offer Obligations Load Aggregation Point Granularity Interconnection Process Enhancements Board Presentation September September November November November December December Page 39

40 Infrastructure Update Debi Le Vine Director, Infrastructure Contracts & Management Slide 40

41 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

42 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

43 Existing Network topology 4/1/2009 6/30/2013 McCullough X 500 kv 6047 Crystal 500 kv 6123 Navajo 500 kv FCORNER5_MSL McCullough 500 kv MCCULLGH_MSL Moenkopi 500 kv Corners 500 kv FCORNER3_MSL 4 Corners 345 kv El Dorado 500 kv ELDORADO_MSL CAISO Boundary

44 Network topology changes effective 7/1/2013 McCullough X 500 kv 6047 Crystal 500 kv 6123 Navajo 500 kv Scheduling points deactivated McCullough 500 kv MCCULLGH_MSL ELDORADO_MSL Willow Beach 500 kv Moenkopi 500 kv Corners 500 kv 4 Corners 345 kv El Dorado 500 kv Active scheduling point is WILLOWBEACH CAISO Boundary

45 Tag and Bidding Examples - Today TAGS Transmission Provider Point of Receipt Point of Delivery Scheduling Entity CISO MOENKOPI500 ELDORADO500 AZPS CISO ELDORADO500 SP15 CISO BIDS SC_MOENKOPI500_I_F_xxxx SC_MOENKOPI500_E_F_xxxx

46 Tag and Bidding Examples Trade Date 7/1/2013 TAGS Transmission Provider Point of Receipt Point of Delivery Scheduling Entity AZPS MOENKOPI500 WILLOWBEACH AZPS CISO WILLOWBEACH SP15 CISO BIDS SC_WILLOWBEACH_I_F_xxxx SC_WILLOWBEACH_E_F_xxxx

47 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

48 System Operations 2013 Summer Assessment Nancy Traweek Director, System Operations Slide 48

49 Topics 2012 Recap 2013 Summer Operations Assessment Hydro & Fire predictions Resources at System Peak Reserves Local Reliability Concerns without San Onofre Page 49

50 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

51 2013 Summer Operations Assessment Page 51

52 2013 Hydrologic Conditions: Key Reservoir Storages As of date: 5/2/2013 Page 52

53 California Snow Water Content:15%of April 1 Average As of date: 5/2/2013 Statewide Percent of April 1: 15%

54 Cal Fire presentation Precipitation

55 Cal Fire presentation

56 Cal Fire Presentation Live Fuel Moisture

57 Cal Fire presentation

58 Annual Peak Demand (MW) ISO in-2 peak demand forecast is 47,413 MW 52,000 ISO 1-in-2 Peak Load Forecasts based on Economic Base Case & 4 Scenarios 51,000 50,000 49,000 48,000 47,413 MW 47,000 46,000 45,000 44,000 43,000 42, Historical Forecast Economic Scenario-1 Economic Scenario-2 Economic Scenario-3 Economic Scenario-4 Economic Base Case Slide 58

59 Jan-06 May-06 Sep-06 Jan-07 May-07 Sep-07 Jan-08 May-08 Sep-08 Jan-09 May-09 Sep-09 Jan-10 May-10 Sep-10 Jan-11 May-11 Sep-11 Jan-12 May-12 Sep-12 Jan-13 May-13 Monthly Peak Demand (MW) 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) 52,000 50,085-7/24/06 45,809-9/3/09 46,675-8/13/12 47, ,000 36,000 27, ,000 22,632-7/25/06 28,251-8/31/07 26,712-8/13/12 20,136-8/13/12 20,000 21, ,000 SP26 NP26 ISO Page 59

60 Estimated On-peak Generation 2013 ISO Summer On-Peak NQC by Fuel Type Natural Gas 71.2% Coal 0.5% Hydro 15.4% Geothermal 2.2% Biomass 0.9% Biogas 0.5% Wind 2.3% Solar 2.0% Nuclear 4.4% 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. Oil 0.7% Page 60

61 Generation additions from April 2 to June 1, 2013 Page 61

62 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

63 Interruptible Loads and Demand Responses Interuptible & DRs (MW) ISO SP26 NP26 Demand Response Interruptible Load 1,512 1, Total Amount 2,322 1, Page 63

64 Normal Scenario: On-Peak Resources (MW) ISO SP26 NP26 Existing Generation 50,177 23,380 26,797 Retirement High Probability Additions 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 DR & Interruptible Programs 2,322 1, Total Resources 57,101 33,591 25,818 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

65 Extreme Scenario: On-Peak Resources (MW) ISO SP26 NP26 Existing Generation 50,177 23,380 26,797 Retirement High Probability Additions Hydro Derate (1,022) (239) (782) High Outages (1-in-10 Generation ) (6,704) (3,500) (4,132) Net Interchange 8,600 9,200 1,300 DR & Interruptible Programs 2,322 1, Total Resources 54,264 31,357 23,880 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.

66 Operating Reserve Margin (%) 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 25% 20% 20.4% 23.3% 21.1% ISO SP26 NP26 15% 10% 10.4% 5% 6.2% 7.1% 0% Normal Scenario Extreme Scenario 3% Firm Load Shedding Page 66

67 Local Reliability Concerns due to SONGS Outage Page 67

68 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

69 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

70 Overview of the mitigation plan in LA Basin and San Diego Page 70

71 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

72 Questions?

73 Technical Updates Khaled Abdul-Rahman, Executive Director George Angelidis, Principal Li Zhou, Senior Advisor Power Systems Technology Development Page 73

74 RIMPR Phase 1 and BCR Mitigation Expected Energy Calculation Posted as Draft es/renewableintegrationmarketproductreviewphase1.a spx Final version will be posted as BPM change Page 74

75 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

76 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

77 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

78 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

79 RIMPR Phase 1 and BCR Mitigation continued Questions? Page 79

80 FERC 764 External Impact External Business Requirement Specification es/fercorderno764marketchanges.aspx Page 80

81 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 Dayahead, Hourly Process and RTPD (15-minute); Inter-tie shadow prices are already posted per DA, Hourly Process and RTPD. Page 81

82 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

83 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

84 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

85 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

86 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

87 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

88 FERC 764 External Impact - Tagging Follow the tagging rules for transmission and energy profile; Draft Final Proposal FERC 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

89 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

90 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

91 FERC 764 External Impact Questions? Page 91

92 Technical User Group Updates Douglas Walker, Lead Enterprise Architect Architecture Slide 92

93 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

94 Release Plan Updates Janet Morris, Director June Xie, Sr. Advisor Program Office Eureka Cullado, Business Solutions Manager, IT Product Development Slide 94

95 The ISO offers comprehensive training programs Date June 11 June June 20 Training Introduction to ISO Markets Market Transactions Welcome to the ISO Web Training Training calendar - Contact us - markettraining@caiso.com Page 95

96 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

97 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

98 2013 Release Schedule *Mandatory MSG Market Sim occurs one week per month through October 1 st Note: SIBR-Lite is no longer available.

99 Spring 2013 FERC Order 755 pay for performance Milestone Description/Date Application Software Changes 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 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 BPM Changes Business Process Changes Market Operations Market Instruments Settlements & Billing Definitions & Acronyms Outage Management Maintain Master File, Day Ahead Process, Manage Billing and Settlements, 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) Technical Specifications External Training Market Simulation Production Activation June 1, 2013 Nov 16, MasterFile technical specifications, SIBR rules, charge code list Jan 15, 2013 Settlements configuration guides Jan 7, 2013 SLIC, OASIS and CMRI technical specifications April 4, 2013 SLIC market Notice V5.0.4 release April 29, Updated OASIS Application Release Version Technical Specifications February 14, PerformanceRegulationFERC_Order755Presentation.pdf Structure scenario Trade Date 3/14 Structure scenario rerun Trade Date 3/18 Structure scenario rerun Trade Date 5/16 Page 99

100 June 2013 Release - CMRI CRN Report New API Sample CMRI User Interface Screen Page 100

101 June 2013 Release - CMRI CRN Report New API CRN XML files Currently: Posted on the sftp site To Be: New CMRI retrievecontractusage API to be made available. Access will be granted to users who have existing CRN GUI report access already. Technical docs postings Release Planning Page - June 2013 CMRI technical specifications subheading retrievecontractusage Interface Specifications retrievecontractusage Artifacts Package (xsd, wsdl) Release Notes document Timeline June : June 27: June 30: July 31: Further updates via market notice communication Market Simulation open Production drop New CMRI API effective TD 6/27/2013 DA & RT markets Last Trade Date (TD) to exist on the sftp site Last calendar date to retrieve XML files from the sftp site Page 101

102 Access and Identity Management (AIM) Milestone Application Software Changes Date The goal of the AIM project is to improve upon the existing approach for establishing, updating and terminating access to applications as well as providing visibility (transparency), ease of use and self-service where appropriate to POCs (Points of Contact), internal ISO users, business units and IT to manage this process from end to end. AIM: New system with UI and workflow BPM Changes Definitions and Acronyms (For AIM Release 1) Business Process Changes IT Access Mgmt. - Certificate based application access; Metering systems access Board Approval N/A External Business Requirements Jan 31, 2013 Updated BPMs Market Simulation Tariff TBD N/A N/A Production Activation Currently being rescheduled Page 102

103 Fall 2013 RIMPR Phase 1 / BCR Mitigation / Bid Floor Application Software Changes Implementation Impact Assessment IFM/RTM: Energy Bid Floor to -$150/MWh MQS: Modify MLC calculation and cost allocation rules. Change DA MLC determination Program PUIE calculation (may need to change MQS energy algorithm) Split netting between DA and RT markets. Settlements: Requires a tune-up on formulas to determine the ON criteria for resources, and the eligibility for Bid Cost Recovery. Modify and build up to 12 charge codes to implement new BCR netting rules and MLC. Program PUIE (persistent UIE) calculation. Program new RT PM (performance metric) calculation. Offset DA MLC by MLE revenues. Develop a number of BCR mitigation measurements SIBR: SIBR rule changes will be needed to change the bid floor from -$30 (soft) to -$150 (hard). CMRI: RTM to publish all advisory schedules including current and next hour in the horizon for RTPD runs Post relevant startup or transition time period for each startup cost or transition cost period from MQS in the commitment cost report Post energy allocation based on the default energy bid Post relevant startup ramp time or transition ramp time periods from MQS Monthly Market Reports incorporating greater granularity in reporting BCR components have been made available. Page 103

104 Fall 2013 RIMPR Phase 1 / BCR Mitigation / Bid Floor Milestone BPM Changes Business Process Changes Board Approval Date Settlements & Billing, Market Operation, Market Instrument Manage Billing and Settlements, Market Performance Bid Floor and BCR netting: December 15-16, 2011 Post Emergency BCR / Mandatory MSG: Feb 15, 2012 BCR Mitigation Measures: December, 2012 External Business Requirements April 19, 2013 (Post Emergency BCR posted on Feb 1, 2013) Technical Specifications July 3, 2013 Updated BPMs August 9, 2013 Market Simulation August 2013 Tariff June 2013 Production Activation Fall 2013 (October 1, 2013) release date under reconsideration Page 104

105 Fall 2013 Circular Scheduling Milestone Date Application Software Changes BPM Changes Business Process Changes Masterfile: Creation of new field to capture attestation letter submission. CAS: Identify the circular schedules MW, import/export resource IDs for the single e-tag, with source/sink at the same BAA; the BAA could be CAISO or other BAA; Exclude dynamic, DC segment, open intertie, Wheeling through for load. CRR Claw Back/MQS: Identify the SC s affiliation for single SC and circular schedule MW. Build new rule of calculate value the claw-back CRR in dollars. Settlement: Identify the SC s affiliation for single SC. Identify the circular schedule Import applicable IFM and HASP scheduled MW. Build Settlement rule the settle the import schedule at lower LMP of Import/export. Circular schedule is not eligible for BCR for the interval. Market Operations, Market Instruments, Settlements & Billing Manage Interchange Scheduling, Manage MQS, Manage Billing and Settlements Board Approval March 2012 External Business Requirements March 22, 2013 Updated BPMs August 5, 2013 Technical Specifications N/A Draft Configuration Guides 7/3/13 Market Simulation August 13, 2013 August 23, 2013 Tariff Production Activation Filed November 21, 2012 Approved January 30, 2013 Fall 2013 (October 1, 2013) release date under reconsideration Page 105

106 Fall 2013 Commitment Cost Refinement Milestone Application Software Changes Date Masterfile: Creation of new field to capture resource specific characteristics. Settlements: Operational Flow Orders, NOx, and Sox penalties must be submitted ex post under circumstances attributable to exceptional dispatch and real-time commitments. These costs will be included in a re-evaluation of the real-time BCR calculation for that day with the Operational Flow Orders (OFO) costs added into the calculation of the generator s net shortfall or surplus over that day. Must establish an interface in which Market Participants can enter data to flow directly to Settlements. The long-term service agreement costs refer to the major maintenance costs. The ISO is working with POTOMAC to develop a template and will share the template with Stakeholders at first quarter of BPM Changes Business Process Changes Market Instruments Billing & Settlements Manage Reliability Requirements Board Approval May 2012 External Business Requirements April 30, 2013 Updated BPMs August 9, 2013 Market Simulation August 2013 Tariff July 2013 Production Activation Fall 2013 Release (October 1, 2013) release date under reconsideration Page 106

107 Fall 2013 AS Buy Back Milestone Description/Date RTM: Operators will have the ability to manually force a buy back due to resource or transmission constraints. Application Software Changes Settlements: Settlements will need to map to the new payload element that will indicate the reason for disqualification. Fourteen Charge Codes related ancillary services are impacted. MQS will need to correct the new output from RTM BPM Changes Business Process Changes Settlements & Billing, Market Operations Manage Billing and Settlements Board Approval July 13, 2012 External Business Requirements February 28, 2013 Updated BPMs August 5, 2013 Technical Specifications N/A Draft Configuration Guides 7/3/13 Tariff Filed January 3, 2013 Anticipating FERC decision in June 2013 Market Simulation August 6, 2013 August 23, 2013 Production Activation Fall 2013 Release (October 1, 2013) release date under reconsideration Page 107

108 Fall PIRP Logic Change Milestone Date Application Software Changes BPM Changes Business Process Changes RTM: Dispatch VER based on its economic energy bid with the forecast as its Pmax. PIRP: Provide the hourly PIRP forecast for RTM. Determine if the PIRP hourly eligibility in UIE monthly netting based on PIRP s RTM DOT and the hourly forecast For the PIRP unit and/or hours that continues to use self schedule to participate, the existing production logic stays the same Settlements: Perform PIRP resource monthly UIE netting based on the hourly eligibility determined by PIRP. Market Operations, Market Instrument Manage Billing and Settlements, Market Performance Board Approval May 15, 2013 External Business Requirements May 20, 2013 Technical Specifications Not Applicable Updated BPMs August 5, 2013 Market Simulation August 2013 Structured Scenario timeframe Tariff August 2013 Production Activation Fall 2013 (October 1, 2013) release date under reconsideration Slide 108

109 Fall 2013 RIMS Generation Milestone Application Software Changes BPM Changes Business Process Changes Board Approval Date RIMS Generation module will be changed, including a revamp of the external user interface. Changes include pre-programmed notifications (based on approaching deadlines, status changes, new project creation), canned reporting and ability to push reports to project contacts. External access will be granted with an ability to upload data and attachments directly to the system. Dashboard will be enhanced to provide accurate project statuses, filtering and export functions. N/A Manage New Participating Generator Interconnections N/A External Business Requirements April 10, 2013 Technical Specifications Updated BPMs N/A because there is no API. However, there will be an external UI for participants, and a user guide related to this UI will be provided six weeks in advance of the market simulation. N/A Market Simulation After Fall 2013 Tariff N/A Production Activation TBD Page 109

110 Fall 2013 Replacement Requirement for Scheduled Generation Outages Phase 2 (RRSGO P2) Milestone Application Software Changes Date IRR: TBD RAAM: TBD SLIC: TBD BPM Changes NEW Monthly RA Workshops Board Approval July 12, 2012 External Business Requirements End of June Replacement Requirements Resource Adequacy Resource Planned Outage Reporting Second Monday of each month from 1:30 3:00 PM (May 17, 2013 first call) Technical Specifications Updated BPMs N/A TBD Market Simulation Fall 2013 Tariff Production Activation FERC Filing September 20, 2012 FERC Order Conditional Acceptance November 19, 2012 FERC Compliance Filing December 19, 2012 Request for Rehearing December 19, 2012 Annual October 2013 Monthly December 2013 Page 110

111 Spring 2014 release - FERC 764 Application Software Changes Implementation Impact Assessment MasterFile: Identify variable energy resources and their selection of using ISO VER forecast or their own VER forecast. IFM/RTM: A new 15-Minute market with financially binding energy and AS awards for internal generators, imports/exports, and participating loads. Real time bid submission process remains same Cleared against the CASIO forecast of real time demand Executed 37.5 minutes prior to the start of the binding interval, 15 minutes earlier than the current 22.5 minute prior to the binding of RTUC run Allow a number of bidding options for an intertie A new hourly process to produce the advisory hourly block schedule for the non-dynamic intertie transaction that will be used for subsequent 15-minute market. Convergence bidding will be allowed on intertie scheduling point. All convergence bids will be settled between the day-ahead market and the 15-minute market The physical only constraint at the scheduling point of the dual constraints not enforced in the IFM but enforced in RUC. RUC establishes the number of etags it can accept for day-ahead physical market awards. 15-minute market and 5-minute market dispatch VER based on its economic energy bid and use forecast as its upper operation limit Support Primary/Alternative ITC for DS/PTG Slide 111

112 Spring 2014 release - FERC 764 Application Software Changes Implementation Impact Assessment CAS: Perform scheduling check-out based on the 15-minute based schedules and tag energy profile Perform the tag update/approval by the hourly deadline T-20 for various intertie bidding options Receive and consume the RUC cleared capacity for day-ahead tagging checkout purpose Receive and consume the RTPD 15-minute schedules for tagging check-out purpose Automatically match retag DS/PTG schedule from the primary ITC to the alternative ITC when the primary ITC become open ADS As the HASP will be replaced the hourly process to accept the block schedule and the hourly process schedule is advisory, no more HASP predispatch schedules will be issued through ADS Settlements: 15-minute energy settlements will be based on the 15-minute schedule and the day-ahead energy schedule. 5-minute energy settlement will be based on the difference of 15-minute schedule and 5-minute dispatch. All metering related settlement will be changed to 5-minute base. Real-time Inter-SC trades based on 15-minute price. Metering: 10-minute metering data changed to 5-minute metering data SIBR: Allow market participants to submit 5-minute VER forecast with a 2-hour lookahead window Allow an intertie various additional bidding options: An hourly block schedule A single curtailment for the remainder of the hour with block schedule Option to determine 15-minute market participation if not accepted in the Slide 112 hourly process

113 Spring 2014 release - FERC 764 Milestone BPM Changes Date Market Operation, Market Instruments Settlements & Billing, Definitions & Acronyms Business Process Changes Manage Master file: Identify variable energy resources and their selection of using ISO VER forecast or their own VER forecast DA and RT processes: A new financially binding 15 minute scheduling market run for import, export, internal resources and loads Settlements: 15-minute market settlement Price Correction and Validation: Price Validation and correction tools and/or proposed MVT tool shall be modified to include 15-minute market Price validation. Interchange Scheduling: Update/approval etag hourly transmission profile and the 15-minute energy profile for various intertie bidding options. Manage Metering: Metering data for settlement for both CAISO ME polled data and SC submitted data are changed to 5-minute. Analysis Dispute and Resolution: expanded to include validation rules and corrections for the 15-minute market solution. Market Performance (MAD/DMM): expanded to monitor market performance related to the 15-minute market scheduling and settlement. Training: Training will be needed to train Operator/Analysts on the 15-minute market scheduling and settlement. Slide 113

114 Spring 2014 release - FERC 764 Milestone Date Board Approval May 15, 2013 External Business Requirements Technical Specifications Updated BPM s Dec 2013 Draft Configuration Guides May 20 th MasterFile and SIBR May 24 th Metering and Settlements June 3 rd ADS, OASIS and CMRI Complete BRS: June 7, 2013 Master File and SIBR: Aug 2013 OASIS, CMRI, ADS TBD Metering Oct 2013 Dec 2013 initial draft Market Simulation Feb 3 Mar 7, 2014 Tariff Nov 12, 2013 Production Activation Spring 2014 (April 1, 2014) Slide 114

115 FERC Order 764 Market Changes Readiness The ISO will help participants track implementation efforts and share their needs for readiness support The Release Users Group (RUG) bi-weekly call will be used for this purpose All stakeholders are invited to participate RUG discussions focus on the proper level of technical detail for the FERC Order 764 project Slide 115