Market Performance and Planning Forum June 5, 2013 Objective: - - PowerPoint PPT Presentation

Market Performance and Planning Forum

June 5, 2013

Objective: Enable dialogue on implementation planning and market performance issues

• Review key market performance topics
• Share updates to 2013-2014 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

Agenda

Slide 3

10:00- 10:05 Introduction, Agenda Mercy P. Helget 10:05 – 11:30 Market Performance and Quality Update GHG Update Guillermo Bautista Alderete, Nan Liu, Mark Rothleder 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

Agenda Agenda Agenda Agenda

Note: Agenda is subject to change.

Market Performance and Quality Update

Market Quality and Renewable Integration

Mark Rothleder Dede Subakti Guillermo Bautista-Alderete Nan Liu

Slide 4

Slide 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

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

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

Nomogram Definition Posted in CMRI

Page 8

Summary of Major Nomogram around San Diego and Pacific Southwest

Slide 10

Wind Schedules in HASP and DA

500 1,000 1,500 2,000 2,500 3,000 3,500 4,000

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 HASP IFM MW

Slide 11

No change in trend for NP prices between RTD and IFM.

• 200
• 100

100 200 300 400 500 600 700

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 NP15 Hourly Price Difference (RTM less IFM)

Slide 12

• 200

200 400 600 800 1,000 1,200

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 SP15 Hourly Price Difference (RTM less IFM)

No change in trend for SP prices between RTD and IFM.

Slide 13

RUC Load Adjustment increased in the second half of February.

0.0% 0.5% 1.0% 1.5% 2.0% 2.5% 3.0% 3.5% 4.0%

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 Daily Load Adjustment

Slide 14

• 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.

Summer outlook

Slide 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 16

• 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.

Circular schedules

Higher DA monthly average DLAP LMP than RTD LMP in May.

Page 17 10 20 30 40 50 60 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 10 20 30 40 50 60 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 10 20 30 40 50 60 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 5 10 15 20 25 30 35 40 45 Jan-13 Feb-13 Mar-13 Apr-13 May-13 $/MWh

IFM HASP RTD

VEA

DLAP LMP Monthly Average (On Peak)

Page 18 10 20 30 40 50 60 70 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 10 20 30 40 50 60 70 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 10 20 30 40 50 60 70 80 90 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 5 10 15 20 25 30 35 40 45 50 Jan-13 Feb-13 Mar-13 Apr-13 May-13 $/MWh

IFM HASP RTD

VEA

DLAP LMP Monthly Average (Off Peak)

Page 19 10 20 30 40 50 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 10 20 30 40 50 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 10 20 30 40 50 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 10 20 30 40 Jan-13 Feb-13 Mar-13 Apr-13 May-13 $/MWh

IFM HASP RTD

VEA

More volatile RT DLAP LMP on average in May.

Page 20

20 40 60 80 100 120 140 160 180 200 1 2 3 4 5 6 7 8 9 101112131415161718192021222324

$/MWh

IFM HASP RTD

PG&E Hour

10 20 30 40 50 60 70 80 90 1 2 3 4 5 6 7 8 9 101112131415161718192021222324 $/MWh

IFM HASP RTD

SCE

10 20 30 40 50 60 70 80 90 1 2 3 4 5 6 7 8 9 101112131415161718192021222324 $/MWh

IFM HASP RTD

SCE

10 20 30 40 50 60 70 1 2 3 4 5 6 7 8 9 101112131415161718192021222324 $/MWh

IFM HASP RTD

VEA

Monthly price distributions: Price volatility increased in both positive and negative direction in May.

Page 21

• 10.0%
• 8.0%
• 6.0%
• 4.0%
• 2.0%

0.0% 2.0% 4.0% 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-13 Percent of Real Time Intervals

• $30 to -$5
• $100 to -$30
• $300 to -$100

<-$300 $250 to $500 $500 to $750 $750 to $1000 >$1000

Monthly average of RTD intervals with insufficient up ramping capacity continued the downward trend.

Page 22 0.00% 0.20% 0.40% 0.60% 0.80% 1.00% 1.20% 1.40% 1.60% 1.80% 2.00% 20 40 60 80 100 120 140 160 180 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 Percent of Intervals Count of Intervals

5-minute intervals with insufficient upward ramping capability percent of intervals with insufficient upward ramping capability

Monthly average of RTD Intervals with insufficient down ramping capacity followed an upward trend in the past four months.

Page 23 0.00% 0.50% 1.00% 1.50% 2.00% 2.50% 3.00% 3.50% 4.00% 4.50% 5.00% 100 200 300 400 500 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

5-minute intervals with insufficient downward ramping capability percent of intervals with insufficient downward ramping capability

Slide 24

Real-time congestion offset costs increased in May.

• 10

10 20 30 40 50 60

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

Congestion Imbalance Offset Energy Imbalance Offset Real-time Congestion and Energy Imbalance Offset Cost

Exceptional dispatch volume stayed low relative to last year.

Page 25 0.005 0.01 0.015 0.02 0.025

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 2009 2010 2011 2012 2013

Total Exceptional Dispatch as Percent of Load % of Total Load

Daily exceptional dispatches– by reason

Page 26

0.00% 0.50% 1.00% 1.50% 2.00% 2.50% 3.00% 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

% of Total Load

Bid cost recovery (BCR) costs rose in May, mainly driven by the increase in IFM.

Page 27

2 4 6 8 10 12 14 16 18 20

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 IFM RT RUC

MIP gap performance was good in April and May.

Page 28

10,000 20,000 30,000 40,000 50,000 60,000 70,000 80,000 90,000 100,000

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

Daily Dollar 30 Day Moving Average

Mip Gap ($)

Slide 29

Flexi-ramp constraint costs declined since March.

1 2 3 4 5 6

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

Monthly Flexi-Ramp Cost

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/mtCO2e 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

Page 34

$10.00 $11.00 $12.00 $13.00 $14.00 $15.00 $16.00 $17.00 $18.00 $19.00 $20.00 01-Jan 15-Jan 29-Jan 12-Feb 26-Feb 12-Mar 26-Mar

Greenhouse gas allowance price index ($/mtCO2e)

Implied heat rate = electricity price / gas price

Page 35

5 6 7 8 9 10 11 12 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 Implied heat rate (mmBTU/MWh) Implied heat rate Average implied heat rate

Difference in implied heat rate = 10.03 - 8.57 = 1.47 Average gas price: = 4.23 Greenhouse gas price effect = 1.47 * 4.23 = $6.21/MWh

Estimated greenhouse gas price impact: first quarter regression results

• Average electricity price =

β0 + β1GasPGE + β2GasSCE1 + β3GasSCE2 +β4Load + β5Load2 + β6Peak + B7 Peak ∗ GasPGE + β8 Peak ∗ GasSCE1 + β9 Peak ∗ GasSCE2 + β10 Peak ∗ Load + β11 Peak ∗ Load2 + β12GHG + 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, R2 = 0.83
• Estimated GHG impact:

– Indicator: β12 estimate = $6.15/MWh (SE = 0.47) – Index price: β12 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

Page 39

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 and Must Offer Obligations November Load Aggregation Point Granularity December Interconnection Process Enhancements December

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

4 Corners 345 kV 4 Corners 500 kV El Dorado 500 kV 24042

McCullough X 500 kV 6047

FCORNER3_MSL FCORNER5_MSL ELDORADO_MSL MCCULLGH_MSL Moenkopi 500 kV 14002 Navajo 500 kV Crystal 500 kV 6123 McCullough 500 kV 26048

Existing Network topology 4/1/2009 – 6/30/2013 CAISO Boundary

4 Corners 345 kV 4 Corners 500 kV El Dorado 500 kV 24042

McCullough X 500 kV 6047

ELDORADO_MSL Moenkopi 500 kV 14002 Willow Beach 500 kV Navajo 500 kV Crystal 500 kV 6123 McCullough 500 kV 26048

Network topology changes effective 7/1/2013 CAISO Boundary

MCCULLGH_MSL

Scheduling points deactivated Active scheduling point is WILLOWBEACH

Tag and Bidding Examples - Today

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 TAGS

Tag and Bidding Examples – Trade Date 7/1/2013

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 TAGS

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

Page 52

As of date: 5/2/2013

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

Slide 58

42,000 43,000 44,000 45,000 46,000 47,000 48,000 49,000 50,000 51,000 52,000 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017

Annual Peak Demand (MW)

ISO 1-in-2 Peak Load Forecasts

based on Economic Base Case & 4 Scenarios

Economic Scenario-1 Economic Scenario-2 Economic Scenario-3 Economic Scenario-4 Economic Base Case Historical Forecast

47,413 MW

Historical and Projected ISO Peak Demand

Page 59

12,000 20,000 28,000 36,000 44,000 52,000 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)

ISO, SP26 and NP26 Monthly Peak Demand (MW)

(Actual Peak from Jan/06 to Apr/13 and Projected 2013 Annual Peak)

SP26 NP26 ISO 1 2

22,632 - 7/25/06 45,809 - 9/3/09 50,085 - 7/24/06 27,253 - 2013 28,251 - 8/31/07 47,413 - 2013 21,328 - 2013 46,675 - 8/13/12 26,712 - 8/13/12 20,136 - 8/13/12

Estimated On-peak Generation

Page 60

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.

Biogas 0.5% Biomass 0.9% Geothermal 2.2% Hydro 15.4% Coal 0.5% Natural Gas 71.2% Nuclear 4.4% Oil 0.7% Solar 2.0% Wind 2.3%

2013 ISO Summer On-Peak NQC by Fuel Type

Generation additions from April 2 to June 1, 2013

Page 61

Projected moderate import

Page 62

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

Interruptible Loads and Demand Responses

Page 63

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

Normal Scenario:

Page 64

The outage calculation excluded SONGS units 2 and 3 because the existing generation did not include them.

On-Peak Resources (MW) ISO SP26 NP26

Existing Generation 50,177 23,380 26,797 Retirement 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 DR & Interruptible Programs 2,322 1,781 541 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%

Extreme Scenario:

2013 extreme scenario operating reserve margins are above 3% firm load shedding threshold for ISO, SP26 and NP26.

On-Peak Resources (MW) ISO SP26 NP26

Existing Generation 50,177 23,380 26,797 Retirement High Probability Additions 891 735 156 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 1,781 541 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%

Operating Reserve Margins are greater than 15% under Normal Scenario and 3% under Extreme

Page 66

20.4% 10.4% 23.3% 6.2% 21.1% 7.1%

0% 5% 10% 15% 20% 25%

Normal Scenario Extreme Scenario

Operating Reserve Margin (%)

ISO, SP26 and NP26 Operating Reserve Margins at 2013 Summer Peak

ISO SP26 NP26

3% Firm Load Shedding

Local Reliability Concerns due to SONGS Outage

Page 67

LA Basin and San Diego is at risk under Category C Contingency without SONGS

Page 68

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

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

Page 70

Overview of the mitigation plan in LA Basin and San Diego

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

• perating 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

Page 95

Training calendar - http://www.caiso.com/participate/Pages/Training/default.aspx Contact us - markettraining@caiso.com

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 1st 2013. Note: SIBR-Lite is no longer available.

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

• f 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

Market Operations Market Instruments Settlements & Billing Definitions & Acronyms Outage Management

Business Process Changes

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

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 April 4, 2013 – SLIC market Notice V5.0.4 release April 29, 2013 - Updated OASIS Application Release Version 6.3.1 Technical Specifications

External Training

February 14, 2013 http://www.caiso.com/Documents/Pay- PerformanceRegulationFERC_Order755Presentation.pdf

Market Simulation

Structure scenario Trade Date 3/14 Structure scenario rerun Trade Date 3/18 Structure scenario rerun Trade Date 5/16

Production Activation

June 1, 2013

Spring 2013 – FERC Order 755 pay for performance

Page 99

June 2013 Release - CMRI “CRN” Report New API

Page 100

Sample CMRI User Interface Screen

June 2013 Release - CMRI “CRN” Report New API

Page 101

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” sub- heading – “retrieveContractUsage” Interface Specifications – “retrieveContractUsage” Artifacts Package (xsd, wsdl) – Release Notes document Timeline June 17 – 21 : Market Simulation open June 27: Production drop New CMRI API effective TD 6/27/2013 DA & RT markets June 30: Last Trade Date (TD) to exist on the sFTP site July 31: Last calendar date to retrieve XML files from the sFTP site

Further updates via market notice communication

Milestone Date

Application Software Changes

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

TBD

Market Simulation

N/A

Tariff

N/A

Production Activation

Currently being rescheduled

Access and Identity Management (AIM)

Page 102

Implementation Impact Assessment

Application Software Changes

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.

Fall 2013 – RIMPR Phase 1 / BCR Mitigation / Bid Floor

Page 103

Milestone Date

BPM Changes

Settlements & Billing, Market Operation, Market Instrument

Business Process Changes

Manage Billing and Settlements, Market Performance

Board Approval

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

Fall 2013 – RIMPR Phase 1 / BCR Mitigation / Bid Floor

Page 104

Milestone Date

Application Software 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.

BPM Changes

Market Operations, Market Instruments, Settlements & Billing

Business Process Changes

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

Filed November 21, 2012 Approved January 30, 2013

Production Activation

Fall 2013 (October 1, 2013) – release date under reconsideration

Fall 2013 – Circular Scheduling

Page 105

Milestone Date

Application Software Changes

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

• f 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

• r 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 2013.

BPM Changes

Market Instruments Billing & Settlements

Business Process Changes

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

Fall 2013 – Commitment Cost Refinement

Page 106

Milestone Description/Date

Application Software Changes

RTM: Operators will have the ability to manually force a buy back due to resource or transmission constraints. 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

Settlements & Billing, Market Operations

Business Process Changes

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

Fall 2013 – AS Buy Back

Page 107

Fall 2013 - PIRP Logic Change

Slide 108

Milestone Date

Application Software 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.

BPM Changes

Market Operations, Market Instrument

Business Process Changes

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

Milestone Date

Application Software Changes

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.

BPM Changes

N/A

Business Process Changes

Manage New Participating Generator Interconnections

Board Approval

N/A

External Business Requirements

April 10, 2013

Technical Specifications

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.

Updated BPMs

N/A

Market Simulation

After Fall 2013

Tariff

N/A

Production Activation

TBD

Fall 2013 – RIMS Generation

Page 109

Milestone Date

Application Software Changes

IRR: TBD RAAM: TBD SLIC: TBD

BPM Changes

606 - Replacement Requirements 607 - Resource Adequacy Resource Planned Outage Reporting

NEW Monthly RA Workshops

Second Monday of each month from 1:30 – 3:00 PM (May 17, 2013 first call)

Board Approval

July 12, 2012

External Business Requirements

End of June 2013

Technical Specifications

N/A

Updated BPMs

TBD

Market Simulation

Fall 2013

Tariff

FERC Filing September 20, 2012 FERC Order Conditional Acceptance November 19, 2012 FERC Compliance Filing December 19, 2012 Request for Rehearing December 19, 2012

Production Activation

Annual – October 2013 Monthly – December 2013

Fall 2013 – Replacement Requirement for Scheduled Generation Outages Phase 2 (RRSGO P2)

Page 110

Spring 2014 release - FERC 764

Slide 111

Implementation Impact Assessment

Application Software Changes 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

Spring 2014 release - FERC 764

Slide 112

Implementation Impact Assessment

Application Software Changes 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 check-
• ut 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

• n 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 look-

ahead 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

hourly process

Spring 2014 release - FERC 764

Slide 113

Milestone Date

BPM Changes 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.

Spring 2014 release - FERC 764

Slide 114

Milestone Date

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

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