Market Performance and Planning Forum July 30, 2013 Objective: - - PowerPoint PPT Presentation

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Market Performance and Planning Forum July 30, 2013 Objective: - - PowerPoint PPT Presentation

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Market Performance and Planning Forum July 30, 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

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SLIDE 1

Market Performance and Planning Forum

July 30, 2013

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SLIDE 2

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

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SLIDE 3

Agenda

Slide 3

10:00- 10:05 Introduction, Agenda Mercy P. Helget 10:05 – 11:15 Market Performance and Quality Update Guillermo Bautista Alderete, Nan Liu 11:15 – 12:00 CMRI Report on Transmission Constraints Dede Subatki 12:00 – 1:00 Lunch 1:00 – 1:30 Policy Updates Brad Cooper 1:30 – 2:15 Technical Updates Khaled Abdul-Rahman, Li Zhou 2:15 – 2:30 Technical User Group Update Doug Walker 2:30 – 3:00 Release Plan Updates Janet Morris, June Xie

Agenda Agenda Agenda Agenda

Note: Agenda is subject to change.

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SLIDE 4

Market Performance and Quality Update

Market Quality and Renewable Integration

Guillermo Bautista-Alderete Nan Liu

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SLIDE 5

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

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SLIDE 6

Hot topic and follow up items

  • Summer update
  • Pay for performance
  • DA and RT prices
  • Wind and solar generation

Page 6

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SLIDE 7

Summer Update.

  • Peak load occurred on June 28 at 45097 MW.
  • There were adequate supply offered in both DA and RT

to meet demand.

  • One area of concern is the amount of import declines

and curtailments in real-time (1000 MW).

  • Additional imports and internal generations would be

required to meet real-time system demand.

  • Incurred high RTCO.

Slide 7

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Slide 8

Pay for Performance

1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000 1-Jun-13 3-Jun-13 5-Jun-13 7-Jun-13 9-Jun-13 11-Jun-13 13-Jun-13 15-Jun-13 17-Jun-13 19-Jun-13 21-Jun-13 23-Jun-13 25-Jun-13 27-Jun-13 29-Jun-13 1-Jul-13 3-Jul-13 5-Jul-13 7-Jul-13 9-Jul-13 11-Jul-13 Payment ($) Trade Date

Daily Distribution of Mileage Payments

Mileage Down Mileage Up Mileage Down Mileage Up 67,716 12,460

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SLIDE 9

Slide 9

Pay for Performance

0.00 2,000.00 4,000.00 6,000.00 8,000.00 10,000.00 12,000.00 14,000.00 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 Payment ($)

Hourly Distribution of Mileage Payment

Mileage Down Mileage Up

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SLIDE 10

Pay for Performance

Page 10

0% 10% 20% 30% 40% 50% 60% 70% 1-Jun-13 3-Jun-13 5-Jun-13 7-Jun-13 9-Jun-13 11-Jun-13 13-Jun-13 15-Jun-13 17-Jun-13 19-Jun-13 21-Jun-13 23-Jun-13 25-Jun-13 27-Jun-13 29-Jun-13 1-Jul-13 3-Jul-13 5-Jul-13 7-Jul-13 9-Jul-13 11-Jul-13 13-Jul-13 15-Jul-13

System Mileage Performance Accuracy

System Up Accuracy System Down Accuracy

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SLIDE 11

Slide 11

DA vs. RT prices trends

  • 10
  • 8
  • 6
  • 4
  • 2

2 4 6 8

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 Jun-13 NP15 SP15 Monthly Average Price Difference between RT and DA (RT minus DA)

$/MWh

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SLIDE 12

Slide 12

Wind Schedules in HASP and DA.

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

1-Jan 8-Jan 15-Jan 22-Jan 29-Jan 5-Feb 12-Feb 19-Feb 26-Feb 5-Mar 12-Mar 19-Mar 26-Mar 2-Apr 9-Apr 16-Apr 23-Apr 30-Apr 7-May 14-May 21-May 28-May 4-Jun 11-Jun 18-Jun 25-Jun HASP IFM MWh

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Slide 13

Solar Schedules in HASP and DA.

2,000 4,000 6,000 8,000 10,000 12,000 14,000 16,000 18,000 20,000

1-Jan 14-Jan 27-Jan 9-Feb 22-Feb 7-Mar 20-Mar 2-Apr 15-Apr 28-Apr 11-May 24-May 6-Jun 19-Jun HASP IFM MWh

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SLIDE 14

DA monthly average DLAP LMP was higher than RTD LMP in June.

Page 14 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 Jun-13 $/MWh

IFM HASP RTD

VEA

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PG&E HASP prices elevated by two days of HASP congestion in HE 15 and 16.

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50 100 150 200 250 1 2 3 4 5 6 7 8 9 101112131415161718192021222324

$/MWh

IFM HASP RTD

PG&E Hour

10 20 30 40 50 60 70 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

SDG&E

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

IFM HASP RTD

VEA

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Monthly price distributions: mostly negative price spikes in June.

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  • 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

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SLIDE 17

Insufficient up ramping capacity continued to be very low in June.

Page 17 0.00% 0.50% 1.00% 1.50% 2.00% 2.50% 3.00% 3.50% 4.00% 50 100 150 200 250 300 350 400 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 Jun-13 Percent of Intervals Count of Intervals

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

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Monthly average of RTD Intervals with insufficient down ramping capacity dropped in June.

Page 18 0.00% 0.50% 1.00% 1.50% 2.00% 2.50% 3.00% 3.50% 4.00% 50 100 150 200 250 300 350 400 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 Jun-13 Number of Intervals

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

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Slide 19

Real-time congestion offset costs increased in June.

  • 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 Jun-13

$Millions

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

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Slide 20

Real-time congestion and energy imbalance offset costs decreased in June after increasing in five straight months.

10 20 30 40 50 60 70

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 Jun-13

$Millions

Sum of Congestion and Energy Imbalance Offset

Congestion and Energy Imbalance Offset

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SLIDE 21

Exceptional dispatch volume increased in May and June.

Page 21 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

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Daily exceptional dispatches– by reason

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0.00% 0.50% 1.00% 1.50% 2.00% 2.50% 3.00% 1-May 3-May 5-May 7-May 9-May 11-May 13-May 15-May 17-May 19-May 21-May 23-May 25-May 27-May 29-May 31-May 2-Jun 4-Jun 6-Jun 8-Jun 10-Jun 12-Jun 14-Jun 16-Jun 18-Jun 20-Jun 22-Jun 24-Jun 26-Jun 28-Jun 30-Jun

Fires Software Limitation Transmission Outage Unit Testing Thermal Margin Load Forecast Uncertainty SP26 Capacity 7430 Other

% of Total Load

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SLIDE 23

Bid cost recovery (BCR) costs fell in June.

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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 Jun-13 $Millions IFM RT RUC

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SLIDE 24

MIP gap performance continued to be good in June.

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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 6/1/13

Daily Dollar 30 Day Moving Average

Mip Gap ($)

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Slide 25

Flexi-ramp constraint costs declined in June.

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 Jun-13

$Millions

Monthly Flexi-Ramp Cost

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Price corrections decreased in June.

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Price corrections decreased in June.

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CMRI Report on Transmission Constraints

Dede Subakti, Director Operations Engineering

Slide 28

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NERC Standard Requirement for Transmission Constraint

TOP-002-2

  • R6. Each Balancing Authority and Transmission

Operator shall plan to meet unscheduled changes in system configuration and generation dispatch (at a minimum N-1 Contingency planning) in accordance with NERC, Regional Reliability Organization, subregional, and local reliability requirements TOP-004-2

  • R2. Each Transmission Operator shall operate so that

instability, uncontrolled separation, or cascading outages will not occur as a result of the most severe single contingency.

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N-1 Secure

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Modeling Simple N-1/N-2 Contingency for Tranmission Constraint Modeling

  • In the past, there are three ways to model congestion
  • Method 1: Utilization of Path, Example

– Path 15

  • Loss of LBN overload Los Banos-Westley
  • Loss of LBS overload Gates-Panoche
  • Loss of MWN overload Gates-Midway

– Path 26

  • Loss of MV1+2 overload MV3 (or now MW)

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Modeling Simple N-1/N-2 Contingency

  • Method 2: Utilization of LODF, Example

– Flow Limit in Bay Area: 0.24*Pittsburg-San Mateo 230 kV (,@Pittsburg) + Pittsburg-Eastshore 230 kV (,@Pittsburg) Monitor Pittsburg-Eastshore for loss of Pittsburg-San Mateo – Flow Limit in Orange County: 0.72*Barre-Villa Park 220 kV + Barre-Lewis 220 kV Monitor Barre-Lewis for loss of Barre-Villa Park

  • Method 3: Utilization of Contingency Analysis

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For Discussion Purpose - Simplified System Diagram – Importing region

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Un 1 Un 2 Un 3 Line A Line B Normal Rating Emergency Rating Line A 100 150 Line B 100 150 Line C

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How to Implement The Standards – Method 1: Using Proxy Path Limit

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Line A Line B

Normal Emergency Line A 100 150 Line B 100 150

  • Utilizing Proxy Path Limit:
  • Line A + Line B + Line C < Import Limit

Line C Problem: It’s a proxy limit calculated based on off-line assumption

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How to Implement The Standards Method 2: Using LODF

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Line A Line B

Normal Emergency Line A 100 150 Line B 100 150

  • Utilizing LODF
  • Line A + (Distribution Factor * Line B) < Rating of Line A

Line C Problem: LODF is calculated off line and it is based on system

  • topology. LODF changes when the system topology changes
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How to Implement The Standards Method 3: RTCA

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Line A Line B

Normal Emergency Line A 100 150 Line B 100 150

  • RTCA
  • Tool automatically do calculation with the input:
  • What to monitor ( Line A)
  • What to simulate (Contingency of Line B)
  • What is the rating (Rating of Line A)

Line C

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Method 1: Example for Path 15

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How does this look in CMRI

In CMRI: Transmission Constraint Definition

Page 37

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Method 2: Example for BARRE-LEWIS_NG

Lewis Barre Vila Park

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Utilizing Flow Limit and LODF

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Purpose: Ensure that Barre-Lewis (from Lewis to Barre) does not overload for N-1 loss of Barre-Villa Park above its 1470 Emergency Rating Utilization of LODF (Method 2): Line A + (Distribution Factor * Line B) < Rating of Line A Distribution Factor Line Rating

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This is how Market Implementation is

  • Utilize Nomogram

Barre-Lewis + (0.72 * Barre-Villa Park) < 1470

Page 40 200 400 600 800 1000 1200 1400 1600 500 1000 1500 2000 2500

Barre-Lewis Line Flow Barre - Villa Park Line Flow

Barre-Lewis_NG Safe Operating Region N-1 Insecure Operating Region

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How does this look in CMRI

Barre-Lewis + (0.72 * Barre-Villa Park) < 1470 In CMRI: Nomogram Definition In CMRI: TCORR Definition In Market Modeling Data

Page 41

BARRE_NG_1 BARRE_NG_2

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Nomogram Naming Convention

  • Procedure Base nomogram will have the procedure

name. – Example:

  • 7820_TL230S_OVERLOAD_NG
  • This is for Procedure 7820

– New Procedure number is 6xxx – 7xxxx – Old Procedure number is T-xxx

  • Outage base nomogram is normally temporary. It will

have the SLIC number in it. – Example:

  • SLIC 1860182 HUMSB_SOL-2

Page 42

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Method 3: Using Straight Contingency

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Utilizing Contingency

  • Need to ensure the line that could be overloaded is

defined as “Enforced Flowgate”

  • Need to ensure the contingency is active

Page 44

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Transmission Contingency Definition

  • In CMRI: Contingency Definition
  • In Market Modeling Data

Page 45

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Policy Update

Brad Cooper Manager, Market Design and Regulatory Policy

Slide 46

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SLIDE 47

Market design initiatives coming soon

  • PIRP Protective Measures

− Starting August

  • Reliability Services Auction

− Targeted to start September

  • Load Granularity Refinements

− Targeted to start August

  • Stakeholder Initiative Catalog

− Targeted to start September

Page 47

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SLIDE 48

Market initiatives going to the Board for approval

Page 48

Initiative Board Presentation Revision of Price Corrections Process September PIRP Protective Measures September Contingency Modeling Enhancements November Energy Imbalance Market November Full Network Model Expansion November Flexible Resource Adequacy Criteria and Must Offer Obligations December Interconnection Process Enhancements December

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Technical Updates

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

Page 49

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Technical User Group Updates

Doug Walker, Lead Architect Architecture

Page 50

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Technical User Group

2013 Second Half Topics – Integration

  • MTOM
  • GMT for services
  • CIM Adoption
  • Acceptable Use

– Federated Security – Smart Grid Proof of Concepts – Notifications We want your input

Slide 51

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Release Plan Updates

Janet Morris, Director June Xie, Sr. Advisor Program Office

Page 52

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The ISO offers comprehensive training programs

Date Training July 23 Settlements 101 July 24 Settlements 201 August 15 Welcome to the ISO Web Training

Page 53

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

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SLIDE 54

Release Plan – 2013

  • Fall 2013
  • Post Emergency Filing BCR changes / Mandatory MSG is combined with

RIMPR-Phase 1 / BCR Mitigation Measures / Bid Floor Cap

  • Commitment Cost Refinements 2013
  • Ancillary Services Buy-Back
  • PIRP Logic Change
  • FERC 755 Pay for Performance API Report
  • CMRI “CRN” Report New API
  • Independent Efforts
  • Access and Identity Management
  • RIMS Generation
  • Replacement Requirements for Scheduled Generation Outages Phase 2
  • DRS API Deployment
  • GMT

Page 54

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Release Plan – 2014 (proposed)

  • Spring 2014
  • Circular Scheduling
  • FERC Order 764 Compliance / 15 Minute Market / Dynamic Transfers
  • ADS User Interface Replacement
  • RDPR activation / FERC 745 Compliance
  • Fall 2014
  • Energy Imbalance Market (EIM)
  • Full Network Model Expansion
  • Outage Management System Replacement (OMS)
  • Flexible Resource Adequacy Criteria and Must Offer Obligation
  • Subject to further release planning:
  • Contingency Modeling Enhancements
  • Subset of Hours
  • Acceptable Use Policy
  • Flexible Ramping Product
  • iDAM (simultaneous IFM and RUC)
  • Revisions to Price Correction Requirements
  • Expanding Metering and Telemetry
  • Enterprise Model Management System

Page 55

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2013 Release Schedule

http://www.caiso.com/Documents/ReleaseSchedule.pdf *Mandatory MSG Market Sim occurs one week per month through October 1st 2013.

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MAP-Stage Outages and SIBR-Lite

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  • MAP-Stage will be unavailable for external access from August 1-26, 2013
  • The ISO intends to keep SLIC available during this outage (may experience a short

maintenance window)

  • SIBR-Lite will be re-instated as of August 1, 2013 and will be installed with the

Production version of SIBR

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SLIDE 58

2013 – SLIC JDK 1.7 Support

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What to Expect: – SLIC web client support for all Java versions including JDK 1.7 – SLIC RTAM client support for all Java versions including JDK 1.7 – Fix for “Password could not be saved” error that occurs during the “Configure Client Password” step of the web client installation process Target Date: Mid-August 2013 Impact to Users: – There is no mandatory action required of users – Users will be able to upgrade to JDK 1.7 and then re-install the SLIC web and/or RTAM client – Installation steps will remain the same and can be found on caiso.com: http://www.caiso.com/Documents/SLICWebClientInstructions.pdf

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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 59

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SLIDE 60

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 10, 2013

Draft Configuration Guides - draft

July 10, 2013

Updated BPMs

August 26, 2013

Market Simulation

August 26, 2013 – September 13, 2013

Tariff filing date

August 26, 2013

Production Activation

November 1, 2013

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

Page 60

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Milestone Date

Application Software Changes

Masterfile: Adding the Min. Load, Startup Major Maintenance Adder (MMS) and Grid Management Charge (GMC) to the projected proxy calculations. 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 26, 2013

Market Simulation

August 26, 2013 – September 13, 2013

Tariff filing date

August 23, 2013

Production Activation

November 1, 2013

Fall 2013 – Commitment Cost Refinement

Page 61

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SLIDE 62

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

N/A

Board Approval

July 13, 2012

External Business Requirements

February 28, 2013

Updated BPMs

August 5, 2013

Technical Specifications

N/A

Draft Configuration Guides - draft

July 10, 2013

Tariff

Filed January 3, 2013 Approved Thursday June 27, 2013

Market Simulation

August 26, 2013 – September 13, 2013

Production Activation

November 1, 2013

Fall 2013 – AS Buy Back

Page 62

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SLIDE 63

Fall 2013 - PIRP Logic Change

Slide 63

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:

  • Continue to 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 26, 2013 – September 13, 2013

Tariff

August 2013

Production Activation

November 1, 2013

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SLIDE 64

Milestone Description/Date

Emergency BPM Changes

See PRR 673

System Mileage Production Report UI

Jul 1 deployment to production

System Mileage Production Report API

Fall 2013

Technical Specification

Jul 15 – OASIS API technical specification

Business Process Changes

AS Certification – AGC signal certification process

DATA MILEAGE REQUESTS

Submit mileage data requests through CIDI

  • Due to resource limitations, the maximum data request will be for one

trade date ,for one resource, per SC, per month.

Fall 2013 - FERC Order 755 pay for performance

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SLIDE 65

Fall 2013 – Market Simulation Plan

Page 65

Fall Release 2013 Market Simulation Plan Posted - http://www.caiso.com/Documents/Fall2013ReleaseMarketSimulationPla nV1_0.pdf

Timelines - Market Simulation Trade Dates 8/27 – 9/13 Kickoff call 8/15 In scope initiates and simulation type -

  • AS Buy Back – Structured
  • Commitment Cost Refinements 2013 – Unstructured
  • RI-MPR Phase 1 with BCR-Post Emergency and Mandatory MSG (Includes

CMRI CRN API) – Unstructured

  • RRSGO Phase 2 Annual – Unstructured
  • PIRP Logic Change (Includes FERC 755 OASIS AS Report and Load Forecast

Report API) - Unstructured

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SLIDE 66

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

August 19th , 2013 (Release 1)

2013 - Access and Identity Management (AIM)

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SLIDE 67

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

November 15th, 2013

2013 – RIMS Generation

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SLIDE 68

Milestone Date

Application Software Changes

IRR: Moving Annual IRR functionality to new CIRA (CAISO Interface for Resources Adequacy) Application (new url, same look and feel, some new interactions)

BPM Changes

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

Next Monthly RR Workshops

August 12, 2013, 2:00 pm

Board Approval

July 12, 2012

Updated External Business Requirements

Posted July 19, 2013 (includes Annual and Monthly)

Technical Specifications

N/A for Annual

Training

August 22, 2013 (webinar)

Market Simulation

August 26 – September 13 2013 (unstructured)

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, 1 2013

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

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SLIDE 69

Milestone Date

Application Software Changes DRS - Addition of API to support automated registration, and potentially for reporting on baseline and performance. BPM Changes TBD Board Approval N/A External Business Requirements Registration API Baseline & Performance API August 30, 2013 December 2013 (if needed) Technical Specifications - Registration September 2013 Updated BPMs TBD Market Simulation Registration API Baseline & Performance API November 2013 (tentative) Feb 3 – Mar 7, 2014 (if needed) Tariff N/A Production Activation Registration API Baseline API Performance API December 2013 (tentative) Spring 2014 (if needed) Spring 2014 (if needed)

2013 – Demand Response System (DRS) API

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SLIDE 70

Milestone Date

Application Software Changes

OASIS and CMRI All APIs will be provided with GMT option

BPM Changes

N/A

Board Approval

N/A

External Business Requirements

N/A

Technical Specifications

ISO is planning to provide options in TUG for feedback on 07/30. Based on feedback, we will provide update on technical specifications in RUG on 08/06.

Updated BPMs

N/A

Market Simulation

TBD

Tariff

N/A

Production Activation

December 2013

2013 - GMT

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SLIDE 71

Milestone Date

Application Software Changes

Currently Planning to do a proof of concept and based on results, implementation and technical solution will be communicated through TUG &

  • RUG. This policy will impact all external applications.

BPM Changes

N/A

Board Approval

N/A

External Business Requirements

N/A

Technical Specifications

N/A

Updated BPMs

N/A

Market Simulation

TBD

Tariff

N/A

Production Activation

TBD

Acceptable Use Policy

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SLIDE 72

Milestone Date

Application Software Changes

Masterfile: Creation of new field to capture attestation letter submission. Change

to Generator RDT to allow participants to view the new field. 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

December 6, 2013

Technical Specifications

Master File - August 2013

Draft Configuration Guides

TBD

Market Simulation

Feb 3 – Mar 7, 2014

Tariff

Filed November 21, 2012 Approved January 30, 2013

Production Activation

Spring 2014 (April 1, 2014)

Spring 2014 – Circular Scheduling

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SLIDE 73

Spring 2014 - FERC 764

Slide 73

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
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SLIDE 74

Spring 2014 - FERC 764

Slide 74

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

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SLIDE 75

Spring 2014 - FERC 764

Slide 75

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.

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SLIDE 76

Spring 2014 - FERC 764

  • Slide 76

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 21, 2013 External Data Requirements Specification Jul 22nd MasterFile, SIBR, ADS, CMRI and OASIS Jul 23rd RUG walkthrough each application Technical Specifications Aug - MasterFile and SIBR Sep – Oct OASIS, CMRI, ADS TBD – ADS Framework Oct – Metering 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)

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SLIDE 77

Milestone Date

Application Software Changes

  • Port client from Delphi to new common user interface (ADS

Query Tool and Real Time Functionality)

  • Conform APIs to current ISO standards

BPM Changes None Board Approval N/A External Business Requirements N/A Technical Specifications TBD Updated BPMs N/A Market Simulation Feb 3 – Mar 7, 2014 Tariff N/A Production Activation Spring 2014 (April 1, 2014)

Spring 2014 – ADS User Interface Replacement

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SLIDE 78

Milestone Date

Application Software Changes

Activation of Reliability Demand Response Product (RDRP) including FERC Order 745 compliance.

BPM Changes

TBD

Board Approval

Not required

External Business Requirements

See: http://www.caiso.com/informed/Pages/StakeholderProcesses/ReliabilityDema ndResponseProduct.aspx

Technical Specifications

See slide on DRS API

Updated BPMs

TBD

Market Simulation

Feb 3 – Mar 7, 2014

Tariff

Compliance filing due on August 19, 2013

Production Activation

Spring 2014 (April 1, 2014)

Spring 2014 - RDRP Activation / FERC 745 Compliance

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SLIDE 79

Milestone Date

Application Software Changes

Master File: Register EIM entity, EIM resources, EIM resource emission rate, EIM Interties SIBR: Accept and validate submitted EIM resource plan and load base schedule, EIM resource bids. ALFS: Forecast EIM load, EIM VER. EMS: Model updates EIM BAA, model EIM NSI. DAM/RTM: Perform the DCPA for each BAA for the constraint in the BAA and the test and mitigate the resources in the BAA; Decompose the LMP congestion by the constraint belong the same BAA; option for EIM entity unit commitment; All LMPs will not include marginal loss contributions from external network losses; The EIM entity access the interface to submit exceptional dispatch with “EIM type”; send the latest valid prior RTD advisory results to EIM when ISO run RTCD. Model Greenhouse Gas (GHG) emission for EIM to ISO; Calculate BAAs transfers; Perform flexible ramping requirement sufficiency test. Meet flexible ramping requirement by BAA and total. MQS: Calculate resource unit contribution on congestion cost for real time congestion balance account. OMS: EIM submission of resource and transmission Outages Settlement: settle 15 minute and 5 minute markets IIE and UIE at LMP ; Calculate EIM LAP hourly volumetric weighted average LMP weighted by the load forecast deviations bounded by the min/max LMPs; Settle EIM administrative cost; create real-time congestion balancing account for each BAA; Collect and allocate under- schedule penalty by month. Settle EIM resource BCR. Allocate uplift to the BAA shared by the transfers. Pay the flexible ramping capacity use current formula, allocate the cost prorata to the requirements. CMRI/OASIS/ADS: Publish the market results for EIM BAA and resources.

Fall 2014 – Energy Imbalance Market (EIM)

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SLIDE 80

Milestone Date

BPM Changes Market Operations, Market Instruments, Settlements and Billing Board Approval November 8, 2013 External Business Requirements September 1, 2013 Technical Specifications April 1, 2014 Updated BPMs TBD Market Simulation July 8, 2014 Tariff February 28, 2014 Production Activation October 1, 2014

Fall 2014 – Energy Imbalance Market (EIM)

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SLIDE 81

Milestone Date

Application Software Changes

Master File: Define external BAA scheduling point as Generation Aggregated Point (GAP) and GDF SIBR: Submit and create transaction ID for the SC Bids on Scheduling Points-BAA dynamically; Allow the SC bids at same BAA-SP to bid to different interties. DAM/RTM: Receive the dynamically formed transaction ID attributes from bid, perform contingency analysis for some critical external BAA resources and transmission equipment. Incorporate external BAA critical outages, Enforce both flow and schedule Intertie constraints, Model HVDC line. CRR: CRR market run on expanded Full Network Model. CMRI/ADS/OASIS/Settlement: Receive and process the dynamically formed transaction ID.

BPM Changes Market Operations, Market Instruments, Managing FNM Board Approval November 2013 External Business Requirements September 1, 2013 Technical Specifications April 1, 2014 Updated BPMs TBD Market Simulation July 8, 2014 Tariff TBD Production Activation Fall 2014

Fall 2014 – Full Network Model Expansion

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SLIDE 82

Milestone Date

Application Software Changes

CRR: Receive outage data from OMS ED: Provide equipment to patch mapping date to OMS EDR: Store outage data from OMS EMS: Receive outage data from OMS once outage is created or changed ETCC: Retrieves outages from OMS, updates path limits impacted by the

  • utages and broadcasts path limits from OMS

IFM/RTN: Receive outage data from OMS and broadcast flowgate and nomogram data to OMS MF: Provide reference data to OMS via web services MPP and OASIS: New outage reports posted. OMS: New OMS replaces LSLIC and current OMS with improved capability. Notifications become automatic. Manual email supported. OMS takes over role for publishing data. PIRP: Receive outage data from OMS CIRA: Retrieves outages from OMS and checks if RA resources are impacted by outages. Scheduling Coordinator replaces RA units. Settlements: Receives outage data from OMS TR: Provide Transmission Equipment reference data to OMS via web services.

BPM Changes

Managing Full Network Model Market Instruments Outage Management Market Operations Compliance Monitoring

Fall 2014 – Outage Management System (OMS)

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SLIDE 83

Milestone Date

Board Approval

July 11, 2013

External Business Requirements

Posted June 28, 2013

Technical Specifications

November 1, 2013

Business Process Changes

Maintain Master File Manage Generation Outages Manage Transmission Outages Day-Ahead Process Real-Time Process – Prior to Bid Close Real-Time Process – After Bid Close Real-Time Process – 5 minute dispatch Manage FNM Maintenance Promote Network Model into Production Determine Generation of OTC – determine if it affects OTC, enter data into ETC application, notify affected parties of change in ETC values and notify requestor of decision.

Fall 2014 – Outage Management System (OMS) - continued

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SLIDE 84

Milestone Date

Business Process Changes (continued)

Evaluate Generation Initial Review and Request – disapprove new or modification request, evaluate outage request for accuracy, evaluate the

  • utage request, and obtain additional information for evaluation.

Evaluate Generation Modification Request – approve forced/immediate request, assign requested status, and pend /internal consult. Evaluate Generation Outage Request – check if discrepancy is resolvable, determine appropriate action of request, determine generation OTC, evaluate request, and push ERTC data to OASIS on demand. Manage Dispatcher Load Flow Analysis Manage Extreme Long-Start Commitment Manage Generation Outages Manage Outage Request Submission Manage Outage Updates to network Model Manage Real-Tome Outage Impacts to ETC and Network Model Manage Resource Interconnections Manage Transmission Outages

Updated BPMs

September 2014

Market Simulation

July 8 – July 29, 2014

Tariff

~ August 2014

Production Activation

October 1, 2014

Fall 2014 – Outage Management System (OMS) - continued

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