Market Performance and Planning Forum Welcome to the Inaugural - - PowerPoint PPT Presentation

Market Performance and Planning Forum

Welcome to the Inaugural Meeting Karen Edson Vice President, Policy and Client Services February 4, 2010

Objective: Enable dialogue on implementation planning and market performance issues

• Review key market performance topics
• Share updates to 2009-2011 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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Agenda

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TIME TOPIC PRESENTER

9:00-9:15 Overview, Objectives Karen Edson 9:15 – 9:45 Power System Technology Architecture & Development Khaled Abdul- Rahman, Hani Alarian 9:45-11:00 Market Performance

• Minimum Online Commitment Constraint
• Improve Imbalance Requirements in RT Market
• RTUC to RDT Commitment Consistency and

Financial Implications

• Load Distribution Factor
• HASP/RTD Price Convergence
• Market Model Improvements

Mark Rothleder 11:00 -12:00 Policy Update

• Current Stakeholder Initiatives
• Market Evolution
• Market Initiatives Roadmap

Margaret Miller 12:00 -1:00 Lunch – Provided by ISO 1:00 – 2:15 Release Planning

• Spring 2010 Release
• Summer 2010 Release
• Fall 2010 Release
• Early 2011 Release
• Upcoming Implementation Efforts

Khaled Abdul- Rahman, Hani Alarian, Janet Morris 2:15 – 3:00 Other Forum Updates – SIUG, SaMC, Team

Power System Technology Architecture & Development

Khaled Abdul-Rahman, PhD. Principal, Market and Performance Initiative Owner Hani Alarian Director, Advanced Power Network Technology

Slide 4

Power System Technology Architecture & Development

• New Department
• Involved from inception through after production
• Works with all departments to balance the needs of

policy, business units, design complexity, implementation, integration, testing, transition to production, maintenance and support after production

• Evaluates the feasibility and balance of the design to

reach the goal of engineering, economic, grid operation,

• ptimization, transmission, performance, and IT needs.

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Slide 6

Our release plan derives from the strategic plan, FERC

• rders, and stakeholder input.

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1 year 2-3 years 5 years

Long term resource planning

Develop Market Design Enhancements

Reduce credit risk Improved Market Efficiency

Comparable Treatment of Generation and Non-Generation

Improved price signals

Continue the Integration of Renewable Resources

Greater Demand participation Infrastructure guided by Reliability and Economics Transparent and well functioning markets Continue to advance State, Regional and Federal priorities

2010

Economic Efficiency Reliability

MSG CB ASHASP PLR PDR SP LDF FOR SCP MOC MWP

Implement Planned Market Improvements

Market Performance

Mark Rothleder Director, Market Analysis & Development

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Slide 8

Current Market Improvements

Slide 8

Short-Term Market Improvements – Current Market

• Minimum Online Commitment Constraint
• Improve Imbalance Requirements in RT Market
• RTUC to RDT Commitment Consistency and

Financial Implications

• Load Distribution Factor
• HASP/RTD Price Convergence
• Market Model Improvements

1 year 2-3 years 5 years During 2010

Minimum Online Commitment Constraint

Slide 9

Objective:

• Obtain correct and consistent unit commitment in IFM/RUC to

satisfy procedural and outage-based reliability requirements

• Reduce the need for exceptional dispatch
• Trade-Date February 5, 2010 start using constraint for G-217/G-

219

Load Distribution Factor (LDF)

Objective:

• Analyze the quality and develop some metrics of LDF

accuracy that can be tracked

• Analyze the LDF correlation between weather patterns and

changes to weather patterns

• Develop and implement improvements to the LDF accuracy

and forecasting

• Track improvements and impacts of LDF accuracy

improvements

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Slide 11

Day-Ahead System LDFs Improvement Overview

• Perform Day-Ahead hourly load forecast for each of the

23 sub-LAPs within the CAISO system

• Adjustment factors, one for each sub-LAPs for each hour

are determined on the basis of the sub-LAPs DA load forecast.

• Adjustment factors are used to adjust DA system LDFs

under the current approach so that the total LDFs within each sub-LAP will reflect sub-LAP forecast loads relative to each other.

• The adjusted DA system LDFs are fed to the market

system to run DA market.

Slide 12

Sub-LAP Day-Ahead Hourly Load Forecast

• Currently, CAISO production system is set up to perform DA load

forecast for 10 load forecast zones

• Load forecast model is based on neural network and auto

regression and moving average methodologies

• Weather forecast and actual load and weather data of pre-specified

lag time are fed to the load forecast model to perform load forecasting

• Sub-LAP DA load forecasting is on “indirect” basis through the load

forecast of the 10 load forecast zones

• Using the 2009 hourly load data of sub-LAPs and load forecast

zones through statistical approach, the CAISO identifies for each sub-LAPs, one or a group of LF zones of no more than 2 to be best correlated with

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Sub-LAP Day-Ahead Hourly Load Forecast cont

• For each sub-LAP, a functional mapping from the load(s) of

the identified forecast zone (group of forecast zones) to the sub-LAP load is determined on the basis best fit between the historical hourly load data of the sub-LAP and the forecast zone.

• In future operation, using the forecast loads of forecast zones,

the forecast load of each sub-LAP is determined by applying the pre-determined functional mapping of the sub-LAP to the forecast load(s) of its corresponding forecast zone (group of forecast zones).

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Proposed Adjustments of DA LDF from Current Production System by Example

• A system consisting two sub-LAPs A and B with sub-LAP A

comprised of Nodes 1 and 2 and sub-LAP B comprised of Nodes 3 and 4.

• Normalized LDFs from current production system adaptation

method are given in the table below

Node Name LDF N1 (Sub-LAP A) 0.4 N2 (Sub-LAP A) 0.3 N3 (Sub-LAP B) 0.2 N4 (Sub-LAP B) 0.1

• LDF values implies that

ratio of the two sub-LAP loads be 7 : 3

Slide 15

Proposed Adjustments of DA LDF from Current Production System by Example

• Forecasted loads of sub-LAPs are 80MW for sub-LAP A

and 20MW for sub-LAP B

• Adjustment factors are 8/7 for sub-LAP A and 2/3 of sub-

LAP B. Each sub-LAP specific adjustment factor is applied to all nodes of the sub-LAP.

Node Adj LDF N1 0.4*8/7 = 0.457 N2 0.3*8/7 = 0.343 N3 0.2*2/3 = 0.133 N4 0.1*2/3 = 0.067

• Final LDFs after adjustments

are listed in the table on the

• left. The adjusted LDFs are

normalized.

Improve Imbalance Requirements of RT Market

Slide 16

Objective:

• Direct 15 minute and 5 minute load forecast
• Analyze the need for regulation/AGC feedback into the

imbalance energy needs with objective of returning regulation resources

• Propose solution and potential approach to dispatching in

recognition of regulation energy dispatched

The ISO improved the consistency between RTPD (HASP) and RTD load forecast.

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RTPD load forecast lags behind RTPD load forecast before the improvement.

Hourly Average of 12/29/09 – 01/01/10

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There is no more such pattern after the improvement.

Hourly Average of 01/02 – 01/05/10

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The ISO will monitor RTM load forecast and its impacts on other market issues.

• Causes for remaining differences are under review
• The improvement may help other known issues
• Accuracy of RTPD unit commitment decision
• Divergence between HASP and RTD energy prices

HASP/RTD Price Convergence

Slide 21

Objective:

• Continue to analyze the sources of the HASP/RTD price divergence
• Evaluate the impact of HASP load forecast for any systemic time shifts
• r load forecasting differences
• Implement and evaluate the Hourly Intertie Ramp enhancements

which are currently in test

• Monitor improvement to RT Energy Offset

RTUC to RTD Commitment Consistency

Slide 22

Objective:

• Understand the drivers to the RTUC and RTD price differences that

leads to different expected results

• Analyze the source of if issue is more a problem with STUC (5 hour

run) and RTD versus RTUC and RTD

• Review STUC SIBR bid replication rules
• Analyze effect load forecast shifting has on RTUC/RTD

price/commitment

• Analyze effectiveness of BCR to make resources whole

Market Model Improvements

Slide 23

Objective:

• Model Trans-Bay DC cable
• Review opportunity for enhancing external network to
• Improve accuracy of responsiveness to Lugo – Victorville
• Congestion. Development of a new nomogram is underway
• Compensating Injections:
• Return automated compensation
• Analyze impact on flow accuracy improvement
• Analyze impact on imbalance

Model: Trans-Bay Cable

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General:

• 53 Mile Direct – Current (DC) Cable
• Connects Pittsburg (East Bay) to Potrero (San Francisco)
• 400 MW Unidirectional Control from Pittsburg to Potrero under CAISO control
• +/-300 MVAR reactive capability under PG&E control
• PTO: Cost recovery via Transmission Access Charge

Model: Trans-Bay Cable

Slide 25

• Primary: Optimally determined based on the economics of the system such

that flow will occur up to the full 400MW capability when the LMP price at Potrero terminal is greater than the LMP at Pittsburg terminal.

• Secondary: ISO operator determines the required power in order to satisfy

reliability requirements.

• Losses: To account for the fact the losses over the DC line are less than the

losses over the AC system from Pittsburg and Potrero, flow will occur even if Potrero is as much as 10 cents less than Pittsburg price

Scenario 1: No congestion into or out of SF but Potrero naturally higher price than Pittsburg

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• DC Cable Flow: 400 MW
• Potrero Price > Pittsburg Price

Scenario 2: Congestion getting power out of Potrero to SF

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• Scenario possible when Potrero 3 online and other work occurring on SF

transmission system

• DC Cable Flow: Optimization may reduce cable flow between 0 – 400 MW to relieve

congestion

• Potrero Price = Pittsburg Price – approx 10 cents

P

Scenario 3: Congestion getting power out of Potrero to SF such that TBC is reduced to 0MW

Slide 28

• Scenario possible when Potrero 3 online and other work occurring on SF

transmission system

• DC Cable Flow: Optimization may reduce cable flow to 0 MW to relieve congestion
• Potrero Price < Pittsburg Price – approx 10 cents

P

Policy Update

Slide 29

Margaret Miller Manager, Market Design & Regulatory Policy

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Our market initiatives release plan is derived from the five year strategic plan.

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1 year 2-3 years 5 years

Convergence Bidding Participating Load Refinements AS for Non-Generation Resources

Current Operations

AS Market Review SCP Phase II Increased Load Granularity Ex-Post Price Corrections Proxy Demand Resource Scarcity Pricing MSG AS Procurement in HASP Forbidden Operation Regions Economic Efficiency Reliability

Active market initiatives on Board calendar

February March May E-Tag Timing AS for Non- Generation Resources Changes to commitment costs – SUC/MLC Information Release Phase 1 and 2 Standard Capacity Product II Post 5-Day Price Correction Make Whole Payment for Demand CRR Credit Enhancements Dynamic Schedules LMPM for PDR Bids for RA Imports CRR Enhancements – load migration

Slide 31

Market Initiatives Planned for 2010-2011

Initiative FERC Mandated Estimated Policy Start Date Estimated Board Presentation

Emergency Demand Response Product N Q2 Q4 AS Market Product Review N Q2 2011 Long Term Resource Adequacy N Q2 TBD ICPM Successor N Q2 Q4 Update Exceptional Dispatch Pricing N Q2 Q4 DAM and RTM Dispatch Enhancements for Intermittent Resources N Q2 2011 Information Release Phase 3 N Q4 2011 Load Aggregation Point Granularity Y Q2 Q4 Bid in Demand in LMPM Process Y Q3 Q4 Multi-Day Unit Commitment in IFM Y Q4 2011 Bid Cost Recovery for Units Running Over Multiple Operating Days Y Q4 2011

Slide 32

Additional high ranked and FERC mandated market enhancements

Initiative FERC Mandated Estimated Policy Start Date 2009 Roadmap Rank

Simultaneous RUC and IFM N TBD High Two Tier Real-Time Uplift Y TBD Medium Long Term CRR Auction Y TBD Medium Exports of AS Y TBD Low AS Substitution Y TBD Low Multi Hour Block Bidding in RUC Y TBD Low

Slide 33

The ISO will update the market initiatives catalog but will not run the ranking process this year

• Leveraging results from 2009 ranking process
• Plate already full with planned and completed market

initiatives to be implemented over the next several years

Slide 34

Release Planning – Project Update

Janet Morris Director, Program Office

Slide 35

2010-2011 Market Initiatives Release Plan

Slide 36

Market Simulation

09 Apr 09 May 09 Jun 09 Jul 09 Aug 09 Sep 09 Oct 09 Nov 09 Dec 10 Jan 10 Feb 10 Mar 10 Apr 10 May 10 Jun 10 Jul 10 Aug 10 Sep 10 Oct 10 Nov 10 Dec 11 Jan 11 Feb

Tariff Filing March Go Live 4/1/52010 Final Proposal 9/30 BOG Approval 12/17 Mkt Sim Go Live 4/1/2010 Final Proposal 8/5 BOG Approval 9/11 Go Live 5/1/2010 Final Proposal 10/02 BOG Approval 10/28 Go Live 2/1/2011 External BRS 8/12 10/1/2010 – 1/31/2011 Tech Specs Q1 2010 External BRS 12/2 BPM Q3 2010 External BRS Q1 2010

Forbidden Operating Regions Scarcity Pricing Proxy Demand Resources

Convergence Bidding Participating Load Refinements

AS Procurement in HASP

Market Sim External BRS 10/19 Tech Specs (initial) 12/1 BOG Approval 9/11 External BRS 12/31 Tech Specs 12/15

Spring 2010 Early 2011

Multi-Stage Generating Unit Modeling

Go Live 10/1/10

Fall

2010

External BRS 11/15 Mkt Sim Go Live 4/1/2010 Mkt Sim BPM BPM Market Simulation Market Simulation BPM July – September 2010 Q3 2010 Go Live 2/1/2011

Summer

2010

Ex Post Price Corrections Make Whole Payments

Go Live Summer 2010

Spring 2010 Release Milestones

Milestone Forbidden Operating Regions AS Procurement in HASP Scarcity Pricing Proxy Demand Resource Publish Final Draft Proposal N/A Aug 25, 2009 Oct 2009 Aug 5, 2009 CAISO BOG Approval N/A Sep 10-11, 2009 Dec 16-17, 2009 Sep 10-11, 2009 Submit FERC Filing Feb 15, 2010 Change Dec 23, 2009 Dec 24, 2009 Feb 2010 On track Publish Business Requirements Jan 4, 2010 (tech. bulletin) Dec 30, 2009 Nov 5, 2009 Oct 19, 2009 (revised – Dec 30) Publish Technical Specifications Not required Not required Not required Dec 1, 2009 Publish BPM Drafts Jan 20, 2010 Jan 20, 2010 Jan 20, 2010 Jan 20 + Feb 3 Begin Market Simulations Mar 1, 2010 On track Mar 1, 2010 On track Mar 1, 2010 On track Mar 1, 2010 (registration) On track Go-Live Apr 15, 2010 Change Apr 1, 2010 On track Apr 1, 2010 On track May 1, 2010 On track

Slide 37

Market Initiatives Update

Spring Release Project Update – Market Simulation

Slide 38

Pre-Simulation Milestones

Date Milestone Project 1/11/10 Submission of AARFs for user accounts FOR, Scarcity Pricing (SP), AS HASP 2/04/10 Request sample Resource IDs by email PDR 2/08/10 Market Simulation Plan posted All 2/16/10 Market Simulation Kick-off Conference Call All 2/18/10 Receive sample Resource IDs / Registrations PDR 2/22/10 Connectivity Testing (MAP Stage Environment) FOR, Scarcity Pricing (SP), AS HASP 3/01/10 Connectivity Testing (DR Environment) PDR 3/01/10 Rules Testing in SIBR Lite AS-HASP, PDR 3/01/10 Registration GUI is available for only those who request it *PDR *One on one support will be available by appointment

PDR

Monday Tuesday Wednesday Thursday Friday

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1 2 3 4 5 8 9 10 11 12 15 16 17 18 19 22 23 24 25 26 31 30 2 1 29

FOR – Live Production Feed

PDR – Registration / SIBR Rules

Spring 2010 Release Market Simulation Schedule March

SP / AS-HASP FOR

System Available No Scenarios

PDR – Registration / SIBR Rules PDR – Registration /SIBR Rules SP / AS-HASP FOR

System Available No Scenarios

SYSTEM AVAILABLE – NO SCENARIOS

PDR – Registration / SIBR Rules CODE FREEZE PDR – End to End SYSTEM AVAILABLE – NO SCENARIOS GO-LIVE SP, AS-HASP, FOR

System Available No Scenarios

Monday Tuesday Wednesday Thursday Friday

Slide 40

1 2 5 6 7 8 9 12 13 14 15 16 19 20 21 22 23 28 27 30 29 26

PDR – End to End PDR – End to End PDR – End to End CODE FREEZE PDR – End to End GO-LIVE (5/1) PDR – System Available (No Scenarios)

System Available No Scenarios System Available No Scenarios System Available No Scenarios System Available No Scenarios

Spring 2010 Release Market Simulation Schedule April

Market Initiatives Update

Spring Release Project Update – Market Simulation

• Market Simulation Communication Plan – to be posted
• n 2/8/10
• Market Notices
• ISO Market Simulation Portal
• Kickoff on 2/16/10
• Teleconferences: starting week of 2/22/10
• Mondays at 1pm Pacific, Thursdays at 9am – as needed
• IMS Tickets – primary source for defect/issue reporting
• Dedicated Phone Line (Number TBD)
• SIUG
• Market Simulation Support Center (as with Winter Release 2009)
• Help Desk: 1-888-889-0450, or (916) 351-2309

Slide 41

Spring Release – Technical Update

Khaled Abdul-Rahman, PhD Principal, Market and Performance Initiative Owner Hani Alarian Director, Advanced Power Network Technology

Slide 42

Market Initiatives Update

Spring Release Project Update – FOR Market Simulation Approach

• FOR Market Scenarios

1. Decrease the bid price of all FOR resources to Floor Price cap forcing all FOR resources to go to their hi operating output and in turn through any of their FOR in between 2. Increase the bid price of all FOR resources to Ceiling price cap forcing them to go through their FOR regions as they go from Hi operating output to their low operating output 3. Split the resources with FOR into two groups called A and B and force them to go through their FOR

• Increase the bid price of group A to Ceiling price cap
• Decrease the bid price of group B to Floor price cap

4. Repeat Test 3 above but reverse A and B group Note: The goal of these tests is to force FOR to be crossed and observe their behavior and the performance of all other units that must balance commodities during FOR crossing

Slide 43

Market Initiatives Update

Spring Release Project Update – SP Market Simulation Approach

• Scarcity Pricing Market Scenarios (performed in DA,

HASP and RTUC)

1. Trigger Spinning Reserve shortage and Regulation down shortage in the CAISO Expanded System Region 2. Trigger Non-Spinning Reserve shortage in the SP-26 Sub- Region 3. Trigger scarcity in all commodities in CAISO Expanded System Region and all active Sub-Regions

• Daily settlement statements will be published

Slide 44

Market Initiatives Update

Spring Release Project Update – AS HASP Market Simulation Approach

• AS HASP Market Scenarios

1. Verify procurement of AS in HASP for Hourly Pre-Dispatch resources and that it is contingent and never used in normal RTD runs 2. Call a Contingency dispatch in the middle of an hour 3. Call a Contingency dispatch at the top of an hour 4. Call 2 Contingency dispatches in the same hour 5. Manual mid-hour CAS change

• Daily settlement statements will be published

Slide 45

Market Initiatives Update

Spring Release Project Update – PDR Market Simulation Approach

• PDR Simulations are expected to include the following

types of scenarios:

• Bid Submissions and Market Clearing Scenarios
• DA Energy Only
• DA Energy plus Capacity (A/S & RUC - various combinations)
• DA and RT (various dispatch scenarios)
• DA and RT with SLIC Outages
• Post Market Scenarios
• Metering and Baseline Calculation Validation
• Settlements: DA, RT (energy and ancillary services, various conditions)
• Settlements: No-Pay (various conditions)
• Daily settlement statements will be published
• A mini-monthly settlement statement and invoice will be

published

Slide 46

Milestone Multi-Stage Generator (full release) Publish Final Draft Proposal May 8, 2009 CAISO BOG Approval May 18, 2009 Submit FERC Filing Mar 2010 Publish Business Requirements Aug 12, 2009 Publish Technical Specifications Dec 15-31, 2009 (initial drafts) Settlement Configuration Guides Apr 2010 On track Publish BPM Drafts Jun 2010 On track Begin Market Simulations July 2010 On track Go-Live Oct 1, 2010 On track

Fall 2010 Release Milestones – Project Update

Slide 47

Fall 2010 Release – Technical Update

Slide 48

• Multi-Stage Generator Modeling
• Working on detailing and defining the limitation for the

transition of a resource from FOR to MSG in real-time

• Modifying GOTS simulation to accommodate MSG
• All test data were generated and being used for unit

testing

• Working on improving performance design for RTM
• Soon to test performance impact of MSG
• Finalized test case scenarios

Early 2011 Release Milestones – Project Update

Milestone Convergence Bidding Participating Load Refinements Publish Final Draft Proposal Oct 2, 2009 N/A ISO BOG Approval Oct 29-30, 2009 N/A Submit FERC Filing Q1 2010 On track TBD Publish Business Requirements Dec 2, 2009 Q1 2010 On track Publish Technical Specifications Q1 2010 On track Q2 2010 On track Publish BPM Drafts Q3 2010 On track Q3 2010 On track Begin Market Simulations Oct 4, 2010 On track Q4, 2010 On track Go-Live Feb 1, 2011 On track Q1, 2011 On track

Slide 49

Early 2011 Release Milestones – Technical Update

Slide 50

• Convergence Bidding
• Use Cases (MF, MO, Posting, Settlement, CMRI, OASIS) under

final review

• SIBR and CMS interface Design under final review
• SIBR rules 4.0 under final review
• CRR clawback Architecture design under review
• Drafting Implementation Plan outline
• Design Document Specification from Siemens under review
• Software Development Phase
• Testing plans

Early 2011 Release Milestones – Technical Update

Slide 51

• Participating Load Refinements
• Finalizing BRS
• Separate track for required EMS changes related to regulation

requirements

• Refining Use Cases
• Developing SRS
• Performing Impact Assessment

Release planning of new market initiatives is based on joint impact assessment.

• Scope
• Impact assessment begins with straw proposal
• ISO determines impacts to external business process, system

interfaces, BPMs, and any other touch points

• ISO communicates impacts as the policy phase progresses
• Schedule
• Estimates are based on level of effort
• Resource and other constraints are considered
• Estimates are refined as the policy evolves to final proposal
• Implementation date is jointly determined as part of final proposal
• Budget
• Factor implementation costs into market design complexity
• Cost / benefit discussions are included in the policy discussion

Slide 52

Example: Ex-Post Price Corrections Make-Whole Payments

• Scope
• Straw proposal posted on 12/16/09
• ISO determined impacts to post market processes, determined no

external system interface changes, and identified that changes would be required in the Settlements & Billing BPM

• Impacts were communicated at the 1/5/10 Release Planning Workshop
• Schedule
• Estimates were determined to be low (less than 3 months)
• Resource and other constraints are being considered
• The final proposal is schedule to be presented to the ISO Board on

2/10/10 with a proposed implementation in the summer of 2010

• Budget
• Implementation options presented to stakeholders were based on cost

consideration

Slide 53

Current Impact Assessments - February

• Make Whole Payment for Convergence Bidding
• To be included in the Convergence Bidding project plan
• E-Tagging Timing Requirement
• To be included in the Convergence Bidding project plan
• Cost impact is under review
• Information Release Phase 1 and 2
• Phase 1 implementation plans are under review
• Phase 2 implementation will be included in the Convergence

Bidding project plan

• LMPM for PDR
• Run AC without PDR bids (Option 3) to be included in PDR

project plan; no impact to schedule

Slide 54

Make Whole Payment for Convergence Bidding Impact Assessment

Slide 55

Application Software Changes The following application will require software modifications for Convergence Bidding:  SaMc Application change will be made as part of convergence bidding. BPM Changes BPM changes will be made as part of convergence bidding BPM changes. Business Process Changes Business process changes will be evaluated as part of business process changes for convergence bidding. Client Training Materials External training will be provided as part of convergence bidding. Operating Procedures To be determined

E-Tagging Timing Requirement Impact Assessment

Slide 56

Application Software Changes The following application will require software modifications for Convergence Bidding:  SaMc Application change will be made as part of convergence bidding. BPM Changes BPM changes will be made as part of convergence bidding. Business Process Changes Business process changes will be evaluated as part of convergence bidding. Client Training Materials External training will be provided as part of convergence bidding. Operating Procedures To be determined

Information Release Phase 1 Impact Assessment

Slide 57

Application Software Changes The following applications will require software modifications for information related to transmission constraints:  OASIS  Secured Web Site communication (to be determined) BPM Changes BPM change, Market Operation Business Process Changes Business process changes will be evaluated Client Training Materials To be determined Operating Procedures None

Information Release Phase 2 Impact Assessment

Slide 58

Application Software Changes The following application will require software modifications for Convergence Bidding:  OASIS Application change will be made as part of convergence bidding. BPM Changes BPM changes will be made as part of convergence bidding. Business Process Changes Business process changes will be evaluated along with other business process changes for convergence bidding. Client Training Materials External training will be provided as part of convergence bidding. Operating Procedures None

LMPM for PDR Impact Assessment

Slide 59

Application Software Changes The following applications require software modifications:  IFM/RTM Application changes are intended as part of PDR changes. BPM Changes BPM changes will be made along with other PDR BPM changes. Business Process Changes Business process changes will be evaluated along with other business process changes for PDR. Client Training Materials External training will be provided as part of PDR. Operating Procedures None

• The following impacts assessments are underway and will be

discussed at the next Market Performance and Planning Forum

• AS for Non-Generation Resources
• Standard Capacity Product II
• CRR Enhancements
• Changes to Commitment Costs – Transition Cost
• Post 5-Day Price Correction

Slide 60

Impact Assessments – March through May

Other Forum Updates: SIUG, SaMC

Slide 61

SIUG Jami Long, Manager of Business Solutions SaMC Brad Bouillon, Manager of Billing & Settlements

SIUG Updates

• SIUG Scope Change
• Release Updates & Q&A
• System Incident/Problem Updates
• Activity Planning and Execution Coordination

Slide 62

SIUG Updates: Environment

• Environment Overview
• The purpose
• An inventory of external-facing applications
• Environment availability and support information
• Provide a single reference for all external-facing ISO connectivity

information including URLs, API Addresses, and IP Addresses

• Under Strict Version Control

Slide 63

SIUG Updates: Environments

• MAP-Stage

MAP Stage is used for Market and Performance (MAP) initiatives and any

• ther long-running projects that require a market simulation. External-

facing systems in this environment include ADS, BAPI, CMRI, DRS, MF, MDS, MPP, OASIS, OMAR, PIRP, SIBR, and SLIC. SIBR-Lite may be up to MAP-Stage code levels as needed.

• Stage

Stage is used as the production promotion path for variance corrections and small enhancements. This environment may be used by participants for general testing purposes of functionality that is in production. The ISO may close access for short periods in order to conduct specific testing. External-facing systems in this environment include ADS, BAPI, CMRI, DRS, MF, MDS, MPP, OASIS, OMAR, PIRP, SIBR, SIBR-Lite, and SLIC.

• Production

Production systems cannot be used for testing.

Slide 64

Settlements and Market Clearing (SaMC) Usergroup

Slide 65

Purpose: To provide regular status updates on related SaMC initiatives and allow for an interactive discussion on system-related, or system- impacting topics. Frequency: Calls are held weekly from 9-10AM (PST) on Wednesdays More information: Meeting notes are posted each week at:

http://caiso.com/docs/2004/05/11/200405110959025865.html

SaMC User Group Agenda (Example)

January 27, 2010

10:00 a.m. – 11:00 a.m. (Pacific Time)

Web Conference Information Conference Call Information URL: http://www.webmeeting.att.com Meeting Number: 8665282256 Access Code: 5319800 Domestic Call In: (866) 528-2256 International Call In: (216) 706-7052 Pass Code: 5319800

Time Topic Presenter 10:00 – 10:10 Welcome and Introductions Brad Bouillon 10:10 – 10:30 SaMC Update

• General SaMC Update
• Settlements Documentation Update
• BPM Documentation Update
• FERC NOPR on Credit Issues and Payment

Acceleration Brad Bouillon Tri Huynh Elizabeth Caldwell Brad Bouillon 10:30 – 11:00 Open Discussion Brad Bouillon

Slide 66