Market Performance and Planning Forum March 16, 2010 Objective: - - PowerPoint PPT Presentation

Market Performance and Planning Forum

March 16, 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

Slide 2

Agenda

Slide 3

TIME TOPIC PRESENTER

9:00-9:15 Overview, Objectives Mercy Parker-Helget 9:15-11:00 Market Performance

• Minimum Online Commitment Review
• Discussion of Effective Threshold Report
• Bid Caps and associated parameters
• Cycling of Resources and initial conditions
• Constraint Management

Mark Rothleder, Nan Liu, Brian Jacobsen 11:00 -11:30 Policy Update Margaret Miller 11:30-12:30 Lunch – Provided by ISO 12:30 –3:00 Release Planning

• Impact Assessment of new policy initiatives
• Convergence Bidding
• Technical Update
• Technical Specifications
• Upcoming Implementation Efforts
• Participating Load Refinements
• Business Requirements Specifications
• Impact Assessment
• Release Update

Khaled Abdul- Rahman, Janet Morris, Li Zhou

Market Performance

Mark Rothleder Director, Market Analysis & Development

Slide 4

Minimum Online Commitment Review

• G-219 - Local Area Generation Requirement for Orange

County activated requires approximately 224MW of

• nline commitment at current load levels
• Results in 0 to 1 unit commitment
• G-217 - South-of-Lugo Generation Requirements not

currently active at current load level

• Extending Minimum Online Commitment constraint to
• utage conditions in final testing

Slide 5

Discussion of Effective Threshold Report

• March 1, 2010 Report on Effectiveness Threshold

posted: http://www.caiso.com/274c/274ce65363b0.html

• Currently effectiveness threshold was applied based

individual resource’s shift-factor relative to distributed slack reference

• Analyzes impact on operational market performance
• Analyzes impact on APNode vs Anode pricing

Slide 6

Discussion of Effective Threshold Report

Slide 7

• No increase or decrease from 2% effectiveness

threshold recommend at this time

• Consideration should be given to investigate the

alternative effectiveness threshold methodologies that address combinational effectiveness rather than individual resource effectiveness

• Current methodology in some situation may reduce ability to

manage and price congestion

• Current methodology in some situations may not eliminate

relatively ineffective combinations of dispatch

• The impact on APNode vs. ANode differences are small

and no change is recommended

Discussion of Effective Threshold Report

Slide 8

500 1,000 1,500 2,000 2,500

• 11.00%
• 9.50%
• 8.50%
• 7.50%
• 6.50%
• 5.50%
• 4.50%
• 3.50%
• 2.50%
• 1.50%
• 0.50%

0.50% 1.50% 2.50% 5.00% 6.00% 7.00% 8.00% 9.50% 13.50% 22.00%

Counts of Nodes Shift Factors: (ΔFjk/ΔPi)ref x 100 (%) Typical Hourly Shift-Factor 32212_E.NICOLS_115_32214_RIO OSO _115_BR_1 _1

Total

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

• 3.00%
• 1.00%
• 0.50%

0.00% 0.50% 1.00% 1.50% 2.00% 2.50% 5.00% 7.00% 7.50% 8.00% 9.00% 9.50% 10.00%

Counts of Nodes Shift Factors: (ΔFjk/ΔPi)ref x 100 (%) Typical Hourly Shift-Factor VICTVL_BG

Total

• East Nicolas to Rio Oso 115 kV and Palermo to

Honcut Junction 115 kV Constraints

• Low Shift-Factors excluded resources that could have

been effective in congestion relief

• VICTVL_BG due to its location has resources with

relatively low effectiveness

• Combinations of effective resource re-dispatch are

not showing as effective since individual that have shift-factor lower than threshold are set to 0 effectiveness

Discussion of Effective Threshold Report

Slide 9

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

• 53.00%

47.00%

Counts of Nodes Shift Factors: (ΔFjk/ΔPi)ref x 100 (%) Typical Hourly Shift-Factor SCE_PCT_IMP_BG

Total

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

• 90.00%

10.00%

Counts of Nodes Shift Factors: (ΔFjk/ΔPi)ref x 100 (%) Typical Hourly Shift-Factor SDGE_CFEIMP_BG

Total

• SCE_PCT_IMP and SDG_CFEIMP_BG constraints are

examples of constraint where re-dispatch of resources that are within individual effective threshold can result in combinations of re-dispatch that is relatively ineffective

• Ineffective combinations of re-dispatch result in

prices between bid cap ($500) and scheduling run parameter for constraint relaxation ($5000)

• This effect can be due to use of lossless shift-factor
• r due to small differences between resources both
• f which are considered effective on an individual

resources basis

Discussion of Effective Threshold Report

Slide 10

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

• 99.50%

0.50%

Counts of Nodes Shift Factors: (ΔFjk/ΔPi)ref x 100 (%) Typical Hourly Shift-Factor HUMBOLDT_BG

Total

• HUMBOLDT_BG is example where a few resources

are highly effective but all other resources on

• pposite side of constraint are considered ineffective
• While ineffective resources are re-dispatched to

maintain power-balance, such ineffective resource’s LMP will not reflect congestion relief

Discussion of Effective Threshold Report – APNode vs ANode

Slide 11

ANode Clearing Price APNode Price Bid Price ($/Mwh) Demand (MW)

APNode Vs Anode Impact

ANode Clearing Price APNode Clearing Price ANode Clearing MW MW Intersect

• f APNode Price
• n DLAP Bid Curve
• APNode price is the weighted average of constituent PNodes
• Anode price is the price of the aggregate ANode and reflects the

effectiveness of the aggregate Anode relative to a constraint

Discussion of Effective Threshold Report – APNode vs ANode

Slide 12

Comparison PGAE_DLAP SCE_DLAP SDGE_DLAP % of Day-Ahead hours with ABS(APNode - Anode) < $.01 86.8% 94.1% 98.0% % of Day-Ahead hours with ABS(APNode - Anode) < $1.0 98.78% 99.8% 100% Maximum Positive Price Difference (APNode>Anode) $23.28 $45.15 $0.14 Maximum Negative Price Difference (APNode<Anode)

• $1.68
• $0.29
• $0.15

Estimated settlement impact of APNode and Anode price difference $75,068 $228,225 $0

Bid Caps and associated parameters

Slide 13

• Energy Bid Cap changes from $500 to $750
• Energy Soft-Bid Floor remains unchanged at -$30
• A/S Bid Cap remains unchanged at $250
• RUC Bid Cap remains unchanged at $250
• $2500 Price Cap is eliminated
• Other parameters change coordinate with change in

Energy Bid cap as follows

Bid Caps and associated parameters – Day Ahead

Slide 14

Penalty Price Description Scheduling Run Value Pricing Run Value Comment Market energy balance 6500 500750 Market energy balance is the requirement that total supply equal the sum of total demand plus losses for the entire system. In the IFM energy balance reflects the clearing of bid-in supply and demand; in the MPM-RRD component of the DAM it reflects the scheduling of bid- in supply against the ISO demand forecast. Transmission constraints: Intertie scheduling 7000 500750 Intertie scheduling constraints limit the total amount of energy and ancillary service capacity that can be scheduled at each scheduling point. Transmission constraints: branch, corridor, nomogram (base case and contingency analysis) 5000 500750 In the scheduling run, the market optimization enforces transmission constraints up to a point where the cost of enforcement (the “shadow price” of the constraint) reaches the parameter value, at which point the constraint is relaxed. Transmission Ownership Right (TOR) self schedule 5900, -5900 500->750,

• 30

A TOR Self-Schedule will be honored in the market scheduling in preference to enforcing transmission constraints. Existing Transmission Contract (ETC) self schedule 5100 to 5900, -5100 to -5900 500->750,

• 30

An ETC Self-Schedule will be honored in the market scheduling in preference to enforcing transmission constraints. The typical value is set at $5500, but different values from $5100 to $5900 are possible if the instructions to the ISO establish differential priorities among ETC

• rights. For some ETC rights the ISO may use values below the stated

scheduling run range if that is required for consistency with the instructions provided to the ISO by the PTO. Converted Right (CVR) self schedule 5500, -5500 500->750,

• 30

A CVR Self-Schedule is assigned the same priority as the typical value for ETC Self-Schedules.

Bid Caps and associated parameters – Day Ahead

Slide 15

Penalty Price Description Scheduling Run Value Pricing Run Value Comment Self-scheduled CAISO demand and self-scheduled exports using identified non- RA supply resource 1000->1500 500750 Pursuant to section 31.4, the uneconomic bid price for self-scheduled demand in the scheduling run exceeds the uneconomic bid price for self-scheduled supply and self- scheduled exports not using identified non- RA supply resources. Self-scheduled exports not using identified non-RA supply resource 800->1200 500750 The scheduling parameter for self-scheduled exports not using identified non-RA capacity is set below the parameter for generic self- schedules for demand. Regulatory Must-Run and Must Take supply curtailment

• 750->-1125
• 30

Regulatory must-run and must-take supply receive priority over generic self-schedules for supply resources. Price-taker supply bids

• 550->-825
• 30

Generic self-schedules for supply receive higher priority than Economic Bids at the bid cap.

Bid Caps and associated parameters – Real Time

Slide 16

Penalty Price Description Scheduling Run Value Pricing Run Value Comment Energy balance/Load curtailment and Self-Scheduled exports utilizing non-RA capacity 6500 500750 Scheduling run penalty price is set high to achieve high priority in serving forecast load and exports that utilize non-RA capacity. Energy bid cap as pricing run parameter reflects energy supply shortage. Transmission constraints: Intertie scheduling 7000 500750 The highest among all constraints in scheduling run, penalty price reflects its priority over load serving. Energy bid cap as pricing run parameter reflects energy supply shortage. Transmission constraints: branch, corridor, nomogram (base case and contingency analysis) 5000 500750 Scheduling run penalty price will enforce internal transmission constraints up to a re-dispatch cost of $5000 per MWh of congestion relief. Energy bid cap as pricing run parameter consistent with the value for energy balance relaxation under a global energy supply shortage. Self-scheduled exports not using identified non-RA supply resource 800->1200 500750 Scheduling run penalty price reflects relatively low priority in protection as compared to other demand categories. Energy bid cap as pricing run parameter to reflect energy supply shortage. Final IFM Supply Schedule

• 2000->
• 3000
• 30

Scheduling run penalty price is much higher in magnitude than supply generic self-schedule but lower than ETCs. Energy bid floor is the pricing parameter for all energy supply self-schedules. Regulatory Must-Run and Must Take supply curtailment

• 825->
• 1125
• 30

Scheduling run penalty price reflects the higher priority of regulatory must- run and must-take supply received over generic self-schedules for supply

• resources. Energy bid floor is the pricing parameter for all energy supply

self-schedules. Price-taker supply bids

• 550->
• 825
• 30

Scheduling run penalty price for generic supply self-schedules is 10% higher in priority than Economic Bids at the bid cap. Energy bid floor is the pricing parameter for all energy supply self-schedules.

Bid Caps and associated parameters – Real Time

Slide 17

Penalty Price Description Scheduling Run Value Pricing Run Value Comment

Conditionally qualified Reg Up or Down Real Time self- provision (RTPD only)

• 285->
• 400

Scheduling run penalty price allows the conversion

• f AS self-schedules to Energy to prevent LMP of

local area from rising so high as to trigger transmission constraint relaxation. AS bid floor is pricing parameter for any type of AS self-provision. Conditionally qualified Real Time Spin self-provision (RTPD only)

• 280->
• 395

Scheduling run penalty price is below the one for regulating-up. AS bid floor is pricing parameter for any type of AS self-provision. Conditionally qualified Real Time Non-Spin self- provision (RTPD only)

• 275->
• 390

Scheduling run penalty price is below the one for

• spin. AS bid floor is pricing parameter for any type
• f AS self-provision.

Cycling of Resources and initial conditions

• Currently DAM Initial Condition of a resource are

determined based on the status of the resource in HE24 from the previous DAM (IFM/RUC) result

• If resource is off-line at HE24, resource is initialized as off-line

must satisfy minimum down time

• If resource is on-line at HE24, resource is initialized as on-line

and commitment / de-commitment decision will be optimally determined subject to minimum run time

• Cycling of resource currently limited from considering

next days peak

Slide 18

Cycling of Resources and initial conditions

• Interim solution for consideration: Consider informing

DAM initial conditions based on Real-Time self-schedule information submitted by SC prior to 10 am

• If resource is committed in HE24 then the ISO will continue to

initialize resource as on-line for next DAM

• If SC self-schedules for TD+0 HE24 then ISO will initialize the

resource as on-line when running market for TD+1 regardless if resource was committed in DAM

• If SC does not self-schedule HE24 and resource has no DAM

commitment for HE24 then resource initial condition will be off- line

• Some protection may be necessary to reduce exposure

to over-generation conditions in HE24

Slide 19

Constraint Management

• Transmission Constraint Information Release Status
• Completed Items
• Filed with FERC in December 2009 describing the ISO’s constraint

management process in compliance with FERC Oct 2nd Order.

• Stakeholder process.
• Board of Governor approved
• Monthly constraint adjustments summary provided in Monthly Market

Performance Report starting January 2010 http://www.caiso.com/2749/2749843772a50.pdf

• Next Steps
• Preparing new tariff language for constraint information requiring FERC

approval.

• Evaluating implementation effort and timing
• Evaluate additional information release needs.

Slide 20

Constraint Management (Cont.)

• DB47 Model Improvements: Adding equivalent network

in external LADWP model to improve VICTVL_BG flows

Slide 21

L

Mona Gonder IPP Marketplace Mead 500 Lugo 24086 Westwing

Mead 230 N

Victorville 26105

SYLMAR S 230

Adelanto 500 6003 MEAD230 – MEAD500 182 / 182 GOND - IPPDC 5 / 15 MONA - IPPDC 281 / 295 IPPDC - ADLN 647 / 471 WSTWG - MEAD 126 / 126 MEAD - MKTPC 369 / 369 MKTPC - ADLN 423 / 423 MCCL - MKTPC 731 / 731 ADLANTO - VICTVL 874 / 366

CAMINO ELDORADO 230 Mead 230 S

Toluca 500 6079 Century287 6070 Sylmar LA230 6094 Toluca 230 6078 Century230 6072 Rinaldi 230 6061 Rinaldi 500 6062 Inyo 230 24729

LADWP Network

~ ~ ~

VICTVL 287 6104 Mead 287 6051 MCCL 230 6046 MCCL X 500 6047 ADLN - SYL 162 / 162 VICTVL - SYL 26 / 26

~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~

Constraint Management (Cont.)

• New Constraints
• MOC (Minimum Online Capacity in IFM)
• G-219 (Done)
• G-217 (Done but not active based on loading conditions)
• Outage Conditions (testing interface)
• SCISL
• Southern California Intertie Separation Limit.
• To more accurately count for the fact that SCE and SDG&E systems are one

(not separate) island should an extreme under frequency event occur.

• Plan to deactivate the SCE_PCT_IMP_BG limit.
• Plan to issue technical bulletin prior to implementing SCISL.
• Considering late April for implementation to coincide with DB 47 release.

Slide 22

Constraint Management (Cont.)

• Compensating Injections
• Performed some sample testing in February
• Evaluating relationship and impact of “Reliability Based Control”

implemented on March 1, 2010

• Currently in trial evaluation for 1 year
• Replaces CPS2 Control Criteria
• Additional and extended evaluation will be performed in March

Slide 23

Policy Update

Slide 24

Margaret Miller Manager, Market Design & Regulatory Policy

Active market initiatives on Board calendar

March May July AS for Non-Generation Resources Changes to commitment costs – SUC/MLC Bids for RA Imports and subset of hours RA CRR Credit Enhancements Post 5-Day Price Correction Dynamic Schedules CRR Enhancements – load migration Standard Capacity Product Phase II RETPP

Slide 25

Market Initiatives Starting in Q2

Initiative FERC Mandated Estimated Policy Start Date Estimated Board Presentation

Reliability Demand Response Product No May 2010 November 2011 AS Market Product Review No April 2010 May 2011 Modifications to Small Generator Interconnection Procedures No March 2010 (internal) December 2010 Successor to ICPM Yes March 2010 (internal) December 2010 Update of Exceptional Dispatch Pricing Yes March 2010 (internal) December 2010 Long-Term Resource Adequacy No April 2010 (internal) TBD DAM and RTM Dispatch Enhancements for Intermittent Resources No June 2010 March 2011

Slide 26

Convergence Bidding Policy Update

• FERC Order on convergence bidding conceptual filing -

E-2, California Independent System Operator Corp., Docket Nos. ER10-300-000 and ER06-615-000

• Plan to address change in position limits and tariff filing

schedule discussed on 3/2 conference call

• Presentation posted at:

http://www.caiso.com/274d/274d76f752940.pdf

• Tariff language to be filed in May

Slide 27

Impact Assessment – New Market Initiatives

Li Zhou

• Sr. Advisor, Program Office

Slide 28

Transmission Constraint Data Release Impact Assessment

Slide 29

Application Software Changes The following applications will require software modifications for information related to transmission constraints:  OASIS (Binding Constraints and Contingency causing the Constraint Binding)  Secured Web Site communication (Data download based on NDA agreement – Constraints being Enforced and Definitions of those Constraints) BPM Changes BPM change, Market Operation, Market Instruments Business Process Changes N/A Client Training Materials Not Planned Operating Procedures N/A Market Simulation Not planned Proposed Implementation Timeframe To be implemented in the summer of 2010; ISO will provide notice of deployment date four weeks in advance.

Ex Post Price Correction Make Whole Payments Impact Assessment (Physical Load and Export)

Slide 30

Application Software Changes Post market correction. Will calculate the resource level LMPs (DA for load / export, HASP for export) to reflect the would-be make whole payment if any when Ex Post price correction happens. BPM Changes BPM change: Market Operations, Attachment C Business Process Changes N/A Client Training Materials Methodology has been described in the following linked document, http://www.caiso.com/2495/2495ccf168cd0.pdf Example will be provided through SIUG Operating Procedures N/A Market Simulation Not planned – plan to share actual results of a correction. Proposed Implementation Timeframe Summer, 2010. Will inform market participants four weeks in advance.

Regulation for Non-Generation Resources (NGR) Scope

Slide 31

NGR Model NGRs will be modeled as Generating Resources by offsetting their operating range so that their Minimum Load (Pmin) is zero. For example, the ISO would model a ±20 MW NGR as a Generating Resource with an operating range from 0 to 40 MW and a fixed schedule at 20 MW. These resources would participate only in the Regulation Market. Consequently, they would be certified for Regulation with a single regulating range between their Minimum Load (Pmin) of 0 MW and their Maximum Capacity (Pmax). DA and RT Bidding NGRs would submit a self-schedule halfway within their regulating range and only Regulation bid and/or self-provision in the DAM and RTM. No Energy or other AS bids would be submitted. Market Clearing Results NGRs will be considered always on-line. NGRs would have energy schedule, regulation up and down awards in the DAM/RTM. CMRI and ADS continue to be used to post results for NGRs like generation resources. AGC Model EMS shall remove the self schedule from the AGC control signals sent to NGRs on Regulation, which means that set point will be positive for regulation up and negative for regulation down. Settlement There shall be no energy settlement. NGR settlement shall include only regulation settlement with associated regulation No Pay and certain GMC changes.

Regulation for Non-Generation Resources Impact Assessment

Slide 32

Application Software Changes Application changes include MasterFile, SIBR, IFM/RTM, EMS, MQS and Settlement BPM Changes To be determined Business Process Changes To be determined Client Training Materials To be determined Operating Procedures To be determined Market Simulation To be determined Proposed Implementation Timeframe To be determined

Standard Capacity Product Phase 2 Impact Assessment

Slide 33

Application Software Changes The following applications will require software modifications for information related to Standard Capacity Product 2:  ISO Reliability Requirements  Resource Adequacy Availability Management  Settlement BPM Changes To be determined Business Process Changes To be determined Client Training Materials To be determined Operating Procedures To be determined Market Simulation Winter, 2010 Proposed Implementation Timeframe To be implemented by 1/1/2011

Convergence Bidding (CB)

Khaled Abdul-Rahman Principal, Markets and Performance Initiative Owner

Slide 34

Convergence Bidding – Technical Update

• Design supports CB on both nodal and aggregate basis
• There is no proposed change in the position limit design for both

internal nodes as well as at inter-ties

• LMPM will continue using forecasted load for CB implementation
• No virtual bids are considered in MPM-RRD process
• No virtual bids are considered in RUC process
• Nodal constraints are enforced when AC solution is not attainable
• Both physical and virtual bids are treated equally when a nodal

constraint is enforced

Slide 35

Convergence Bidding – AC Solution

• When an AC Solution cannot otherwise be reached, a nodal/group
• f nodes constraint will be enforced
• MW limit is defined for each node based on the physical characteristics of the

generation unit at that node (for gen busses) or the load forecast (for load busses)

• MW Limit = Physical MW * (1+%delta)
• A percent violation is calculated for each bus at which CB occurs
• %Violation = [ abs( Net MW ) – Limit ] * 100/Limit on nodes that have CB
• A list of the biggest %Violation is automatically generated
• Nodes with physical bids only will not appear in the violation list
• A nodal MW constraint is imposed
• A nodal constraint is automatically applied to a configurable subset of the

%Violation list if a DC solution is passed back to UC from a given NA run

• Both physical and virtual bids are subject to this constraint once it is imposed
• A DC solution is still a possibility

Slide 36

Convergence Bidding – Aggregation

• The ISO will size the software to handle 30,000 bids and 700,000

bid segments in Day-Ahead Market run

• A bid is an SC for a location for supply/demand type for a day
• A bid segment is defined as a price/MW pair for an hour
• Smallest convergence bid segment is 1 MW
• The ISO will aggregate bid segments at a single location across multiple SC

to create a composite bid curve for use in the optimization

• Following the determination of cleared quantities at each location, awards

based on the composite bid curve will be disaggregated and assigned back to the correct SC

Slide 37

Convergence Bidding – Aggregation

• Example – Three SCs submit Virtual Supply bids at the same node
• SC1 submits: (0,$25), (25,$32), (50,$35), (75,$37), (100, $37)
• SC2 submits: (0,$35), (50,$45), (100,$45)
• SC3 submits: (0,$30), (10,$35), (20, $45), (30,$47), (40,$47)
• The market program will combine these three bids into:
• (0,$25), (25,$30), (35,$32), (60,$35), (145,$37), (170,$45), (230,$47), (240, $47)
• This bid curve will be used in the IFM representing the total virtual supply to be

considered at the submitted bid location

Slide 38

Convergence Bidding – Disaggregation

• Assume the IFM cleared at $35 at this node for 130MW
• Any bid segments under $35 will clear
• Since more than one participant submitted a $35 segment, and that segment is

marginal, the MW at $35 will be awarded pro-rata among the participants

• Allocation of Marginal Segment
• SC1 would receive 29.4% (i.e. 25 MW / 85 MW) of the pro-rata portion
• SC2 would receive 58.8% (i.e. 50 MW / 85 MW) of the pro-rata portion
• SC3 would receive11.8% (i.e. 10 MW / 85 MW) of the pro-rata portion
• Final CB awards at the selected node:
• SC1: 50 MW + (0.294 * 70 MW) = 70.58 MW
• SC2: (0.588 * 70 MW ) = 41.16 MW
• SC3: 10 MW + (0.118 * 70 MW) = 18.26 MW

Slide 39

Convergence Bidding – Technical Specifications

Slide 40

• SIBR rules, XSDs, WSDLs and associated technical documentation is on

track to be posted on March 31

• Submit CB_RawBidSet
• Submit CB_BidAction
• Retrieve CB_CurrentBidResults
• Retrieve CB_CleanBidSet
• CMRI Reports
• Retrieve CBAwards
• OASIS Reports
• Day Ahead Aggregate Convergence Bidding Awards
• Day Ahead Convergence Bidding Public Bids
• Reference Prices
• PNode Listing ( Existing Report)
• APNode Listing ( Existing Report)

Note: The ISO will schedule time on the SIUG call on April 6 and/or April 13 to discuss these technical documents with participants.

Design will parallel existing design for physical bids

Convergence Bidding – Upcoming Dates

• A proposed Market Simulation schedule has been created
• SIBR Testing
• IFM Testing
• Settlements Testing
• An Implementation Plan will be published on April 20
• Information on technical documentation
• Registration information for simulation and production
• To be discussed with participants at the April 27 Market Performance

and Planning Forum

• Settlements
• Configuration guides – target publication in September
• Market Simulation of settlements in December

Slide 41

Convergence Bidding – Additional Scope

• Three additional pieces of functionality have been incorporated into

the Convergence Bidding project

• E-tagging Requirements which extend the CRR settlement rule to physical

intertie schedules which are reversed in HASP

• Make-Whole provisions related to accepted convergence bids which are

rendered uneconomic due to a price correction

• OASIS reports to release aggregated cleared Convergence Bid MW quantities
• The E-Tagging and Make-Whole functionality will be incorporated in

the SaMC updates concurrent with CB implementation

• The Data Release functionality will be incorporated in the OASIS

updates concurrent with CB implementation

• BPM Updates, Procedure Updates and Training needs are being

evaluated

Slide 42

Participating Load Refinements (PLR)

Li Zhou

• Sr. Advisor, Program Office

Slide 43

PLR – Product Impacts

Slide 44

In general, PLR will increase the resource pool available for RUC and AS and provides comparable treatment of between supply-side and demand-side resources. Energy:

• Having additional demand resources participating in the CAISO Markets adds depth and liquidity

to the markets, which helps to address market power concerns. In addition, having demand resources bid at their location (through custom load aggregation) versus at the Default Load Aggregation Point, as does bundled load, enhances congestion management; RUC:

• Having demand resources participate in RUC will increase availability of RUC capacity and thus

enhance reliability; Ancillary service:

• Having PLR resources offering Spin Reserve, Non-spin Reserve and regulation services in both

day-ahead and real-time will increase availability of operating reserve capacity, enhancing reliability; Renewable Energy / Smart Grid:

• Having full PLR model in our market so to offer demand resources the full capability of generation

models is in line with the expectation of the renewable energy / Smart Grid initiative

PLR System Impacts

Slide 45

# System Impact 1 Master File Master File will be able to explicitly define a participating load resource as a different resource type from generation and load. Various PLR resource characteristics will need to be defined in Master File 2 SIBR Will need to provide bidding capability and relevant validation rules for the three parts bids for PLR resources along with the inter-temporal constraint parameters 3 ALFS Be able to exclude the PLR resource data from its system and zonal forecasts. 4 Day-ahead Market (MPM/RRD) Will need to be able to include PLR resources in the power balance consideration while not mitigating the PLR

• resources. Be able to observe the inter-temporal constraints unique to PLR resources.

5 Day-ahead Market (IFM) Co-optimize PLR bids with generation, inter-tie and non-participating load bids/schedules along with convergence bids, and be able to respect the inter-temporal constraints of PLR resources. 6 Day-ahead (RUC) Co-optimize PLR bids with generation, inter-tie and non-participating load bids/schedules, and be able to respect the inter-temporal constraints of PLR resources. 8 Real-time Market (MPM/RRD) Will need to be able to include PLR resources in the power balance consideration while not mitigating the PLR

• resources. Manual process shall include PLR resources. Be able to observe the inter-temporal constraints

unique to PLR resources. 9 Real-time Market (RTPD) Co-optimize PLR bids with generation, inter-tie and load forecast, and be able to respect the inter-temporal constraints of PLR resources. Be able to handle the ancillary services for PLR resources. 10 Real-time (RTD) Co-optimize PLR bids with generation, inter-tie and non-participating load and load forecast. Be able to dispatch PLR resources with associated energy, operation reserve services. Be able to respect the ramping and daily energy limit constraints for PLR resources. 11 Integration Enable PLR resource data to be communicated between ISO systems.

PLR System Impacts (continued)

Slide 46

# System Impact 12 SMDM and Network Application (NA) Be able to handle the PLR distribution as a custom LAP. Be able to handle the distribution when a custom LAP for a PLR is overlapping with another custom LAP or default LAP. Be able to derive the real-time load distribution factor based on state estimator solution or telemetry data provided by EMS. 13 EMS Be able to recognize both the dispatch and regulation on PLR resources. Be able to provide AGC signal to control

• PLRs. Be able to provide telemetry data of the PLR resources to market systems and settlement systems. Be

able to provide other PI data for regulation monitoring purpose. 14 SLIC Be able to allow de-rate of ramp-rate for PLR resources capable of providing ancillary service. Be able to allow de-rates or outage for PLR resources. 15 MQS Be able to calculate expected energy, commodity allocation, expected energy allocation for PLR resources. This requires algorithm to be able to recognize dispatch instructions on the load side. Be able to calculate commitment cost for PLR resources. Be able to provide other market corrections including DOP corrections. 16 Compliance and SaMC Be able to settle PLR resources differently from generation or non-participating load resources. Impacted areas include energy settlement, bid cost recovery, AS No Pay and regulation performance monitoring, neutrality calculation. 17 ADS Be able to report and communicate dispatch instructions and commitment instructions and real-time ancillary service capacity explicitly for PLR resources separate from generation, inter-tie resources. 18 CMRI (Report) New reports will show market cleared results for PLR resources separate from generations, inter-tie and loads. 19 OASIS (Report) Be able to provide aggregated reporting results on PLR resources. 20 OMAR/MDAS Be able to receive and manage individual Load meter for PLR resources for settlement purpose. 21 Credit Management Incorporate PLR market cleared results into calculation of the individual scheduling coordinator’s credit calculation.

PLR – Impact Assessment

Slide 47

BPM Changes The following BPM impacts are expected (Impact assessment = High/Medium/Low): Managing Full Network Model (High) SC Certification & Termination (Low) Congestion Revenue Rights (None) Rules of Conduct Administration (Low) Market Instruments (High) BPM Change Management (None) Outage Management (Medium) Definitions & Acronyms (Low) Reliability Requirement (Low) Settlements & Billing (High) Market Operations (High) Credit Management (Low) Compliance Monitoring (Medium) Candidate CRR Holder (None) Metering (Medium) Transmission Planning Process (None) Business Process Changes Business process changes will be evaluated as part of the requirements phase for PLR Client Training Materials External training will be provided as part of PLR implementation Operating Procedures TBD Market Simulation TBD Proposed Implementation Timeframe The base functionality is planned to be included in the Early 2011 release with deployment on 2/1/2011. The ISO is considering a phased approach that would incorporate changes in regulation and possibly other areas of functionality at a later date. Update of this approach will be provided later.

Release Planning – Project Update

Janet Morris Director, Program Office

Slide 48

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 Dec 23, 2009 Dec 24, 2009 Feb 2010 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 Mar 1, 2010 Mar 1, 2010 Mar 1, 2010 (registration) Go-Live Apr 15, 2010 On track Apr 1, 2010 On track Apr 1, 2010 On track May 1, 2010 On track

Slide 49

Milestone Multi-Stage Generator 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) Implementation Plan – Version 1 February 26, 2010 Settlement Configuration Guides April 20, 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 50

Slide 51

MSG Implementation Workshop – April 20, 2010

• Settlements configurations guides
• Physical trades on MSG resources
• Maximum number of transitions per day for MSG Resources
• Market simulation scenarios
• Other topics?

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 Q2 2010 Revised TBD Publish Business Requirements Dec 2, 2009 March 2010 On track Publish Technical Specifications March 31, 2010 On track Q2 2010 On track Implementation Guide Draft April 20,2010 On track Q3 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, 2010On track Q1, 2011On track

Slide 52

Slide 53

Market Simulation

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 Proposal10/02 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 Generation 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

Price Correction Make Whole Payments

Go Live Summer 2010

Transmission Constraint Data Release

Winter

2010

Standard Capacity Product Phase 2 (placeholder)

Go Live Summer 2010 Go Live 1/1/11 BOG review May 2010 BOG Approval 2/2010 BOG Approval 2/2010

Slide 54

BPM Change Management Process

• Open discussion