Market Performance and Planning Forum · Khaled Abdul-Rahman, George Angelidis, Li Zhou 12:15 –...

Market Performance and Planning

Forum

July 18, 2012

Objective: Enable dialogue on implementation

planning and market performance issues

• Review key market performance topics

• Share updates to 2012-2013 release plans, resulting

from stakeholders inputs

• Provide information on specific initiatives

– to support Market Participants in budget and resource

planning

• Focus on implementation planning; not on policy

• Clarify implementation timelines

• Discuss external impacts of implementation plans

• Launch joint implementation planning process

Slide 2

Agenda

Slide 3

10:00- 10:10 Introduction, Agenda Mercy Parker Helget

10:10 – 11:30 Market Analysis Mark Rothleder, Nan Liu

11:30 – 12:15 Technical Updates

SIBR Rules for fall release (including 72-hour RUC)

LMPM Enhancements Phase 2

Khaled Abdul-Rahman,

George Angelidis, Li Zhou

12:15 – 1:15 LUNCH

1:15 – 2:00 Release Updates

Technical specification and web service changes

for fall release

Training Update

Janet Morris, John Huetter,

Cindy Hinman

2:00 – 2:30 Policy Update Brad Cooper

Market Performance and Quality Update

Market Analysis & Development

Nan Liu

Guillermo Bautista-Alderete

Mark Rothleder

Slide 4

Slide 5

1. Market Metrics

• Price volatility and market convergence

• RT energy imbalance offset

• Convergence bidding

• Exceptional dispatch trends

• Bid cost recovery

• MIP gap

• LMPM

2. Price Corrections

3. Other Events

DLAP LMP Monthly Average:

Increase price divergence observed in May and June

Page 6

$0

$10

$20

$30

$40

$50

Jan

Feb

Mar

Ap

r

May Jun

Jul

Au

g

Sep

Oct

No

v

De

c

Jan

Feb

Mar

Ap

r

May Jun

2011 2012

Pri

ce (

$/M

Wh

)

PGE

IFM

HASP

RTD

$0

$10

$20

$30

$40

$50

Jan

Feb

Mar

Ap

r

May Jun

Jul

Au

g

Sep

Oct

No

v

De

c

Jan

Feb

Mar

Ap

r

May Jun

2011 2012

Pri

ce (

$/M

Wh

)

SCE

IFM

HASP

RTD

$0

$10

$20

$30

$40

$50

Jan

Feb

Mar

Ap

r

May Jun

Jul

Au

g

Sep

Oct

No

v

De

c

Jan

Feb

Mar

Ap

r

May Jun

2011 2012

Pri

ce (

$/M

Wh

)

SDGE

IFM

HASP

RTD

DLAP LMP Monthly Average (On Peak)

Page 7

$0

$10

$20

$30

$40

$50

$60

Jan

Feb

Mar

Ap

r

May Jun

Jul

Au

g

Sep

Oct

No

v

De

c

Jan

Feb

Mar

Ap

r

May Jun

2011 2012

Pri

ce (

$/M

Wh

)

PGE

IFM

HASP

RTD

$0

$10

$20

$30

$40

$50

$60

Jan

Feb

Mar

Ap

r

May Jun

Jul

Au

g

Sep

Oct

No

v

De

c

Jan

Feb

Mar

Ap

r

May Jun

2011 2012

Pri

ce (

$/M

Wh

)

SCE

IFM

HASP

RTD

$0

$10

$20

$30

$40

$50

$60

Jan

Feb

Mar

Ap

r

May Jun

Jul

Au

g

Sep

Oct

No

v

De

c

Jan

Feb

Mar

Ap

r

May Jun

2011 2012

Pri

ce (

$/M

Wh

)

SDGE

IFM

HASP

RTD

DLAP LMP Monthly Average (Off Peak)

Page 8

$0

$5

$10

$15

$20

$25

$30

$35

$40

Jan

Feb

Mar

Ap

r

May Jun

Jul

Au

g

Sep

Oct

No

v

De

c

Jan

Feb

Mar

Ap

r

May Jun

2011 2012

Pri

ce (

$/M

Wh

)

PGE

IFM

HASP

RTD

$0$5

$10$15$20$25$30$35$40$45

Jan

Feb

Mar

Ap

r

May Jun

Jul

Au

g

Sep

Oct

No

v

De

c

Jan

Feb

Mar

Ap

r

May Jun

2011 2012

Pri

ce (

$/M

Wh

)

SCE

IFM

HASP

RTD

$0

$5

$10

$15

$20

$25

$30

$35

$40

Jan

Feb

Mar

Ap

r

May Jun

Jul

Au

g

Sep

Oct

No

v

De

c

Jan

Feb

Mar

Ap

r

May Jun

2011 2012

Pri

ce (

$/M

Wh

)

SDGE

IFM

HASP

RTD

Monthly price distributions: price volatility increased in

May/June 2012.

Page 9

-10.0%

-8.0%

-6.0%

-4.0%

-2.0%

0.0%

2.0%

4.0%

JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC JAN FEB MAR APR MAY JUN

2011 2012

Pe

rce

nt

of

Re

al T

ime

In

terv

als

-$30 to -$5 -$100 to -$30 -$300 to -$100 < -300 $250 to < $500 $500 to < $750 $750 to $1000 > $1000

Monthly average of RTD intervals with insufficient up

ramping capacity also increased in May/June.

Page 10

0.00%

0.20%

0.40%

0.60%

0.80%

1.00%

1.20%

1.40%

1.60%

1.80%

2.00%

0

20

40

60

80

100

120

140

160

180

JAN

FEB

MA

R

AP

R

MA

Y

JUN

JUL

AU

G

SEP

OC

T

NO

V

DEC

JAN

FEB

MA

R

AP

R

MA

Y

JUN

2011 2012

Pe

rce

nt

of

Inte

rval

s

Co

un

t o

f In

terv

als

5-minute intervals with insufficient upward ramping capability

percent of intervals with insufficient upward ramping capability

Monthly average of RTD Intervals with insufficient

down ramping capacity increased too.

Page 11

0.00%

0.50%

1.00%

1.50%

2.00%

2.50%

3.00%

3.50%

4.00%

4.50%

5.00%

0

100

200

300

400

500JA

N

FEB

MA

R

AP

R

MA

Y

JUN

JUL

AU

G

SEP

OC

T

NO

V

DEC

JAN

FEB

MA

R

AP

R

MA

Y

JUN

2011 2012

Nu

mb

er

of

Inte

rval

s

5-minute intervals with insufficient downward ramping capability

percent of intervals with insufficient downward ramping capability

$0.00

$2.00

$4.00

$6.00

$8.00

$10.00

$12.00

$14.00

$16.00

$18.00

$20.00

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

$ M

illio

ns

Month

Real-Time Imbalance Energy Offset

Contribution from Balanced convergence bids within SCContribution from Offsetting Convergence Bids across SCsContributions from Other than Offsetting Convergence Bids

Offset costs ticked up in 2nd quarter due to increased

level of hour-ahead and real-time price divergence

Page 12

Slide 13

Flexi-ramp constraint cost decreased in June and July.

$0

$100,000

$200,000

$300,000

$400,000

$500,000

$600,000

$700,000D

ate

12

/18

/20

11

12

/24

/20

11

12

/30

/20

11

1/5

/20

12

1/1

1/2

01

2

1/1

7/2

01

2

1/2

3/2

01

2

1/2

9/2

01

2

2/4

/20

12

2/1

0/2

01

2

2/1

6/2

01

2

2/2

2/2

01

2

2/2

8/2

01

2

3/5

/20

12

3/1

1/2

01

2

3/1

7/2

01

2

3/2

3/2

01

2

3/2

9/2

01

2

4/4

/20

12

4/1

0/2

01

2

4/1

6/2

01

2

4/2

2/2

01

2

4/2

8/2

01

2

5/4

/20

12

5/1

0/2

01

2

5/1

6/2

01

2

5/2

2/2

01

2

5/2

8/2

01

2

6/3

/20

12

6/9

/20

12

6/1

5/2

01

2

6/2

1/2

01

2

6/2

7/2

01

2

7/3

/20

12

7/9

/20

12

Daily Flexi-Ramp Costs

Exceptional dispatch volume returned to more normal

lower levels in June.

Page 14

1 percent

Daily exceptional dispatches in MWh – by reason

Page 15

0

2

4

6

8

10

12

14

161-M

ay

3-M

ay

5-M

ay

7-M

ay

9-M

ay

11

-Ma

y

13-M

ay

15-M

ay

17-M

ay

19-M

ay

21-M

ay

23-M

ay

25-M

ay

27-M

ay

29-M

ay

31-M

ay

2-J

un

4-J

un

6-J

un

8-J

un

10-J

un

12-J

un

14-J

un

16-J

un

18-J

un

20-J

un

22

-Ju

n

24-J

un

26-J

un

28-J

un

30

-Ju

n

Th

ou

sa

nd

s M

Wh

Pe

r D

ay

T Procedure Transmission Outage Ramp RateGeneration Outage Software Limitation Load Forecast UncertaintyBridging Schedules G Procedure Other

Good MIP Gap performance in May/June.

Page 16

$0

$5,000

$10,000

$15,000

$20,000

$25,000

$30,000

$35,000

$40,000

$45,000

$50,000

Mip

Gap

($

)

Daily Dollar 30 Day Moving Average

Bid cost recovery also trending higher in April and May

but reduced in June.

Page 17

Note 1: Improved cross-day unit commitment decision process

0.00

2.00

4.00

6.00

8.00

10.00

12.00

14.00

16.00

18.00

20.00

Jan

-10

Feb

-10

Mar

-10

Ap

r-1

0

May

-10

Jun

-10

Jul-

10

Au

g-1

0

Sep

-10

Oct

-10

No

v-1

0

Dec

-10

Jan

-11

Feb

-11

Mar

-11

Ap

r-1

1

May

-11

Jun

-11

Jul-

11

Au

g-1

1

Sep

-11

Oct

-11

No

v-1

1

Dec

-11

Jan

-12

Feb

-12

Mar

-12

Ap

r-1

2

May

-12

Jun

-12

Co

st (

$M

illio

ns)

Bid Cost Recovery

IFM RT RUC

1

LMPM performance: will be discussed later during

Khaled/Jeff‟s presentation.

Page 18

Price corrections increase in April and June due to

planned maintenance.

Page 19

0.0%

0.2%

0.4%

0.6%

0.8%

1.0%

1.2%

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

2011 2012

Per

cen

tage

of

No

des

Co

rrec

ted

Data Input Software Tariff Process

A software data transfer issue on one day

caused the October increase

The set-up of a constraint on one

day caused 55% of the price

corrections in April

Slide 20

SONGS generators:

• Expect to be out through the summer.

Summer operations:

• All procedures and plans are in place for summer operations.

• New congestion due to interplay with neighboring balancing

authority area

Renewable Integration:

• Distributed generation report posted June 21, 2012

• http://www.caiso.com/Documents/FinalReport-Assessment-

Visibility-ControlOptions-DistributedEnergyResources.pdf

Other events

http://www.caiso.com/Documents/FinalReport-Assessment-Visibility-ControlOptions-DistributedEnergyResources.pdf









Technical Updates

Khaled Abdul-Rahman, Director

George Angelidis, Principal

Li Zhou, Senior Advisor

Power Systems Technology Development

Page 21

Non-Generator Resource (NGR) Updates

• NGR Expected Energy Algorithm and SIBR Rules

Published

• In both set of rules, a generalized feature is planned

beyond the base model (Fall 2012 Release),

-- GMIN : Min Capacity at NGR Generating Side. This is a

zero or positive number. For the base model, it is zero

and market participants can not register this value;

-- GMAX: Max Capacity at NGR Generating Side. This is

a positive number. For the base model, market

participants register this value to ISO‟s Master File as

Pmax of the NGR resource;

Slide 22

Non-Generator Resource (NGR) Updates …continue

-- LMIN: Min Capacity at NGR Load Side. This is a zero

or negative number. For the base model, it is zero and

market participants can not register this value;

-- LMAX: Max Capacity at NGR Load Side. This is a

negative number. For the base model, market

participants register this value to ISO‟s Master File as

Pmin of the NGR resource.

So, in Fall 2012 release,

Slide 23

Non-Generator Resource (NGR) Updates …continue

$/MWh

MW

Lmin, Lmax, Gmin and Gmax

Lmax

Lmin=Gmin=0

Gmax

Mandatory MSG (Spring 2013) -- ISO Plan

• Completion of MSG Enhancement Phase 3 project;

• Tariff Filing;

• Lessons learned from MSG owners;

• MSG reference document, including:

– How to complete the RDT for MSG resources

– How to submit SLIC outages for MSG resources

– Conversion from FOR to MSG

– References to MSG related information

• External training to be offered prior to the market

simulation scheduled for December 10-14, 2012

• Market notice providing an overview of MSG information,

training, and market simulation available

Slide 25

Overview: SIBR Rules for Fall 2012 Release

• Non-Generator Resource (NGR) Bidding Rules

• Multi-Day (72-hr RUC) Bid Generation Rules

• Multi-State Generation (MSG) Enhancements

• Greenhouse Gas Allowances in Proxy Bids

• On/Off-Peak Support for Regulatory Must Run/Take

(RMT) Resource Self-Schedules

• Price-Taker Market Exclusive Participation

• Cleanup and Clarifications

Slide 26

NGR Model

• New Resource class (dedicated rule flows)

• Continuous operating range:

– From Maximum Load (charge): Lmax

– To Maximum Generation (discharge): Gmax

• No inter-temporal constraints

• Energy and all Ancillary Services bids

– No support for AS self-provision, RA, RUC, or TOR/ETC

• Generating or Load Energy PT self-schedules

• Ramp Rate curve (up to two segments)

• Lower and Upper Charge Limits

Slide 27

NGR Modes of Operation: Load

$/MWh

MW

LSS

Load (charging) with SS

$/MWh

MW

Load (charging) without SS

NGR Modes of Operation: Generation

$/MWh

MW GSS

Generation (discharging) with SS

$/MWh

MW

Generation (discharging) without SS

NGR Modes of Operation: Continuous

$/MWh

MW

Load or Generation; no SS

Multi-Day (72-hr RUC) Bid Generation Rules

• Copy DAM Clean Bid for ELS Resources

– Insert PT SS at Pmin in TH with RUC Start-Up

• If Bid Fill Option is “History”

– Copy DAM Clean Bid from last similar Trading Day

• Copy Market Accepted Bid (7-day ahead)

• If Bid Fill Option is “Last”

– Copy Bid from previous Trading Day

• If Bid Fill Option is “No”

– No Generated Bid unless for RA

• If Market Fill Option is “No” or in Exception List

– Market bid prices replaced with proxy bid prices

Slide 31

MSG Enhancements – Phase 3

• DAM Self-Schedule Validation for State Group Inter-

Temporal Constraints

– A MSG may have multiple (nested) State Groups

– Minimum Group Up Time

• Includes on-state times for states inside the group

• Includes state transitions between states inside the

group

– Minimum Group Down Time

• Includes on-state times for states outside the

group

• Includes state transitions into and out of the group

Slide 32

Greenhouse Gas Allowances in Proxy Bids

• Greenhouse Gas Allowance adder ($/start) in Proxy

Start-Up Cost

– All segments (up to 3)

• Greenhouse Gas Allowance adder ($) in Proxy Minimum

Load Cost

– Unit adder ($/MWh) Pmin

• Greenhouse Gas Allowance adder ($/MWh) in Proxy

Energy Bid

– All segments (up to 10)

Slide 33

Other Changes

• RMT Self-Schedule Validation

– Against On/Off Peak registered maximum quantity

depending on Trading Hour

• Registered Energy Self-Schedule Resource

– Only self-schedule allowed

• Cleanup and Clarifications

– Removed support for ECA/ACA and Base SS

– Consolidated MSG Enhancements – Phase 2 from

Spring Release

Slide 34

Briefing on Local Market Power Mitigation Schedule

Delay

Page 35

• Presented to BOG July 12, 2012

– Background on LMPM Enhancements

– Phase 2 Implementation Challenges

– Delay to Spring 2012 Release

– Updated Schedule Milestones Provided under

Spring Release 2013 update for LMPM P2

Background on local market power mitigation

enhancements: …continue

• July 2011: Board approved new local market power mitigation

– Phase 1 (Implemented April 2012):

• Day-ahead and real-time mitigation triggered based on

decomposition of locational marginal price

• Dynamic competitive path assessment in day-ahead

– Phase 2 (Planned implementation Dec 2012):

• Dynamic competitive path assessment in real-time

• Perform mitigation hourly and 15 minutes in real-time

• February 2012: Briefed the Board on impact of using phased

approach for dynamic competitive assessment in real-time.

Slide 36

Local market power mitigation phase 2 implementation

challenges: …continue

• Phase 2 software implementation is more challenging:

– Performing mitigation every 15 minutes while

maintaining performance requirements is more

complex than day-ahead.

– Vendor requires additional time

– ISO requires sufficient time for testing and simulation

• Keeping local market power mitigation phase 2 in the

Fall release would risk delay of the remaining twelve Fall

release projects.

Slide 37

Phase 2 local market power mitigation is now scheduled

for the Spring 2013 release. …continue

• Delay is less than five months in coordination with the next

major scheduled release

• Real time congestion is less frequent in winter and early

spring months compared to summer

• ISO does not want to rush implementation and risk

insufficient testing of this important enhancement

Slide 38

Performance of LMPM Enhancements Phase I

Jeff McDonald, Ph.D.

Manager, Analysis and Mitigation

Department of Market Monitoring

Slide 39

Performance of RTM LMPM Enhancements Phase I

• Performance of LMPM in the real time market

– Accuracy of HASP in predicting RTD congestion.

– Comparison of path designations – current CPA v.

dynamic CPA.

– Resource bid mitigation under Phase I.

Slide 40

Accuracy of HASP in predicting RTD congestion

• Objective is to identify and mitigate local market power in

the 5-minute RTD market.

• Use HASP to do this 74 minutes in advance.

• Little “over-identification” of market power, however under-

prediction is high.

Slide 41

Cong Not Cong

Cong 43% 11%

Not Cong 46% OK

RTD

HA

SP M

PM

• Congestion parity.

• Percent of constraint-hours

where congested in either

HASP MPM or RTD.

• Apr 25 – Jul 13

Comparison of path designations – current CPA v.

dynamic CPA.

• 781 Constraint Hours.

• Current CPA 19% competitive

– Nearly all constraints are uncompetitive by default.

• Dynamic CPA 72% competitive

– Evaluates each constraint given conditions observed

when HASP MPM runs.

– Conditions observed in HASP MPM are not as

constrained as those observed in RTD…

Slide 42

Comparison of path designations – dynamic CPA in

HASP MPM v. RTD.

• Conditions typically more constrained in RTD.

– Competitive designation in HASP MPM often not

competitive in RTD.

• DCPA in HASP MPM rarely mis-identifies constraint as

uncompetitive.

Slide 43

• Designation parity.

• Percent of binding

constraint-hours.

• Compare only hours where

binding in both market runs.

• Apr 25 – Jul 13

Comp Non Comp

Comp 21% 53%

Non Comp 2% 25%

RTD

HA

SP M

PM

Resource bid mitigation under Phase I.

• Many resources “subject to mitigation” Positive non-

competitive congestion component.

• Bid mitigation does not reduce bid price at market dispatch

for 95% of these instances.

Slide 44

• Frequency (mitigated unit

hour) by price impact.

• Apr 25 – Jul 13

Resource Hours 66,346

Subject to Mitigation

DPRCbid

$0 95%

( $0 , -$5 ] 1%

( -$5 , -$25 ] 2%

( -$25 , -$50 ] 0%

( -$50 , -$100 ] 0%

< -$100 2%

Release Plan Updates

Janet Morris, Director Program Office

John Huetter, End to End System Integrator

Cindy Hinman, Lead Client Trainer

Page 45

Release Plan – 2012

• Fall 2012

• Non-Generator Resources / Regulation Energy Management - Phase 2

• Data Release Phase 3

• 72 Hour RUC

• Transmission Reliability Margin

• Commitment Costs Refinements - Greenhouse Gas Regulation only

• FERC 745 Net Benefits Test

• Contingency Dispatch Upgrade

• Regulatory Must Take Generation

• Replacement Requirement for Scheduled Generation Outages

• IRR enhancement

• December 2012

• MSG Enhancements Phase 3

• Market Simulation: Dec 10-14, 2012

• Deployment in Spring 2013 release

• DRS API

• Market Simulation: Dec 10-14, 2012

• Deployment TBD

Page 46

Release Plan – 2013

• Spring 2013

• MSG Phase 3 deployment

• DRS API deployment

• Dynamic Transfers

• FERC Order 755 – Pay for Performance

• LMPM Enhancements Phase 2

• Post Emergency Filing BCR changes / Mandatory MSG

• Access and Identity Management

• Master File Enhancements (no external impacts)

• Fall 2013

• Flexible Ramping Product

• RIMPR-Phase 1

• Circular Scheduling

• Commitment Cost Refinements (remaining scope)

• Subject to further release planning:

• Enhanced Operating Reserve Management

• Enterprise Model Management System

• Outage Management System (External BRS posted)

• Reliability Demand Response Product

• Subset of Hours

Page 47

2012 Release Plan

http://www.caiso.com/Documents/Plans%20and%20schedule/2012ReleasePlan.pdf

Milestone Associated project(s) Date

SIBR BR v5.0 NGR rules Posted

SIBR BR v5.1 RMT on/off peak self-schedule quantity Posted

SIBR BR v5.2 MSG Enhancements modifications Posted

SIBR BR v5.3* 72h RUC modifications Posted

SIBR BR v5.4* Green house gas and MSG group constraints Posted

Fall 2012 Release – SIBR Business Rules Revision Summary

Page 49

* Note: SIBR BR sets 5.3 and 5.4 may be revised beyond June 29, pending review with

software vendor and stakeholders

RDT Versioning

Generator GRDT 6.5 (and 6.5 in second row of RDT XLS file)

Intertie IRDT 4 (and 4.1 in second row of RDT XLS file)

Detailed in Technical Specifications to be posted July 23, 2012

Fall 2012 Release – RDT and API Versioning

Page 50

Fall 2012 Release – Web Service Changes

Page 51

• ADS

• New API version 5.0; version 3.1 will be deprecated.

• (Contingency Dispatch) Update to ADS APIWebService Web Service / API to accommodate updated DOT payload

• OASIS

• New API version 3.10, URL is not changing.

• (Data Release Phase 3) Update to OASISReport / API Web Service to accommodate query

of “Wind and Solar Forecasting Data” data

• (Data Release Phase 3) Update to OASISReport / API Web Service to accommodate query

of “CRR Public Bid Data” data

• (Data Release Phase 3) Update to OASIS OASISReport / API Web Service to accommodate query

of “Aggregated Generation Outage” data

• (Greenhouse Gas) Update to OASIS OASISReport / API Web Service to accommodate query

of “Average GHG Allowance Index Price” data

• SLIC

• New API version ID TBD

• (NGR-REM) Update to SLIC API External Web Services to accommodate updates/queries

of “NGR-REM” data

• MFRD

• (RMTG) Update to MFRD GeneratorRDT Web Service / API to accommodate updates/queries

of “Regulatory must take maximum (RMTMax)” data -- GeneratorRDT_v20121001

• (MLCA) Update to MFRD IntertieRDT Web Service / API to accommodate updates/queries

of “Marginal Loss Cost Adjustment” data -- IntertieRDT_v20121001

Milestone Date

Application Software Changes

SIBR: NGR as a generation resource

DAM/RTM: Model NGR with an negative to positive power injection

Settlements - Settle the NGR energy and AS similar as generator;

Master File: Define NGR resource characteristics and REM flag

SLIC: Support NGR register outage or de-rate ramp rates OASIS:

Include NGR for publishing T+90 bids,

EMS: Model NGR with supply range of negative to positive

BPM Changes Manage Full Network Model Market Operations

Market Instruments Outage Management

Settlements & Billing Compliance Monitoring

Business Process Changes May 31, 2012 - Expected Energy Calculations –PRR 563

External Business Requirements Update June 8, 2012

Configuration Guides July 31, 2012

Technical specifications July 23, 2012

Market Simulation registration conference call July 23, 2012

Market Simulation registration July 27, 2012

Updated BPM Sep 2012

Market Simulation Sep 4 – 21, 2012

Production Activation Dec 1, 2012

Fall 2012 Release – NGR Phase II: Non-Rem

Page 52

Milestone Date


CMRI: Release of Day-Ahead Load Distribution Factors, Release of

Shift Factors, Transmission Limits

OASIS: Release of Aggregated Generation Outages, Wind and Solar

Forecasts, & CRR Public Bids

BPM Changes Market Operations; Market Instruments

Business Process Changes None

Board Approval May 17, 2011

External Business Requirements March 19, 2012

NDAs Not required for Market Simulation, New NDA will be posted October

1, 2012 and returned by December 1, 2012

OASIS/ CMRI Technical Specifications July 31, 2012

Updated BPMs August 13, 2012

Market Simulation September 4 – 14, 2012

Tariff Filing / Approved Filing July 16, 2012 Approval Expected October 2012

Production Activation Trade Date December 11, 2012

Fall 2012 – Data Release (Phase 3)

Page 53

Milestone Date

Application Software Changes CMRI : Existing reports will publish extra long start unit

binding startup instructions / initial condition

BPM Changes Market Operations

Market Instruments

Business Process Changes Not Applicable

External Business Requirements September 23, 2010 and September 1, 2011

(BPM synch revision)

Technical Specifications Not Applicable

Updated BPMs October 28, 2011

Market Simulation Plan to include Implementation

Plan July 30, 2012

Market Simulation September 10-14


Fall 2012 – 72 Hour RUC

Page 54

Milestone Date

Application Software Changes OASIS – CBM line item replaced, three TRM component line items added.

BPM Changes Market Instruments, Market Operations, Full Network Model (TBD),

Reliability Requirements (TBD), Congestion Revenue Rights (TBD)

Business Process Changes Manage Real-Time Interchange Scheduling

Board Approval March 22, 2012

External Business Requirements April 9, 2012

Technical Specifications July 31, 2012

Updated BPMs July 31, 2012

Market Simulation September 11, 2012- September 17, 2012

Tariff Filing / Approved April 2012 / June 2012


Fall 2012 – Transmission Reliability Margin

Page 55

Milestone Date


Master File: Two new modifiable fields in the Generator RDT.

• A yes / no flag to indicate whether a resource has a Greenhouse gas (GHG)

compliance obligation

• GHG emission rate / factor for resources that have a GHG compliance obligation

SIBR: (CAISO internal) Changes to calculation of Generated Bids, Startup (SU)

and Minimum Load (ML) Costs for resources that have a GHG compliance

obligation.

OASIS: A new report to show the GHG Allowance index price used in the

calculation of proxy SU and ML costs as well in the default energy bids and

generated bids.


Business Process Changes No business process impacts

Board Approval May, 2012

External Business Requirements June 29, 2012

Market Simulation Fall 2012

Technical Specifications July 23, 2012 (Master File Generator Data API)

Tariff Filing July 18, 2012

Production Activation Trade Date January 1, 2013

Fall 2012 – Commitment Cost Refinements (Green House

Gas Emissions Costs)

Page 56

Fall 2012 Release - FERC Order 745 DR Compensation in Wholesale Electricity Markets

Milestone Date


Demand Response System (DRS): 6/26 - No longer impacted.

Settlements

• Automation of the calculation of the Monthly Demand Response DR

Net Benefits test (NBT) Threshold Prices.

• Change Settlement Charge Codes (RT Energy Pre-Calc, CC6806,

CC6475, CC6477) to comply with guidance issued in FERC order

745

BPM Changes Market Operations, Settlement Configuration Guides, Definitions and

Acronyms

Updated External Business Requirement

Specification June 6, 2012


Configuration Guides Aug 27, 2012 – CC6806, CC6475, CC6477, RT Energy Pre-Calculation

Market Simulation Sep 25-26, 2012

Production Deployment Nov 5, 2012


Retroactive settlement dating back to effective trade date Dec 15, 2011

Page 57

Milestone Date


RTM: Prioritize Operating reserves dispatch over energy-only during

Disturbance Control Standard (DCS) event

ADS:

• Always broadcast the Dispatch when it is coming from Real-Time

Contingency Dispatch (RTCD).

• Two new fields to indicate

RTCD was a Disturbance Dispatch (Prioritized Operating

Reserves over energy-only bids)

Incrementing the Northern Ties was skipped

Incrementing Southern Ties was skipped


Business Process Changes Manage Real-Time Contingency Dispatch


External Business Requirements May 8, 2012

Updated BPMs RTCD-6/15/12 (Complete), RTDD-8/17/12

Tariff Filing / Approved Filing July 2012 requesting FERC approval by Oct 2012

Technical Specifications July 23, 2012 (ADS.caiso.com API)

Note: Will include ADS screen-shots

Market Simulation September 17 – September 21, 2012

Production Activation RTCD-11/5/12, RTDD-12/11/12

Fall 2012 – Contingency Dispatch Upgrade

Page 58

Milestone Description/Date


Master File: Allow SCs of Combined Heat and Power (CHP) resources to view

On-peak and off-peak regulatory must take maximum (RMTmax) values along

with their expiration dates via generator Resource data template (GRDT). For

CHP resources, RMTMax values must be within Pmin and Pmax and must be

renewed at least once every 12 months.

SIBR: Change validation rules to only allow self-scheduling priority up to the

resource‟s RMTMax value for on-peak and off-peak hours. Current validation is

to allow self-schedule priority up to Pmax.

BPM Changes

Market Operations and Market Instruments

Business Process Changes Potential new business process to • Manage contracts and approval of a CHP resource for RMT

External Business Requirements April 30, 2012 (updated June 26, 2012)


Technical Specifications July 23, 2012 (Master File Generator Data API)

Tariff Filing July 2012

Market Simulation September 11, 2012- September 17, 2012

Production Activation Trade date December 11, 2012

Fall 2012 – Regulatory Must Take Generation

Page 59

Milestone Date


SLIC/IRR:

1. Add attribute to flag resource as RA. Need new screen in Outage System (SLIC). 2. Each RA resource should be designated as local or system. That information should be obtained from IRR or RAAM. May be done manually.

BPM Changes Outage Management; Reliability Requirements

Business Process Changes

• Manage Generation Outages:

• Annual Monthly RA Process (new)

• RA Outage Management Process (new)

• Reliability Requirements

• Bulletin Board (new) - online forum where market participants list/identify potential

replacement RA capacity during cure period or for forced outages within the month.

LSEs who submit “non-designated RA” can be listed on a bulletin board and

parties may sell this capacity for replacement RA capacity for 1 day to 31 days of

the month. Bulletin Board is open to non-designated RA capacity and generation

capacity not under an RA contract. ISO will evaluate all available resources (using

same criteria as CPM) when seeking short-term RA replacement capacity.

Board Approval July 12, 2012

External Business Requirements July 13, 2012

Technical Specifications July 31, 2012

Market Simulation September 17 – September 21, 2012

Tariff Filing Around the end of July 2012

Production Activation October 15, 2012

Fall 2012 – Replacement Requirements for Scheduled

Generation Outages

Page 60

Milestone Date

Application Software Changes IRR: Modifications to enable annual automated cross validation and

loading of supply and RA plans

BPM Changes Reliability Requirements

Business Process Changes No business process impacts

Board Approval Not Applicable

IRR Users Guide August 20, 2012

Market Simulation September 10 – 14


Tariff Filing Not Applicable

Production Activation Trade Date Oct,1 2012

Fall 2012 – IRR (ISO Reliability Requirements) Annual

Page 61

Milestone Date


Master File: System must be extended to allow the registration of minimum

up time (MUT) or minimum down time (MDT) on a group of MSG

configurations. Registrations would be submitted to the ISO via a separate

registration form.

DAM/RTM: System must be able to recognize the MUT and MDT constraints

on a group of configurations (as registered in the Master File) during the

optimization.

BPM Changes Market Instruments, Market Operations

Business Process Changes Not Applicable

Board Approval Not Applicable

External Business Requirements June 15, 2012 (updates made to document)

Registration Form Draft Available 7/13/12 (subject to change before Market Simulation)

Market Simulation December 10 – December 14, 2012

Tariff Filing Not Applicable

Production Activation Spring 2013

Spring 2013 – MSG Enhancements (Phase 3)

Page 62



SIBR: Pass the 5-min-2-hour rolling forward forecast to Real-Time Market,

including bidding capability and relevant validation rules for the TRC.

ALFS : Create the ISO forecast for the intermittent DT

CAS: e-tag DS/PTG that mapped to multi-ITGs

CMRI : Report Transmission Reservation (TRC)

DAM/RTM: Include TRC, incorporate forecast value, model multi-tie services,

model primary/alternative tie under open tie

Master File: Define TRC, multi-tie group

OASIS: Show aggregated TRC

Settlements: Settle TRC as shadow price of Intertie constraint in market,

exclude congestion cost in RTD for the resources that have TRC.

BPM Changes

Market Operations; Market Instruments;

Settlements & Billing; Definitions & Acronyms

Business Process Changes Maintain Master File, Day Ahead Process, Real Time Process, Manage Billing

and Settlements, Manage Interchange Scheduling



Technical Specifications TBD

Market Simulation Spring 2013

Production Activation Spring 2013 Release

Spring 2013 – Dynamic Transfers

Page 63



ADS: provide DA regulation up/down mileage awards

CMRI : provide DA and RT regulation up/down mileage price and awards

DAM/RTM: include mileage bids and requirements into the optimization and

generate mileage price and awards

Master File: regulation certification based on 10 min ramping capability

OASIS: provide DA regulation up/down mileage price, system mileage

multipliers, system mileage requirement, actual system mileage, historical

mileage bids, historical resource mileage multipliers

Settlements : calculate mileage payment, mileage cost allocation and GMC

for mileage bids

SIBR: receive and validate regulation up/down mileage bid

BPM Changes Market Operations Market Instruments

Settlements & Billing Definitions & Acronyms

Business Process Changes

Maintain Master File, Day Ahead Process

Manage Billing and Settlements, Manage Analysis Dispute and Resolution,

Market Performance (MAD),Market Performance (DMM)

Manage AS Certification and Testing




Compliance Filing April 2012

Product Activation 2013 Spring Release

Spring 2013 – FERC Order 755 Impact Assessment

Page 64

Milestone Date


Real-Time Market: MPM for 15 min. DCPA for HASP and 15 min.

OASIS: Display LMPM-related components for nomogram & intertie

shadow prices, and competitive paths for real-time

CMRI : Display real-time mitigated bid curve


Market Instruments

Business Process Changes Real Time Market & Grid

Manage Real Time Market- After Close of Market

Manage Real Time Operations- Generation Dispatch

Board Approval July 14, 2011

External Business Requirements August 2012

OASIS/ CMRI Technical Specifications December 2012

Updated BPMs December 2012

Market Simulation February 2013

Tariff Filing / Approved Filing in November, FERC Approval TBD

Production Activation Spring Release 2013 (tentative May 2013)

Spring 2013 – LMPM Enhancements (Phase 2)

Page 65

Milestone Date


Master File: Additional MSG Configurations need to completed by Spring

Release 2013.

Reporting: A Breakdown of BCR Components will be added to the Monthly

Market Report.

SAMC: Requires a tune-up on formulas to determine the ON criteria for

resources, and the eligibility for Bid Cost Recovery.

BPM Changes Market Instruments; Market Operations; Settlements & Billing

Business Process Changes N/A

Board Approval Feb 16, 2012

External Business Requirements N/A

Updated BPMs TBD

Market Simulation TBD

Tariff Filing / Approved TBD

Production Activation Spring 2013

Spring 2013 - Post Emergency BCR Filing / Mandatory MSG

Page 66

Milestone Date


The goal of the AIM project is to improve upon the existing approach for

establishing, updating and terminating access to applications as well as

providing visibility (transparency), ease of use and self-service where

appropriate to POCs (Points of Contact), internal ISO users, business units

and IT to manage this process from end to end.

AIM: New system with UI and workflow

CIDI: Provides POC data to AIM

BPM Changes Congestion Revenue Rights; SC Certification and Termination; Candidate

CRR Holder; Definitions and Acronyms

Business Process Changes IT Access Mgmt. - Certificate based application access; Metering systems

access

Board Approval N/A

External Business Requirements TBD

Updated BPMs TBD


Tariff Filing / Approved N/A

Production Activation Spring 2013 Release (Tentative)

Spring 2013 – Access and Identity Management (AIM)

Page 67



ADS: Send Flexible Ramping Up/Down Awards to Market Participants.

CMRI : Report Flex Ramp Up/Down Awards to Market Participants.

DAM/RTM: Co-optimize Energy Ancillary Services and Flexible Ramping

up/down. This optimization is subject to Flexible Ramping requirements and

existing constraints.

OASIS: Show aggregated Flexible Ramping capacity awards, requirements and

marginal prices.

Settlements: Settle Flexible Ramping payment at marginal price in Day Ahead

and Real Time markets Add no pay and cost allocation for Flexible Ramping.

SIBR: Include Flexible Ramping bidding capability and relevant validation rules

of bid cap, self provision.

BPM Changes Market Operations; Market Instruments; Settlements & Billing; Definitions &

Acronyms.

Business Process Changes Maintain Day Ahead Process, Real Time Process, Manage Billing and

Settlements



Board Approval November 2012


Production Activation Fall 2013 Release

Fall 2013 – Flexible Ramping Product

Page 68

Milestone Date


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:

• 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.

BPM Changes Settlements & Billing, Market Operation

Business Process Changes Manage Billing and Settlements, Market Performance

Board Approval Bid Floor and BCR netting: December 15-16, 2011

BCR Mitigation Measures: September, 2012


Updated BPMs TBD



Production Activation Fall 2013

Fall 2013 – RIMPR Phase 1

Page 69

Milestone Date


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



Updated BPMs TBD



Production Activation Fall, 2013

Fall 2013 – Circular Scheduling

Page 70

Milestone Date


Masterfile: Creation of new field to capture resource specific characteristics.

Settlements: Operational Flow Orders, NOx, and Sox penalties must be

submitted ex post under circumstances attributable to exceptional dispatch

and real-time commitments. These costs will be included in a re-evaluation

of the real-time BCR calculation for that day with the Operational Flow

Orders (OFO) costs added into the calculation of the generator‟s net shortfall

or surplus over that day. Must establish an interface in which Market

Participants can enter data to flow directly to Settlements.

BPM Changes Market Instruments

Billing & Settlements

Business Process Changes Manage Reliability Requirements

Board Approval May 2012


Updated BPMs TBD



Production Activation Fall 2013 Release

Fall 2013 – Commitment Cost Refinement

Page 71

Upcoming ISO Training Offerings

Date Training

July 26 Welcome to the ISO (teleconference/webex)

August 1, 2 SC Certification Training (on-site)

August 23 Welcome to the ISO (teleconference/webex)

Page 72

Training calendar - http://www.caiso.com/participate/Pages/Training/default.aspx

Contact us - [email protected]

http://www.caiso.com/participate/Pages/Training/default.aspx

mailto:[email protected]

Policy Update

Brad Cooper, Manager

Market Design and Regulatory Policy

Slide 73

Market initiatives going to the Board for approval in

Sep, Nov 2012

Initiative Board Presentation

BCR Mitigation Meas. (RIMPR 1) Sep

Intertie Pricing and Settlement Sep

Flex Capacity Procurement Phase 1

(Risk of Retirement)

Sep

FERC Order 1000 Sep

Generator Project Downsizing Sep

Price Inconsistency Market

Enhancements

Sep

Flexible Ramping Product Nov

Exceptional Dispatch Mitigation in Real

Time

Nov

Page 74

Market design initiatives coming soon (slide 1 of 2)

• Administrative Pricing Rules

– Starting July 25, 2012

• Exceptional Dispatch Mitigation in Real Time

– Issue paper/straw proposal published July 20, 2012

• FERC VERS Order Compliance

– Targeted to start Q3 2012

• Flexible Capacity Requirements/Procurement - Phase II

– Targeted to start Sep 2012

• PIRP Decremental Bidding


Page 75

Market design initiatives coming soon (slide 2 of 2)

• Cost-Allocation Guiding Principles - Phase 2: Apply

Principles Across Market Design


• Standard Capacity Product Phase III

– FERC order to apply SCP to all RA resources

• Phase III will evaluate SCP for DR


• Marginal Loss Surplus Allocation


Page 76

ISO Will Delay the RDRR Stakeholder Initiative

• A final verdict from the DC Circuit Court of Appeals on the

Order 745 appeal will bring certainty to disputed

compensation issues;

• ISO is concerned about implementing RDRR compliant

with Order 745 at a time when the sustainability and

applicability of the Order is under court review; and

• Desire to fix DR compensation once and for all under a

single, durable settlement solution- both PDR and RDRR.

Page 77

Reliability Demand Response Resources Initiative

Jul

Proposed

Launch

of RDRR

Initiative

Apr-Jun

2013

Verdict Rendered

on Appeal of

Order 745

Nov „12

Board

Approval of

RDRR

changes

compliant with

Order 745

Feb „13

FERC

Approval of

RDRR Tariff

Amendments

Aug 28th

FERC Reply

to Opening

Briefs

Dec

Oral

Arguments

Order 745 Appeal Process

Original RDRR Stakeholder Initiative Schedule

Apr „13

Implement

RDRR

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