Market Performance and Planning Forum...Market Performance and Planning Forum May 11, 2011....

Market Performance and Planning

Forum

May 11, 2011

Objective: Enable dialogue on implementation

planning and market performance issues

• Review key market performance topics

• Share updates to 2011-2012 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 PRESENTER9:00 -9:15 Overview, Objectives Mercy Parker Helget

9:15-11:00 Market Performance and Quality Update Mark Rothleder

11:00-11:30 Policy Update Greg Cook

11:30 – 12:00 Technical Update

- MSG

- LMPM Enhancements Impact Assessment

Li Zhou

12:00 –1:00 Lunch – all are welcome to use the new ISO cafeteria

1:00 – 2:30

2:30 – 3:00

Release Plan Update

- Pre-Summer 2011 Releases

- Fall 2011 Release

- Generation of Bids for NRS-RA / Subset of Hours

- GMC Rate Structure Change

- Regulation Energy Management

- SLIC to SIBR Interface

Ongoing Data Release

Outage Management System – Phase 3

Janet Morris

Jami Long

Market Performance and Quality Update

Mark Rothleder, Director

Market Analysis & Development

Slide 4

Price volatility and market convergence

MIP Gap performance

Convergence Bidding

RT Energy Offset

MSG (There are currently 15 MSG resources)

Exceptional Dispatch

Bid Cost Recovery

Price volatility and market convergence (1)

Slide 6

0.0%

0.5%

1.0%

1.5%

2.0%

2.5%

3.0%

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

2010 2011

Pe

rce

nt

of

real

-tim

e in

terv

als

$250 to $500 $501 to $750 $751 to $1000 > $1000

$500 bid cap $750 bid cap

Price volatility and market convergence (2)

Slide 7

$0

$10

$20

$30

$40

$50

$60

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

2010 2011

Pri

ce ($

/MW

h)

Day-ahead Hour-ahead Real-Time

In March additional actions taken improve convergence

of conditions between the HASP and RTD prices.

Slide 8

0

0.5

1

1.5

2

2.5

3

$0

$1

$2

$3

$4

$5

$6

$7

$8

$9

$10

3/2

/20

11

3/4

/20

11

3/6

/20

11

3/8

/20

11

3/1

0/2

01

1

3/1

2/2

01

1

3/1

4/2

01

1

3/1

6/2

01

1

3/1

8/2

01

1

3/2

0/2

01

1

3/2

2/2

01

1

3/2

4/2

01

1

3/2

6/2

01

1

3/2

8/2

01

1

3/3

0/2

01

1

4/1

/20

11

4/3

/20

11

4/5

/20

11

4/7

/20

11

4/9

/20

11

4/1

1/2

01

1

4/1

3/2

01

1

4/1

5/2

01

1

4/1

7/2

01

1

4/1

9/2

01

1

4/2

1/2

01

1

4/2

3/2

01

1

4/2

5/2

01

1

4/2

7/2

01

1

4/2

9/2

01

1

5/1

/20

11

5/3

/20

11

5/5

/20

11

Ave

rage

Nu

mb

er o

f Sp

ike/

Day

Ave

rge

HA

SP-R

T P

rice

Dif

fere

nce

($/M

wh

)

30-Day Rolling Average Price Volatility and HASP/RTD Price Differences

HASP - RTD Price Difference Number of Price Spikes (>$500)

Actions taken to improve HASP and RTD imbalance

conditions. (1)

Slide 9

Software:

• Intertie ramp profile data issue resolved May 2, 2011

3,500

3,550

3,600

3,650

3,700

3,750

3,800

3,850

3,900

7:20:00 7:25:00 7:30:00 7:35:00 7:40:00 7:45:00 7:50:00 7:55:00 8:00:00 8:05:00 8:10:00 8:15:00 8:20:00 8:25:00 8:30:00 8:35:00 8:40:00 8:45:00 8:50:00

Net

Impo

rt (m

W)

Time

Example of Interchange Ramp

Ramp Error Correct Error


conditions. (2)

Slide 10

Software:

• Variable resource’s expected delivery were reverting to schedule

instead of telemetry mid-hour (issue started April 12, resolved April 19)


conditions.

Slide 11

HASP Forecast Adjustment

• Adjust HASP load during load pull and drop by approximately 25% of

load change

• Adjust HASP load by approximately 2% of raw forecast across peaks

• Use maximum of 5 minute load within 15 minute interval

RTD Imbalance Adjustment

• Adjusted imbalance to account resource shutdown profile instead of

instantaneous shutdown

Other contributing factor to price HASP / RTD price

divergence.

Slide 12

• Deviations of resources

• Intertie schedules not being tagged

• Resources not position to provide maximum ramp capability

MIP Gap performance

Slide 13

• Bid cap raised to $1000 on April 1.

• MIP gap tolerance (%) reduced in anticipation of bid cap increase.

• Small increase in optimization objective function cost due to bid cap

increase, mitigated by reduction in % tolerance.

Increase in optimization objective function cost due to

bid cap increase.

Slide 14

$0

$5,000,000

$10,000,000

$15,000,000

$20,000,000

$25,000,000

$30,000,000

$35,000,000

12/8/2010 12/28/2010 1/17/2011 2/6/2011 2/26/2011 3/18/2011 4/7/2011 4/27/2011 5/17/2011

Ob

jecti

ve C

ost

Date

Series1

Bid Cap increased to $1000 on April 1, 2011

Reduced MIP Gap tolerance to 0.02% in anticipation of

bid cap increase on April 1, 2011.

Slide 15

-0.20%

0.00%

0.20%

0.40%

0.60%

0.80%

1.00%

1.20%

12/8/2010 12/28/2010 1/17/2011 2/6/2011 2/26/2011 3/18/2011 4/7/2011 4/27/2011 5/17/2011

MIP

Gap

%

Series1In response to higher

objective cost reduced MIP

Gap tolerance in IFM to

maintain high quality solution

Average absolute MIP Gap tolerance less than $2,000

since April 1, 2011.

Slide 16

-$10,000

$0

$10,000

$20,000

$30,000

$40,000

$50,000

8/15

/200

9

9/4/

2009

9/24

/200

9

10

/14

/20

09

11/3

/200

9

11/2

3/20

09

12

/13

/20

09

1/2/

2010

1/22

/201

0

2/11

/201

0

3/3/

2010

3/23

/201

0

4/12

/201

0

5/2/

2010

5/22

/201

0

6/11

/201

0

7/1/

2010

7/21

/201

0

8/10

/201

0

8/30

/201

0

9/19

/201

0

10/9

/201

0

10

/29

/20

10

11

/18

/20

10

12/8

/201

0

12/2

8/20

10

1/17

/201

1

2/6/

2011

2/26

/201

1

3/18

/201

1

4/7/

2011

4/27

/201

1

5/17

/201

1

6/6/

2011

MIP

Gap

($

)

Day

MIP Gap ($ difference)

Series1 30 per. Mov. Avg. (Series1)

10-Day Moving Average of Cleared Convergence Bids

Slide 17

10-Day moving average of cleared convergence bids for

internal nodes

Slide 18

10-Day moving average of cleared convergence bids for

interties

Slide 19

10-Day moving average of daily profits/losses

Slide 20

10-Day moving average of daily profits/losses for

internal nodes

Slide 21

10-Day moving average of daily profits/losses for

interties

Slide 22

Convergence among Day-Ahead, Hour-Ahead, and

Real-Time Dispatch prices is expected to develop as

market participants gain experience with CB.

Slide 23

-30

-20

-10

0

10

20

30

40

50

2/1

/11 0

:00

2/4

/11 0

:00

2/7

/11 0

:00

2/1

0/1

1 0

:00

2/1

3/1

1 0

:00

2/1

6/1

1 0

:00

2/1

9/1

1 0

:00

2/2

2/1

1 0

:00

2/2

5/1

1 0

:00

2/2

8/1

1 0

:00

3/3

/11 0

:00

3/6

/11 0

:00

3/9

/11 0

:00

3/1

2/1

1 0

:00

3/1

5/1

1 0

:00

3/1

8/1

1 0

:00

3/2

1/1

1 0

:00

3/2

4/1

1 0

:00

3/2

7/1

1 0

:00

3/3

0/1

1 0

:00

4/2

/11 0

:00

4/5

/11 0

:00

4/8

/11 0

:00

4/1

1/1

1 0

:00

4/1

4/1

1 0

:00

4/1

7/1

1 0

:00

4/2

0/1

1 0

:00

4/2

3/1

1 0

:00

4/2

6/1

1 0

:00

4/2

9/1

1 0

:00

$/M

Wh

Hour Ending

RTD - DA HASP - DA RTD - HASP

Awarded RUC capacity has been low on days with net

virtual demand & up to 5% of daily demand for net virtual

supply, and uses mostly Resource Adequacy resources

Slide 24

0.0%

1.0%

2.0%

3.0%

4.0%

5.0%

6.0%

Fe

b 1

Fe

b 5

Fe

b 9

Fe

b 1

3

Fe

b 1

7

Fe

b 2

1

Fe

b 2

5

Ma

r 1

Ma

r 5

Ma

r 9

Ma

r 13

Ma

r 17

Ma

r 21

Ma

r 25

Ma

r 29

Ap

r 2

Ap

r 6

Ap

r 10

Ap

r 14

Ap

r 18

Ap

r 22

Ap

r 26

Ap

r 30

% o

f S

yste

m L

oa

d

RA RUC Capacity Non-RA RUC Capacity

ANode vs. APNode LMPs for NP15 Trading Hub:

2/1/2011 – 4/29/2011.

Slide 25

-20

-10

0

10

20

30

40

50

60

70

-10

0

10

20

30

40

50

60

70

80

90

2/1

/11

2/4

/11

2/7

/11

2/1

0/1

1

2/1

3/1

1

2/1

6/1

1

2/1

9/1

1

2/2

2/1

1

2/2

5/1

1

2/2

8/1

1

3/3

/11

3/6

/11

3/9

/11

3/1

2/1

1

3/1

5/1

1

3/1

8/1

1

3/2

1/1

1

3/2

4/1

1

3/2

7/1

1

3/3

0/1

1

4/2

/11

4/5

/11

4/8

/11

4/1

1/1

1

4/1

4/1

1

4/1

7/1

1

4/2

0/1

1

4/2

3/1

1

4/2

6/1

1

4/2

9/1

1

Dif

fere

nc

e ($

/MW

h)

$/M

Wh

Hour Ending

NP15 ANode LMP NP15 APNode LMP Difference

Observed instances of larger

differences due to error in a

distribution factor. Resolved

March 1, 2011

Smaller observed differences

result of disconnected nodes

and Point of Delivery

Convergence Bidding affect on physical ties

• LMP could be off awarded bid curve when physical

congestion is binding

• Stakeholder process underway

• Two options were presented

• Option one is preferred

– separate physical and virtual prices when physical

only constraint is binding

• Observe approximately $250,000/month LMP vs bid

shortfall to exports

• Observe offsetting higher LMP payment to imports

Real-time Energy Offset

$0

$2,000,000

$4,000,000

$6,000,000

$8,000,000

$10,000,000

$12,000,000

$14,000,000

$16,000,000

$18,000,000

$20,000,0003

/2/2

01

1

3/9

/20

11

3/1

6/2

01

1

3/2

3/2

01

1

3/3

0/2

01

1

4/6

/20

11

4/1

3/2

01

1

4/2

0/2

01

1

4/2

7/2

01

1

5/4

/20

11

Co

ntr

ibu

tio

n t

o R

eal

-Tim

e E

ne

rgy

Off

set

($)

Date

30-Day Rolling Cummulative(Based on HASP, RT System Marginal Energy Cost)

SC Balanced Virtual Residual Balanced Virtual across SCs

Real-time Energy Offset (cont.)

0

200,000

400,000

600,000

800,000

1,000,000

1,200,000

1,400,000

1,600,000

1,800,000

2,000,000

3/2

/20

11

3/9

/20

11

3/1

6/2

01

1

3/2

3/2

01

1

3/3

0/2

01

1

4/6

/20

11

4/1

3/2

01

1

4/2

0/2

01

1

4/2

7/2

01

1

5/4

/20

11V

olu

me

of

Bal

ance

d V

irtu

al (

MW

)

Date

30-Day Rolling Cummulative(Volume of balanced offsetting virtual intertie supply

and virtual internal demand)

SC Balanced Virtual Residual Balanced Virtual across SCs

Real-time Energy Offset (cont.)

$0

$2,000,000

$4,000,000

$6,000,000

$8,000,000

$10,000,000

$12,000,000

$14,000,000

$16,000,000

$18,000,000

$20,000,000

Feb-2011 March-2011 April-2011

Real-

Tim

e E

nerg

y O

ffset

($)

Date

Monthly Real-Time Energy Offset

Total RT Energy Offset

Attributable to Virtual Bids (Based on balaned virtual import and internal virtual demand and SMEC)

MSG – Configuration change from day-ahead self-

scheduled

-20%

0%

20%

40%

60%

80%

100%

120%

1/1

/19

00

1/5

/19

00

1/9

/19

00

1/1

3/1

90

0

1/1

7/1

90

0

1/2

1/1

90

0

1/25

/190

0

1/2

9/1

90

0

2/2

/19

00

2/6

/19

00

2/10

/190

0

2/1

4/1

90

0

2/18

/190

0

2/2

2/1

90

0

2/26

/190

0

3/1

/19

00

3/5

/19

00

3/9

/19

00

3/13

/190

0

3/1

7/1

90

0

3/2

1/1

90

0

3/2

5/1

90

0

3/2

9/1

90

0

4/2

/19

00

4/6

/19

00

4/10

/190

0

4/1

4/1

90

0

4/18

/190

0

4/2

2/1

90

0

4/26

/190

0

4/3

0/1

90

0

5/4

/19

00

5/8

/19

00

5/12

/190

0

5/1

6/1

90

0

5/20

/190

0

Pe

rce

nt

of

Un

it H

ou

rs

Date

Day-Ahead Clearing in Different Configuration Than Self -Schedule

Pct of unit- hours cleared in different configration than self -scheduled

10 per. Mov. Avg. (Pct of unit - hours cleared in different configration than self -scheduled)

MSG – Real-Time configuration change from

day-ahead or self-scheduled

0%

5%

10%

15%

20%

25%

30%

35%

40%

1/1/

1900

1/4/

1900

1/7/

1900

1/1

0/1

90

0

1/1

3/1

90

0

1/16

/190

0

1/1

9/1

90

0

1/2

2/1

90

0

1/2

5/1

90

0

1/2

8/1

90

0

1/31

/190

0

2/3/

1900

2/6/

1900

2/9/

1900

2/1

2/1

90

0

2/15

/190

0

2/1

8/1

90

0

2/2

1/1

90

0

2/24

/190

0

2/2

7/1

90

0

3/1/

1900

3/4/

1900

3/7/

1900

3/10

/190

0

3/1

3/1

90

0

3/16

/190

0

3/1

9/1

90

0

3/2

2/1

90

0

3/25

/190

0

3/2

8/1

90

0

3/31

/190

0

4/3/

1900

4/6/

1900

4/9/

1900

4/1

2/1

90

0

4/15

/190

0

4/1

8/1

90

0

4/2

1/1

90

0

4/24

/190

0

4/2

7/1

90

0

4/30

/190

0

5/3/

1900

5/6/

1900

5/9/

1900

5/1

2/1

90

0

5/15

/190

0

5/1

8/1

90

0

5/2

1/1

90

0

5/24

/190

0

Pe

rce

nt

of U

nit

Ho

urs

Date

Real Time Clearing in Different Configuration Than Self-Scheduled or Scheduled Day-Ahead

Pct Hours Cleared in Different Config 10 per. Mov. Avg. (Pct Hours Cleared in Different Config)

MSG – Day Ahead cleared MWh versus self-

scheduled MWh

0

10,000

20,000

30,000

40,000

50,000

60,000

70,000

80,000

90,000

100,000

12

/7/2

01

0

12

/14

/20

10

12

/21

/20

10

12

/28

/20

10

1/4

/20

11

1/1

1/2

01

1

1/1

8/2

01

1

1/2

5/2

01

1

2/1

/20

11

2/8

/20

11

2/1

5/2

01

1

2/2

2/2

01

1

3/1

/20

11

3/8

/20

11

3/1

5/2

01

1

3/2

2/2

01

1

3/2

9/2

01

1

4/5

/20

11

4/1

2/2

01

1

4/1

9/2

01

1

4/2

6/2

01

1

Cle

are

d/S

elf

Sch

ed

uled

Mw

h

Date

Day-Ahead Cleared/Self Scheduled Mwh

Self_Scheduled_Mwh Cleared_Mwh

MSG – Day Ahead Cleared / Real-Time Cleared

-30,000

-20,000

-10,000

0

10,000

20,000

30,000

40,000

50,000

60,000

70,000

12

/7/2

01

0

12

/14

/20

10

12

/21

/20

10

12

/28

/20

10

1/4

/20

11

1/1

1/2

01

1

1/1

8/2

01

1

1/2

5/2

01

1

2/1

/20

11

2/8

/20

11

2/1

5/2

01

1

2/2

2/2

01

1

3/1

/20

11

3/8

/20

11

3/1

5/2

01

1

3/2

2/2

01

1

3/2

9/2

01

1

4/5

/20

11

4/1

2/2

01

1

4/1

9/2

01

1

4/2

6/2

01

1

Cle

are

d M

wh

Date

Day-Ahead Cleared Mwh / Real-Time Cleared Mwh

DA_Cleared_Mwh RT Clearned Mwh

MSG – Real-time Exceptional Dispatch

-

100

200

300

400

500

600

700

800 R

eal

Tim

e (

Un

it In

terv

als)

date

Real-Time Exceptional Dispatch - MSG

Note: Humboldt management large portion of MSG exceptional dispatches

Exceptional Dispatches volumes increased in February and

March associated with system capacity and ramp-rate needs.

Slide 35

Approx. 1% of total daily energy

Approx. 1% of

total Demand

Note: To reduce exceptional dispatch to position resource to support awarded

A/S ramp, dynamic ramp will be used to constrain awarded A/S. Refer to

dynamic ancillary ramp solution discussion later in presentation.

Day-Ahead bid cost recovery increased significantly Q1-2011.

Slide 36

$0

$2,000,000

$4,000,000

$6,000,000

$8,000,000

$10,000,000

$12,000,000

$14,000,000

$16,000,000

$18,000,000

Apr

-09

May

-09

Jun-

09

Jul-0

9

Aug

-09

Sep-

09

Oct

-09

Nov

-09

Dec

-09

Jan-

10

Feb-

10

Mar

-10

Apr

-10

May

-10

Jun-

10

Jul-1

0

Aug

-10

Sep-

10

Oct

-10

Nov

-10

Dec

-10

Jan-

11

Feb-

11

Mar

-11

Apr

-11

Series1

Increases in BCR due to revenue

associated with day-ahead

minimum load and schedule when

resource is dispatched down in

real-time. ISO filed and FERC

approved change to bid cost

recovery.

RTM Bid cost recovery increased in Q1-2011.

Slide 37

$0

$1,000,000

$2,000,000

$3,000,000

$4,000,000

$5,000,000

$6,000,000

Ap

r-0

9

May

-09

Jun

-09

Jul-

09

Au

g-0

9

Sep

-09

Oct

-09

No

v-0

9

De

c-0

9

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

De

c-1

0

Jan

-11

Feb

-11

Mar

-11

Ap

r-1

1

Series1

ISO is reviewing sources of

increased real-time BCR

Daily Performance Results of DA LDF Adjustments

Since Production in 12/2010

-80%

-60%

-40%

-20%

0%

20%

40%

60%

80%

12

/20

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10

12

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11

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/20

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2/1

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/20

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/20

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Imp

rove

me

nt

of

Ad

juste

d L

DF

s o

ve

r O

rig

ina

l L

DF

(%

)

Date

Performance of DA LDF Adjustment Since December 2010

Improvement of Adjusted LDFs over Original LDFs

= (1 – Adjusted LDFs Deviation / Original LDFs Deviation )100%

Referencing SE distribution in deviation calculation

Ramping Requirements

1. Implementing Flexi-ramp Reliability Tool

– Nomogram to better manage bid in ramping capacity

– Initially upward constraint only

– Enforce in RTPD and RTD (non-binding intervals)

– Enforce constraint to improve operational preparedness to

changes in imbalance conditions

2. Working Towards Ramping Product

a. Consider opportunity cost compensation

– Review market results for three months (June-August)

– Conduct expedited stakeholder process starting in September/

Board in December

– Implementation plan to be determined

b. Comprehensive product design through Renewable

Integration Market & Product Review Phase 2

Policy Update

Greg Cook, Director

Market & Infrastructure Policy

Slide 40

Market Initiatives In Progress

Initiative Board Presentation

Data Release Phase 3 May 2011

Dynamic Transfers May 2011

GMC Rate Structure Change May 2011

Credit Reform in Organized Energy

Markets

May 2011

Renewable Integration Market &

Product Review Phase 1

June 2011

CRR Enhancements 2011 June 2011

LMPM Enhancements June 2011

Real-Time Imbalance Energy Offset June 2011

Market Initiatives In Progress

Initiative Board Presentation

Regulatory Must-Take Generation June 2011

Regulatory Must-Run Pump Load June 2011

Price Inconsistency caused by Intertie

Constraints

June 2011

Deliverability of Resource Adequacy

on Interties

Resource Transitions

GIP Phase 2 August 2011

Other Market Initiatives Activities

• Renewable Integration Market & Product Review Phase 2

– Complete comprehensive vision and roadmap for end-state

market design to meet 33 percent RPS

– Targeted to be presented to Board in December

• Market Initiatives Roadmap Process

– Targeted to start in June 2011

• Release 2 (year three) FERC Mandated Items – these items

may be delayed in order to address them more holistically

– Export of AS

– Bid Cost Recovery for Unit over Multiple Days

– Two Tier Real-Time Uplift

Technical Updates

Li Zhou, Senior Advisor

Power Systems Technology Development

Open Ties

• CAISO is currently testing the fix for the following issue

identified in Market Simulation,

“When an one MW virtual bid is submitted at an open tie, it

does not get rejected. It should.”

Market participants shall be able to see the effect of this fix

by 05/10/11 in market simulation environment.

Energy Self-Schedule Requirement for Regulation Self

Provision

• Tariff Filing on 05/03/11

• SIBR rule change has been posted

• Go-live day on 05/24/11 (Operation Date), i.e., effective

for any market that is open at the time of deployment

Energy Self-Schedule Requirement for Regulation Self

Provision

• A submission to self-provide Regulation Down must be

supported by an Energy Self-Schedule at a level that

would permit the resource to provide Regulation Down to

its lower Regulation Limit. A submission to self-provide

Regulation Up must be supported by an Energy Self-

Schedule at a level that would permit the resource to

provide Regulation Up within its Regulation Limit

• In real-time, self provisions also include day-ahead

awarded regulation up or down capacity;

• Not applicable to MSS load following;

• Bids will be rejected if not meeting the requirement.

Enforcement of Physical and Physical plus Virtual

constraints for MSL

• Background

Because the market enforces the physical only and

physical + virtual on ITCs while only enforces the physical

+ virtual on the MSLs, there may be a counter flow caused

by virtual that may result is over-scheduling physicals that

will need to be cut in real-time. Due to this reason, CAISO

has disabled some inter-tie scheduling points from virtual

Bidding.

Enforcement of Physical and Physical plus Virtual

constraints for MSL

• Update on the Enhancement

The enhancement is to actually enforce both Physical only

and Physical + Virtual constraints for MSLs as well.

Development is complete;

CAISO will start testing this week.

Planned production dated in the first half of June. Upon

successful test, CAISO will issue market notice and those

nodes disabled due to this reason will be enabled for virtual

bidding on production date.

Dynamic Ancillary Service Ramp - Problem Statement

• Currently in the co-optimization of energy and ancillary

service, operation ramp-rate curve is used for energy

while ancillary service ramp-rate is used for ancillary

service.

• The procurement of AS in the co-optimization of energy

and AS does not consider the possible ramp-rate change

when energy is dispatched at different MW level.

• Hence, the procured AS capacity may not be feasible to

be dispatched for energy due to ramp-rate limit.

• This may cause a reliability concern in production that

may result in increase in number of exceptional

dispatches.

Dynamic Ancillary Service Ramp - Proposed Solution

• ISO is currently evaluating and testing a solution in

which operation ramp-rate curve will be also considered

in the AS procurement.

• Effectively, the procurement of AS in the software will

use the minimum of AS ramp rate, and the operating

ramp rate at the scheduled energy MW.

Dynamic Ancillary Service Ramp – Numerical Example

• Unit 1 has the following operational ramp-rate curve

(20MW, 190MW) 1.6 MW/min;

(190MW, 250MW) 6.4 MW/min;

Spin ramp-rate 6.4 MW/min

Dynamic Ancillary Service Ramp – before fix

• With existing method for AS procurement, the following

energy and Spin results are possible:

EN Spin

HE1: 138 64

HE2: 42 64

HE3: 20 64

• Note: the spin capacity is procured with 6.4 MW/min

even the unit is at 20MW of energy with an effective 1.6

MW/min operation ramp-rate.

Dynamic Ancillary Service Ramp – after fix

• After enforcing the operational ramp-rate for AS, the

energy and Spin results are:

EN Spin

HE1: 138 16

HE2: 94 16

HE3: 190 64

• The spin capacities for HE 1, 2 are now limited with the

1.6 MW/min operational ramp-rate.

MSG Enhancement

• MSG Enhancement List was presented to Stake Holders

on 03/14/11

• Stake Holders have given inputs and comments on

priorities

• Currently finalizing requirement and evaluating timeline

Following is the list for the selected MSG enhancements,

1. RTPD needs to consider telemetry – Currently RTPD

does not take the telemetry into consideration for MSG

resources. RTD does recognize the telemetry;

2. Extension of the terminal condition to consider

configuration level minimum down time when making

transition decisions;

MSG Enhancement

3. Following enforcements will always take the submitted

Bid from MP first, if an energy bid is not submitted for a

Lower configuration, the default energy bid will be used for

That lower configuration.

3.1). Bids for non-RA resources in RTM with DA award.

SIBR shall enforce the bids to be available for all

configurations below the DA schedule even the DA

scheduled configuration is startup-able;

3.2). SIBR rule changes to tighten real-time bid submission

including support of DA awarded AS or sufficient bids to

allow transition across trading hours. Similarly to item 3.1,

MSG Enhancement

SIBR shall enforce the lower configurations to be bid in.

3.3). Whenever a capacity is offered, the MSG resource

shall offer the entire capacity range underneath that

capacity.

4. Transition Cost registration – Formula needs to be

revised (Policy change required);

5. Extension of the Real-time limit on maximum number of

configurations (Tariff change required);

6. Allow at least two ramp rates within configuration in

IFM/RTD (or at least RTD). This is also related to the

need to be able to provide more spin service when it can

move from a configuration into duct firing in 10 minutes

inclusive of ramp and transition.;

Reliability Demand Response Product (RDRP)

• Currently in the development of system requirement

specification and design

• SIBR rules will be posted by 05/13/11

Reliability Demand Response Product (RDRP)

RDRP will be modeled like a supply resource relying on the

functionality and infrastructure designed for the ISO’s

recently implemented Proxy Demand Resource (PDR)

product.

In addition to the regular PDR features, RDRP resources

• Will have a discrete dispatch capability;

• Will deliver “reliability energy” in real-time as specified in

CAISO Electrical System Emergency Operating

Procedures; and

• Will be subject to availability limits of 15 events and/or 48

hours (2,880 minutes) within any six (6) month RDRP

Term.

Release Plan Update

Janet Morris, Director

Program Office

Slide 60

Master Stakeholder Engagement Plan

http://www.caiso.com/2825/2825e37f44400.pdf

(now includes revision log)

http://www.caiso.com/2825/2825e37f44400.pdf

Project Updates

• MSG Market Simulation Update

• Convergence Bidding Update

• Pre-Summer 2011 Monthly Releases– Open Ties milestones

– Flexible Ramping

– Commitment Costs 1.1

– Reporting Platform Migration

• Fall 2011 release– 72 Hour RUC milestones

– RDRP milestones

– Commitment Costs Phase 2

– Flex Ramping milestones

– FERC Order 741 Credit Reform

• December 2011 monthly release– Generation of bids for NRS-RA

– GMC rate structure change

• Spring 2011 release– Regulation Energy Management

– LMPM Enhancements

– SLIC to SIBR Interface

Registration

• Following the third MSG activation window, MSG resources may be

activated for any trade date subject to 16 business days for processing of

the MSG registration.

Testing

• One to two week testing intervals will be planned with each monthly release,

occurring three weeks prior to the second Tuesday of the month.

• External testing will be conducted in the MAP-Stage environment.

• At least one settlement statement will be offered during that testing interval.

• Further testing requests will need to be coordinated in advance with the

ISO.

• Please indicate if you would like to modify your Master File data during the

market simulation.

Ongoing MSG Activation Process

Convergence Bidding Update

Two notable post go-live issues are being addressed:

– The OASIS Day-Ahead Market Summary report has been

restored as of 5/3/11.

– Tie points modeling as MSLs were not held to the correct limits

by the dual intertie constraint functionality and nine MSL intertie

locations have been suspended. We are expecting to resolve

this by the end of May.

May Release - Open Ties Project Milestones

Milestone Open Ties / Market Scheduling Limit

BPM Changes Feb 4th, 2011

Publish external business

requirements

Feb 7th, 2011

Publish Technical Specifications Feb 7th, 2011

Market Simulation April 12th, 2011

Go-Live May 18th, 2011 Rescheduled

API changes to show Open Tie

condition in the CleanBid XSD

October 1, 2011

May Release - Flexible Ramping Project Milestones

Milestone Date

Technical bulletin published February 24, 2011

Publish external OASIS requirements April 1, 2011

BPM change management process April – May, 2011 In Progress

Market Simulation May 5 – May 9 In Progress

Production Deployment (inactive) May 24, 2011 On Track

Activation May 31, 2011 On Track

June Monthly Release - Commitment Costs Phase 1.1

Application impacted: Master File

• Release Details

– Addition of the following flags in the Resource Data Template (RDT)

• Pre Hourly Dispatch, Cert DAM, Cert RTM, and Stranded Load to the Gen RDT as non-modifiable.

• ML Cost Basis Type and SU Cost Basis Type to Gen RDT as modifiable

• Stranded Load to the Intertie RDT as non-modifiable.

– Removal of Cost Basis Type from Gen RDT.

– Support backward compatibility with version 3.0 of the Generator RDT and version 1.0 of Inter-Tie RDT.

– Rounding of submitted Heat Rate to 3 decimal places (no changes to the RDT).

• Market Simulation Schedule

• Monday 05/16 (08:00 AM)- Wednesday 05/18 (05:00 PM):

– Scheduling Coordinators (SCs) test items listed in CC 1.1 release above.

– Please restrict submission to only three resources per SC

• By Monday 05/23 (05:00 PM)

– ISO performs bare minimum manual validation on the submitted Batches and approves the batches.

– ISO will send a notification (via outlook email) to all the SCs who submitted a batch informing them

that their submitted batch has been approved or rejected.

Slide 67

June Monthly Release - Report Platform Migration

• Overview– The California ISO is planning to release software affecting the external

facing graphical user interface (GUI) reports generating MasterFile

(MF), MSSA Load Forecast, Scheduling Infrastructure Business Rules

(SiBR), Business Practice Manual (BPM), Transmission Register (TR),

and Resource Interconnection Management System (RIMS) information

to market participants in the production environment during the Monthly

Release slated on June 14, 2011.

– This release is mainly a software conversion of the existing reports

based on the newly ISO-adopted reporting technology.

– A pre-production external testing period within the stage environment is

planned to be available from May 24 to June 3, 2011.

Fall 2011 Release - 72 hours RUC Release Milestones

Milestone Date

Publish business requirements September 23, 2010

Implementation plan December 10, 2010

Technical specifications N/A

Publish draft BPM July 19, 2011 On Track

Market simulation Aug 23 – Sept 8, 2011 On Track

Production Deployment October 1, 2011 On Track

Fall 2011 Release - Reliability Demand Response

Product (RDRP) Release Milestones

Milestone Date

Publish business requirements March 29, 2011

Publish draft BPM June 2011 On Track

Technical specifications June 27, 2011 On Track

Implementation plan July 2011 On Track

Market simulation Aug 23 – Sept 8, 2011 On Track

Production Deployment October 1, 2011 On Track

Fall 2011 Release - Change in Commitment Costs

Phase 2

Application

Software

Changes

Enhance the Master File (MF) system

Enhance the MF RDT to collection Start-Up cost for

MSG configurations not capable of direct start-up

Provide comparison and validation Report via MF

User Interface (UI)

RDT Processing status updates via automated E-mail

Notification

Enhancements to the validation and processing of

data changes submitted to the MF system (Internal to

ISO)

Policy

ImplementationReview default O&M adder default values and revise as

needed.

Changes (if any) would be effective on April 1, 2012

No application changes anticipated

Fall 2011 Release - Credit Reform Release Milestones

Milestone Date

Post final implementation proposal April 8, 2011

Board approval May 15, 2011 On Track

Tariff stakeholders’ process May 18 – June 29, 2011 On Track

FERC filing June 30, 2011 On Track

Technical specifications N/A

BPM change management process July 1 - Sept 30, 2011 On Track

Configuration guides July 15, 2011 (tentative)

Market simulation August 15 – Sept 2, 2011 On Track

Production deployment October 1, 2011 On Track

• Business Requirements Posted February 25, 2011

• Implementation Workshop (March 10, 2011)

• Scope of project refined to accommodate timeline.

• Insertion of Bids for NRS-RA resources limited to:

– Insertion of bids for NRS resources with RA obligation.

– Subset of hours bids apply to NRS resources with RA obligations only.

– SLIC Outage reporting at NRS resource level for NRS resources with RA

obligations.

– Recognition of the SLIC outages in the market applications for SLIC Outage at

NRS resource level for NRS resources with RA obligations

• Deferred scope due to refined implementation impact analysis showed more

effort than previously considered for subset of hours RA for internal RA

resources to CPM, SCP and RA business processes

• Market Simulation: October/November 2011

• Proposed Implementation Timeframe: January 1, 2012

December Monthly Release - Insertion of Bids for

NRS-RA Impact Assessment

December Monthly Release - GMC Rate Structure

Impact Assessment

Application Software Changes • Congestion Revenue Rights (CRR)

• Settlements

BPM Changes • Congestion Revenue Rights (CRR)

• Settlements & Billing

• Definitions & Acronyms

Business Process Changes • Manage Billing & Settlements

Business Requirements • Under development

Operational Procedures • N/A

Market Simulation • Fall 2011

Proposed Implementation Timeframe • January 1, 2012

Spring 2012 Release - Regulation Energy Management (REM)

Model REM in the framework of Non-Generator Resource (NGR)

Project Technology Model

Option to REM

(Special Treatment)

RegulationSpin/Non-

SpinEnergy

Qualified MW

Non-Generator Resource

(NGR) (2012)

New functions in

EMS, market from bid to

Bill

Energy Storage Resource (ESR)

(Flywheel, battery, energy storage)

Operation range between negative (Charge) and positive (Discharge),

constrained by State of Charge (SOC)

REM SC Bid No No15 minute continuous

delivery

Non REM SC Bid SC Bid SC Bid

Depending on

registration and

certification

Dispatchable Demand Response (DDR) --

Implementation of the PLR model

Operation range is non positive, constrained by

limited curtailable energy.

REM SC Bid No No15 minute continuous

delivery

Non REM SC Bid SC Bid SC Bid

Depending on

registration and

certification

Regulation Energy Management (REM)

Model NGR in EMS with supply range of negative to positive

• EMS shall model NGR as a generation resource with supply range of

negative to positive.

– For ESR, the operation output is positive when the ESR discharging and inject

the power into the grid; the output is negative when the ESR is charging and

withdraw the power from the grid.

Ex: A battery is discharging at 2 MW, the operation output will be 2MW. A battery

is charging at 2 MW, the output will be -2 MW.

– For DDR, the operation output is non positive.

Ex: DDR Load level is 10 MW, the operation output = -10 MW. DDR load level is

curtailed by 2 MW, operate at 8 MW, the operation output = -8 MW.

• EMS AGC module shall dispatch NGR for regulation up and down

– NGR provides regulation up if AGC dispatches the NGR above its DOT

– NGR provides regulation Down if AGC dispatches the NGR below its DOT


EMS shall receive NGR telemetry every four (4) seconds;

• EMS shall receive NGR telemetry of the following data every four (4)

seconds:

– Resource Instantaneous Output (MW);

– State of Charge (SOC), which is the actual stored Energy (MWh) in the device;

ESR Instantaneous Output (MW) telemetry is negative when the ESR is charging.

ESR Instantaneous Output (MW) telemetry is positive when the ESR is discharging.

DDR Instantaneous Output (MW) telemetry is negative for its load level. DDR

Instantaneous Output (MW) telemetry is zero if the load shut down totally

• EMS shall send to RTM every minute the SE solution and all telemetry for

each NGR, including the state of charge (SOC) for ESR


DAM/RTM model NGR as a generation resource with supply range of

negative to positive

• Optimize NGR energy and AS awards in DAM/RTM subject to:

– Capacity Constraints;

– Ramping (Charge/Discharge rates) Constraints;

– State of Charge (SOC) constraints for ESR;

– Daily energy limits and continuous energy limits for DDR;

• NGR optimal schedule and AS awards shall be based on its Energy bid

curve and AS bids.

• DAM/RTM will model NGR with energy and/or AS bids as on-line unit; No

binary commitment decision variables are needed for NGR. No start up cost

/time, No commitment cost recovery.

• RTM shall receive from EMS telemetry for each NGR, including the actual

SOC for each ESR, to calculate initial condition. ESR optimal schedule and

AS awards shall be limited by the available SOC.


REM modeling as a NGR

• REM shall be allowed to bid or self-schedule Regulation Up and Regulation

Down capacity in DAM/RTM

• REM will not bid or self-schedule Energy in DAM/RTM

• The SOC constraints will be enforced in the market for REM. SOC

constraints and regulation bids will determine the REM regulation up and

down awards and energy schedule DOT (dispatch operating target).

• The ISO shall manage REM energy offset through AGC in EMS. AGC will

dispatch REM based on DOT and regulation awards. REM must response

AGC dispatch.

• Settle Regulation Awards in DAM and RTPD.

• Settle REM at RT LMP for each interval of net metered energy.

(equivalent to settle REM at RT LMP for the energy offset and regulation energy

dispatched by AGC)


NGR Settlement

• NGR shall be subject to all existing AS/RUC No Pay categories.

• ESR shall be subject to a new AS/RUC No Pay category: Insufficient Stored

Energy

– The relevant No Pay quantity (MW) shall be calculated for each dispatch interval

to see if SOC level can provide enough energy once the awarded AS called upon

• Settle the NGR energy schedule at LMP in IFM and RTD.

• Settle the NGR AS awards same as Generators in IFM and RTPD.

REM Market Simulation Notification Date

• REM is planned for deployment in Spring 2012

• In order to participate in the REM market simulation, you

must notify the ISO by July 1, 2011:

– Submit the WDAT (Wholesale Direct Access Tariff)

– If you intend to connect to the transmission system

directly, participate in the fast-track interconnection

process (for less than 5 MW)

SLIC to SIBR Interface – Background

September 2006 FERC Order

• FERC’s September 2006 order directed the ISO to implement an

interface between SLIC and SIBR by “MRTU Release 2,” a feature

that the ISO had itself proposed for Release 2.

• The ISO is reconsidering whether this feature would provide

sufficient benefit to the market to justify the costs of implementation

especially in light of other high priority enhancements

• As noted in the September 2006 order, even if SIBR generated bids

for derated capacity, the day-ahead and real-time markets will see

derates entered into SLIC and bids for capacity that is not available

will not result in market awards

SLIC to SIBR Interface – Impact Assessment

Significant system changes would be required• In order to properly handle in the case of a generation outage/de-rate/re-

rate, around 500 generator processing and validation rules will have to be

revisited and revised;

• In the case that there are multiple commodity bid in (energy and ancillary

services) and the unit is de-rated or re-rated, there is no clean way to adjust

or curtail the bids. CAISO will need to reject the bids.

• In the case that the particular generator is associated with any

ETC/TOR/CVR contract, the adjustment will require to follow the contract

and potentially the chain to all the impacted sources and sinks.

• Outage Management System will replace SLIC in 2012

• Testing and market simulation would be extensive

SLIC to SIBR Interface – Impact Assessment

Benefit to market participants appears to be limited

• Planned Outages: When markets are open, the SC can resubmit

their bids based on planned outages

• Forced Outages: When markets are already closed, bids cannot be

requested and it will be recognized in real time

SLIC to SIBR Interface – Next Steps

• The ISO is seeking comments on the current need to

provide a SLIC to SIBR interface

• Submit comments by 5/25/11 to [email protected]

• Based on comments received, the ISO will publish an

issue paper in the June timeframe

mailto:[email protected]

Implementation Updates

Jami Long, Director

Business Solutions and Quality

Outage Management System – Background

• In 2007, the ISO defined its expectations of an Outage Management

System (OMS).

– An OMS strategy was developed to replace the current Scheduling,

Logging for ISO California (SLIC) and CAISO Outage Modeling

Tool (COMT) systems by creating and incrementally deploying a

consolidated modular OMS. Each module targets a specific outage

domain including transmission, generation, analytical tools, and

reporting.

• Phase 1 was deployed in December 2010 for transmission and

systems analysis. The COMT application was sunset.

• Phase 2 is currently underway and scheduled to deploy to production

in Fall 2011 to provide visualization enhancements to transmission.

• Phase 3 will start with a twenty-two week requirements effort from May

through October 2011, with working group touch-points throughout.

OMS Phase 3 – Project Objectives

• OMS Phase 3 will incorporate generation outage

management functionality currently provided from SLIC

into the new OMS framework.

• Simplification and Usability Improvements

• Market Participant Collaboration

• OMS will decommission the SLIC application upon

deployment.

OMS Phase 3 - Scope

• Proposed Scope:

– Development of web client for external users

– Quick Find

– Search/Reports for Generation Outages

– Process Generation Outages

– Outage/Version Comparison

– Process/Assign User Tasks

– Notifications

– Visualization

– API Simplification

OMS Phase 3 – High Level Milestones

# Milestone DescriptionTarget Delivery

Timeframe

1. Requirements Analysis and Development Q3 2011

2. External User Checkpoints Q3 2011

3. Phase 3 Design and Development Q2 2012

4. BPM Revision Cycle Q2 2012

5. Phase 3 Testing Q3 2012

6. Market Simulation Q3 2012

7. Tariff Changes Q3 2012

8. Deployment Q4 2012

9. Production Validation Q4 2012

10. End-of-Life SLIC API Q4 2012

Data Release Ongoing Process

• Data release requests will be made through the

Business Practice Manual (BPM) Process leveraging the

existing process and timelines.

• A new BPM will be created and maintained to describe

data published by the ISO, both confidential and public

data.

• Proposed Revision Requests (PRR) will be available for

the drafted BPM in Q3.

Market Performance and Planning Forum...Market Performance and Planning Forum May 11, 2011....

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