Market Performance and Planning Forum · Market Performance and Planning Forum Agenda –December...

Market Performance and Planning

Forum

December 7, 2016

Objective: Enable dialogue on implementation

planning and market performance issues

• Review key market performance topics

• Share updates to 2016 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

Market Performance and Planning ForumAgenda – December 7, 2016

12:00 – 1:00 Lunch

1:00 – 1:30 Market Results – PSE and APS

Integration Gabe Murtaugh

1:30 – 2:00 Policy Update Brad Cooper

2:00 – 3:00 • Release Update

• Annual Functional Release Lifecycle

Janet Morris

Time: Topic: Presenter:

10:00 – 10:05 Introduction, Agenda Kristina Osborne

10:05 – 10:20 Real-Time Transfer Limit Increases Danny Johnson

10:20 – 10:45 November 9 Frequency Deviation Event John Phipps

10:45 – 12:00 Market Performance and Quality Update Guillermo Bautista Alderete

Warren Katzenstein

Amber Motley

Slide 3

Real-Time Transfer Limit Increases

Danny Johnson

Sr. Operations Engineer, Operations Planning - South

Slide 4

Increase Transfer Capability on WECC Paths

Slide 5

Aliso Canyon Authority

• CAISO received authority to “reserve internal transfer

capability into Southern California”

• Have since moved to retire this authority as we believe

we can instead use Peak RC SOL methodology to

increase Real Time transfer if needed.

Justification for Real Time Uprate

Peak RC System Operating Limit (SOL) Methodology

– Section 6 specifies that in ‘sub-seasonal’ time

horizons the acceptable performance for Credible

Multiple Contingencies can be relaxed if system

conditions do not allow for the planned level of

performance

– This means in Real Time operations limits established

using more stringent criteria for CMC can be

revaluated during emergency

NERC EOP-002-3.1

– Section 3.4 allows for a revision to SOL limits given

RT information following the issuance of a EEA

(Energy Emergency Alert) by the ISO.Slide 7

Path Limits

Slide 8

• Path limits are based upon offline powerflow studies

• Does not account for Seasonal Variations or changing

load profiles

• Path limits are often pre-contingency proxy MW limits

across multiple transmission elements

– Doesn’t account for minor changes in neighboring

network topology due to outages

– Doesn’t account for voltage conditions.

• Equipment ratings are based upon Amp rating.

• MVA = Amp*Voltage;

• MW limits are converted from MVA limits based

upon studied or assumed power factor, not

RT/Operational power factor

How would CAISO implement?

CAISO RT Operations can utilize Real Time Contingency

Analysis (RTCA) to monitor the actual element the path

limit is trying to protect for

More accurate limit because:

• Rather then limiting flows to the pre-contingency proxy

limit, CAISO can monitor and protect against post

contingency overloads on the actual limiting element

• Allows for utilization of Real Time voltage conditions in

monitoring limit

• Accounts for changes in neighboring area topology

• RTCA RAS functionality allows for incorporating Real

Time congestion relief offered via RAS operation

Slide 9

Use Case – Path 26 (North-to-South)

Path Details

- 4000 MW limit from transfer capability of three transmission lines

- Is composed of Midway-Vincent #1 + Midway-Vincent #2 +

Midway-Whirlwind #1 transmission lines

- Is thermally limited by CMC of two of the three lines composing

path

- Path limit is based upon assumed RAS operation at time of study;

Gen Drop in PG&E and Load Shed in SCE

If necessary CAISO can increase Real Time limit by

monitoring CMC in RTCA

– Accounts for additional load being armed in SCE; Load armed by

RAS has increased significantly since Path Limit was set in 2006

– Controls to a MVA limit based upon Amp rating and post-

contingency voltage.

– Real Time limit above posted SOL achievableSlide 10

Impact on Market Operation

• CAISO plans to use this methodology to increase limits

in Real Time only during emergency conditions. This will

be following exhaustion of all available generation and

utilization of all available demand response

– Due to the Real Time data required this can not be

implemented in IFM. IFM and RTM under normal

conditions will continue to operate with the current

ratings from CAISO Transmission Register

• Real Time Transfer Increases will NOT be posted in TTC

• Will be used to avoid pre-contingency load shedding

Slide 11

November 9 Frequency Deviation Event

John Phipps

Director, Real-Time Operations

Slide 12


– Event Description

– At 11:00 a normal data transfer process with inputs for the market occurred on schedule. A conflict in the process corrupted an input that was then transferred into the market software. The next market run at 11:15 failed and advisory results were sent out based on the last successful run at 10:59. The issues and troubleshooting continued through the hour until the issue was found and fixed around 12:10. Additional related issues were discovered and fixed at approximately 12:39.

– Around 11:59, the market runs started producing undesirable results. The ISO System Operators intervened by identifying and blocking the undesirable dispatches. This continued until 13:35 in order to keep the undesirable instructions from being sent to the market participants via ADS. During this time period the ISO System Operators sent out multiple market messages to Scheduling Coordinators in order to raise awareness and prevent resources from following undesirable startup or shutdown instructions. Scheduling Coordinators were encouraged to call the ISO to validate instructions before starting or shutting down any units.


– 13:33 the ISO market software sent out decrementaldispatch instructions of approximately 2500 MW to multiple generator resources via the Automatic Dispatch System (ADS) before the ISO’s System Operators could block or override the dispatch instructions. The ISO’s Operators verbally instructed Scheduling Coordinators to not follow the dispatches, but 1214 MW of the dispatch included fast moving resources and 730 MW of additional resources which automatically responded to the dispatch signal and reduced their output over an 11 minute period. This reduction in generation output caused the CAISO ACE and System Frequency to deviate.

– At 13:35 BAAL was exceeded. At 13:45 ACE was at its lowest point -3245MW and Frequency was 59.834 HZ.

– 13:53 BAAL was within limits, ACE and Frequency were recovered.


Event Follow-up

• Action Items

– Review both automated and manual controls for

improvement

– Review ramp rates and expectations of units to ramp

over 5 minutes

– Lessons learned training and delivery by operators

involved in the event

Market Performance and Quality Update

Guillermo Bautista Alderete, Ph.D.

Manager, Market Validation and Quality Analysis

Warren Katzenstein

Lead Engineering Specialist

Amber Motley

Manager, Short Term Forecasting

Slide 16

Adjustment to Regulation Capacity

Requirements

Slide 17

Control Performance and variable energy resources’

production affect the quantity of regulation procured

• Control Performance

– Measures the ability to adequately support the interconnection frequency

– Exceedance of Balancing Authority Ace Limits (BAAL)1

– Noticed a decline in real-time CPS1 performance

– Led to procured regulation up/regulation down depletion during high renewable penetration/low load periods

• High renewable penetration/low load periods

– Windy and cloudy conditions exacerbate wind and solar production variability causing larger deviations from forecast

– Erratic weather (seasonal) during low load periods

Slide 18

Method for Determining Regulation Capacity

• For each hour, the ISO determines a percentage of forecasted demand to set regulation capacity

• The amount of regulation capacity for a given month is informed by:

– Forecast Uncertainty Related To:

• Demand Forecast Deviations

• Solar Forecast Deviations

• Wind Forecast Deviations

– Seasonal/Daily Parameters

• New considerations

– Separation of Regulation Need in relation to Regulation Up and Regulation Down

– Hourly Analysis of Historical Regulation Dispatch

– Anticipated variability / forecast uncertainty in weather conditions

Slide 19

Method for Determining Regulation Capacity Cont.

• Historical Need

– For each hour, examine the 95th percentile of regulation required as calculated by the control algorithm

– Use data from the same month last year to inform procurement for the current month (i.e. Oct 2015 informs Oct 2016)

• Anticipated variability / forecast uncertainty

– Examine performance from recent days that had higher forecast uncertainty in order to inform change in procurement related to weather

– Example is a large weather system moving across California causing variability in cloud cover and wind speed/direction.

Slide 20

0

50

100

150

200

250

300

350

400

450

500

0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23

Re

gu

latio

n U

p M

inim

um

Ca

pa

city

(MW

)

Hour Ending

Jan Feb Mar Apr May Jun Jul Aug SEP OCT NOV DEC

Seasonal Trends are Present with New Method

(Regulation Up)

Slide 21

Values above are based on historical information and are subject to change.

0

100

200

300

400

500

600

700

800

0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23

Re

gu

latio

n D

ow

n M

inim

um

Ca

pa

city

(MW

)

Hour Ending

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

Seasonal Trends (Regulation Down)

Slide 22

Values above are based on historical information and are subject to change.

May 2016 Regulation Procurement Versus October

2016 Procurement

Slide 23

-1000

-800

-600

-400

-200

0

200

400

600

800

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24

Reg

ula

tio

n R

equ

irem

ent

(MW

)

Hour of the Day (Hour Ending)

Spring 2016 Regulation Capacity

Oct 2016 Regulation Capacity

October 2016 Results

Slide 24

Percentage of time with insufficient capacity: 1%

Flexible Ramp Product Update

Slide 25

Flexible Ramp Product

• Flexible Ramp product went live on November 1, 2016

• There is both upward and downward definitions for the

product.

• Each EIM area has its own requirement, and there is

also a system-wide EIM area enforced in the real-time

market.

• There is also a flexible ramp sufficiency test done prior to

the real-time market.

• Requirements are based on historical data and

calculated in the Balancing Area Ramp Requirement

(BARR) application.

Slide 26

What is the Balancing Area Ramp Requirement Tool?

• The Balancing Area Ramp Requirement (BARR) tool

calculates the uncertainty requirement and the demand

curves for the Flex Ramp Product

• The uncertainty requirements are hourly values

calculated every day using the BARR tool

• Uncertainty requirements are based on net load forecast

error

Net load = Load – Wind - Solar

• The demand curves are the prices the system is willing

to pay for a given quantity of flex ramp capacity

Slide 27

Flexible Ramp Uncertainty Requirement: 5-minute

Real-Time Dispatch (RTD)

Slide 28

RTD Net Load Forecast Error is difference between the binding

interval net load forecast and the prior market run first advisory net

load forecast

Flexible Ramp Uncertainty Requirement: 15-minute

Real-Time Pre-Dispatch (RTPD)

Slide 29

RTPD Net Load Forecast Error is maximum difference between the

three RTD binding interval net load forecasts and the associated

RTPD first advisory net load forecast

RTPD

Example of the Hourly Distribution of Data that

Comprises the Histogram for Each EIM Entity

Slide 30

Example of the Hourly Distribution of Data and the

Calculated Uncertainty Requirements (Red Lines)

Slide 31

An Example of the Flex Ramp Product Uncertainty

Calculation

• Flex Up and Down Uncertainty Requirement could be calculated as follows:

– For each hour, gather the set of recent net load forecast errors for the appropriate market uncertainty

– Group weekdays and weekends separately due to characteristic differences

• Weekdays use last 40 days of net load forecast error

• Weekends use last 20 days of net load forecast error

– The flex up uncertainty requirement is the 97.5 percentile

– The flex down uncertainty requirement is the 2.5 percentile

• Daily thresholds are calculated using a similar process but with a larger set of data

– Significant reduction in % of time thresholds are setting the requirement compared to the Flex Ramp Constraint

Slide 32

Demand Curves

• The demand curves are used to determine how much

flexible ramp capacity the system will procure

• One demand curve for each EIM entity and ISO plus the

EIM Total Area (including ISO) for 7 total demand curves

• The demand curves are the distribution of net load errors

multiplied by the energy penalty price cap or floor

– The penalty price cap is $1000 per MWh

– The penalty price floor is $-150 per MWh

• The maximum price is $247 per MW

• The minimum price is $-155 per MW

Slide 33

Constructing a Demand Curve

• A demand curve starts with the probability distribution of net load forecast errors

– This is the same set of data that is used for determining the uncertainty requirement

• The flex ramp up demand curve is built by calculating the percent of data that is greater than a given MW value

• The flex ramp down demand curve is built by calculating the percent of data that less than a given MW value

• The percentage is converted a price by multiplying by either the energy penalty price cap or price floor

• Finally, the curve is transformed from MW to Relaxation Capacity by subtracting the MW values from the uncertainty requirement

Slide 34

Constructing a Demand Curve (Cont.)

• The OASIS published demand curves are comprised of two

components

– The amount of capacity to relax the uncertainty

requirement

– The price associated for relaxing the uncertainty

requirement

• Example

– With an uncertainty requirement of 100 MW, a relaxation

capacity of 15 MW, and a price of $25 per MW

– This means the market procured 85 MW of flexible

capacity at a price of $25 per MW

Slide 35

0%

5%

10%

15%

20%

25%

30%

35%

40%

45%

0 20 40 60 80 100 120 140 160

Per

cen

t o

f D

ata

Gre

ater

th

an A

Giv

en N

et L

oad

Fo

reca

st

Erro

r (%

)

Net Load Forecast Error Between RTPD Advisory and RTD Binding (MW)

Example of Constructing a Flex Up Demand Curve:

Start with Probability Distribution of Net Load Forecast

Errors

Slide 36

Curves are limited to the flex up or down

uncertainty requirement

Convert Percentage to Price by Multiplying the Curve

by the Energy Penalty Price Cap ($1000 per MWh)

Slide 37

0

50

100

150

200

250

300

350

400

450

0 20 40 60 80 100 120 140 160

Pri

ce (

$/M

W)

Net Load Forecast Error Between RTPD Advisory and RTD Binding (MW)

Convert x-axis to Relaxation MW by Subtracting the Net Load

Forecast Errors From the Uncertainty Requirement

Slide 38

0

50

100

150

200

250

300

350

400

450

020406080100120140160

Pri

ce (

$/M

W)

Relaxaion Capacity (MW)

The Curve is then Segmented for Use in the Market

Optimization

Slide 39

0

50

100

150

200

250

300

350

400

450

020406080100120140160

Pri

ce (

$/M

W)

Relaxation Capacity (MW)

Finally, the Curve is Capped (if Required) at the

Minimum or Maximum Price ($-155/MW or $247/MW)

Slide 40

0

50

100

150

200

250

300

350

020406080100120140160

Pri

ce (

$/M

W)

Relaxation Capacity (MW)

The segmented demand curve is then capped at a price of $247 per MW

FRP performance

Slide 41

FRP requirements and prices driven by the hourly

profile needs

Slide 42

With FRP construct, the EIM area generally drives the

overall procurement

Slide 43

-2,500

-2,000

-1,500

-1,000

-500

0

500

1,000

1,500

2,000

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24

Flex

Ram

p (

MW

)

APS NV Energy PSE PACW PACE ISO Credit Upward/Downward requirement

Flexible Ramp requirements adjusted with FRP activation

Slide 44

Hourly profile of ISO FRP requirements

Slide 45

Gas Price Update

• FERC clarified use of daily ICE gas price index

• Normal cycle calculates blended gas price indices the

prior night which is used for both DAM and RTM

markets.

• With new provisions, the ICE index available in the

morning is used for the DAM market run.

• When no ICE price index is available, it defaults to use

previous night blended index.

Slide 46

Gas price difference of using morning ICE gas price

update

Slide 47


update

Slide 48

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

-20%

-15%

-10%

-5%

0%

5%

10%

15%

20%

25%25

-Oct

27-O

ct

29-O

ct

31-O

ct

2-N

ov

4-N

ov

6-N

ov

8-N

ov

10-N

ov

12-N

ov

14-N

ov

16-N

ov

18-N

ov

20-N

ov

22-N

ov

24-N

ov

26-N

ov

28-N

ov

30-N

ov

2-D

ec

4-D

ec

% o

f V

olu

me

Trad

ed

% P

rice

Dif

fere

nce

($

/MM

BTu

)

Volume SCE CityGate Hub


update

Slide 49

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

-20%

-15%

-10%

-5%

0%

5%

10%

15%

20%

25%25

-Oct

27-O

ct

29-O

ct

31-O

ct

2-N

ov

4-N

ov

6-N

ov

8-N

ov

10-N

ov

12-N

ov

14-N

ov

16-N

ov

18-N

ov

20-N

ov

22-N

ov

24-N

ov

26-N

ov

28-N

ov

30-N

ov

2-D

ec

4-D

ec

% o

f V

olu

me

Trad

ed

% P

rice

Dif

fere

nce

($

/MM

BTu

)

Volume KRN Del Pool Hub

EIM Update

• Arizona Public Service (APS) and Puget Sound (PSE)

joined the EIM market on October 1, 2016.

• In the first hours after the activation, market observed

minor transitional issues.

• Both entities are under the six-month transitional period,

under which price discovery provisions apply.

Slide 50

APS and PSE have passed the balancing test in over

90% of the time

Slide 51

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

1-O

ct

2-O

ct

3-O

ct

4-O

ct

5-O

ct

6-O

ct

7-O

ct

8-O

ct

9-O

ct

10-O

ct

11-O

ct

12-O

ct

13-O

ct

14-O

ct

15-O

ct

16-O

ct

17-O

ct

18-O

ct

19-O

ct

20-O

ct

21-O

ct

22-O

ct

23-O

ct

24-O

ct

25-O

ct

26-O

ct

27-O

ct

28-O

ct

29-O

ct

30-O

ct

31-O

ct

Passed Test Underscheduling Overscheduling

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

1-O

ct

2-O

ct

3-O

ct

4-O

ct

5-O

ct

6-O

ct

7-O

ct

8-O

ct

9-O

ct

10-O

ct

11-O

ct

12-O

ct

13-O

ct

14-O

ct

15-O

ct

16-O

ct

17-O

ct

18-O

ct

19-O

ct

20-O

ct

21-O

ct

22-O

ct

23-O

ct

24-O

ct

25-O

ct

26-O

ct

27-O

ct

28-O

ct

29-O

ct

30-O

ct

31-O

ct

Passed Test Underscheduling Overscheduling

AZPS Area

PSEI Area

Power balance constraint infeasibilities in both APS

and PSE have been less than 0.3% of the time in

October

Slide 52

0%

10%

20%

30%

40%

50%

1-O

ct

2-O

ct

3-O

ct

4-O

ct

5-O

ct

6-O

ct

7-O

ct

8-O

ct

9-O

ct

10-O

ct

11-O

ct

12-O

ct

13-O

ct

14-O

ct

15-O

ct

16-O

ct

17-O

ct

18-O

ct

19-O

ct

20-O

ct

21-O

ct

22-O

ct

23-O

ct

24-O

ct

25-O

ct

26-O

ct

27-O

ct

28-O

ct

29-O

ct

30-O

ct

31-O

ct

Valid FMM Under-supply Infeasibility Correctable Infeasibilities

0%

10%

20%

30%

40%

50%

1-O

ct

2-O

ct

3-O

ct

4-O

ct

5-O

ct

6-O

ct

7-O

ct

8-O

ct

9-O

ct

10-O

ct

11-O

ct

12-O

ct

13-O

ct

14-O

ct

15-O

ct

16-O

ct

17-O

ct

18-O

ct

19-O

ct

20-O

ct

21-O

ct

22-O

ct

23-O

ct

24-O

ct

25-O

ct

26-O

ct

27-O

ct

28-O

ct

29-O

ct

30-O

ct

31-O

ct

Valid RTD Under-supply Infeasibility Load Bias Limiter Correctable Infeasibilities

Power balance constraint infeasibilities in PSE have

been less than 0.3% of the time in October

Slide 53

0%

10%

20%

30%

40%

50%

1-O

ct

2-O

ct

3-O

ct

4-O

ct

5-O

ct

6-O

ct

7-O

ct

8-O

ct

9-O

ct

10-O

ct

11-O

ct

12-O

ct

13-O

ct

14-O

ct

15-O

ct

16-O

ct

17-O

ct

18-O

ct

19-O

ct

20-O

ct

21-O

ct

22-O

ct

23-O

ct

24-O

ct

25-O

ct

26-O

ct

27-O

ct

28-O

ct

29-O

ct

30-O

ct

31-O

ct

Valid RTD Under-supply Infeasibility Load Conformance Correctable Infeasibilities

0%

10%

20%

30%

40%

50%

1-O

ct

2-O

ct

3-O

ct

4-O

ct

5-O

ct

6-O

ct

7-O

ct

8-O

ct

9-O

ct

10-O

ct

11-O

ct

12-O

ct

13-O

ct

14-O

ct

15-O

ct

16-O

ct

17-O

ct

18-O

ct

19-O

ct

20-O

ct

21-O

ct

22-O

ct

23-O

ct

24-O

ct

25-O

ct

26-O

ct

27-O

ct

28-O

ct

29-O

ct

30-O

ct

31-O

ct

Valid FMM Under-supply Infeasibility Correctable Infeasibilities

EIM Price trends

Slide 54

Transfer capabilities in EIM areas

Slide 55

Market Update

Slide 56

Good price convergence between IFM and RTD in

September and October.

RT prices higher than DA prices for both NP 15 and SP 15

in September but lower than DA in SP15 in October.

Insufficient upward ramping capacity in ISO increased in

October.

Insufficient downward ramping capacity remained low in

2016.

Congestion revenue rights market revenue inadequacy

without including auction revenues.

Congestion revenue rights market revenue sufficiency

including auction revenues.

Exceptional dispatch volume in the ISO area continued at low

levels.

Daily exceptional dispatches by reason

Real-time Bid cost recovery dropped in October

Bid cost recovery (BCR) by Local Capacity Requirement area

Minimum online commitment (MOC)

Pmax of MOC Cleared Units

Enforcement of minimum online commitments in

September and October

MOC NameNumber (frequency) of hours in


Humboldt 7110 1436

MOC TABLE MTN 504

HNTBH 7820 187

Orange County 7630 134

MOC East Nicolaus 4385234 125

SCIT MOC 67

MOC NP15 11

MOC SAN ONOFRE BUS 10

SDGE 7820 3

IFM under-scheduling of solar generation

IFM under-scheduling of wind generation declined in


Renewable (VERS) schedules including net virtual supply

and aligns with VER forecast in September and October

http://www.caiso.com/Pages/documentsbygroup.aspx?GroupID=EFF75C

2E-F28E-4087-B88B-8DFFAED828F8

http://www.caiso.com/Pages/documentsbygroup.aspx?GroupID=EFF75C2E-F28E-4087-B88B-8DFFAED828F8

RTD renewable (VERS) curtailment rose since August

RTD renewable (VERS) curtailment versus avoided

curtailment

Hourly distribution of maximum RTD renewable (VERS)

curtailment in October

Wind, solar and hydro production

Monthly wind (VERS) downward flexibility in FMM

Slide 77

Monthly solar (VERS) downward flexibility in FMM

Slide 78

Monthly solar (VERS) downward flexibility in FMM from

11 AM to 5 PM

Slide 79

ISO area RTCO and RTIEO remains at relatively low levels in

September and October.

2015 2016 (YTD)

RTCO $55,489,221 $49,049,744

RTIEO $13,817,548 $380,581

Total Offset $69,306,769 $49,430,324

Price correction events increased in September and October

0

1

2

3

4

5

6

7

8

9

10

Jan

-15

Feb

-15

Mar

-15

Ap

r-1

5

May

-15

Jun

-15

Jul-

15

Au

g-1

5

Sep

-15

Oct

-15

No

v-1

5

De

c-1

5

Jan

-16

Feb

-16

Mar

-16

Ap

r-1

6

May

-16

Jun

-16

Jul-

16

Au

g-1

6

Sep

-16

Oct

-16

Co

un

t o

f Ev

ents

Process Events Software Events Data Error Events Tariff Inconsistency

EIM BCR in September and October

EIM Exceptional Dispatch in September and October

Day-ahead load forecast

0.0%

0.5%

1.0%

1.5%

2.0%

2.5%

3.0%Jan

Feb

Ma

r

Ap

r

Ma

y

Jun

Jul

Au

g

Se

p

Oct

No

v

De

c

2014 2015 2016

MA

PE

Slide 84

Day-ahead peak to peak forecast accuracy

0.0%

0.5%

1.0%

1.5%

2.0%

2.5%

3.0%

3.5%Jan

Fe

b

Ma

r

Ap

r

Ma

y

Jun

Jul

Au

g

Se

p

Oct

No

v

De

c

2014 2015 2016

MA

PE

Slide 85

Day-ahead wind forecast

0.0%

1.0%

2.0%

3.0%

4.0%

5.0%

6.0%

7.0%

8.0%

9.0%

10.0%Jan

Fe

b

Ma

r

Ap

r

Ma

y

Jun

Jul

Au

g

Se

p

Oct

No

v

De

c

2014 2015 2016

MA

E

Slide 86

Day-ahead solar forecast

0.0%

2.0%

4.0%

6.0%

8.0%

10.0%

12.0%

14.0%Jan

Fe

b

Ma

r

Ap

r

Ma

y

Jun

Jul

Au

g

Se

p

Oct

No

v

De

c

2014 2015 2016

MA

E

Slide 87

Real-time wind forecast

0.0%

0.5%

1.0%

1.5%

2.0%

2.5%

3.0%

3.5%

4.0%

4.5%Jan

Fe

b

Ma

r

Ap

r

Ma

y

Jun

Jul

Au

g

Se

p

Oct

No

v

De

c

2014 2015 2016

MA

E

Slide 88

Real-time solar forecast

0%

1%

2%

3%

4%

5%

6%Jan

Fe

b

Ma

r

Ap

r

Ma

y

Jun

Jul

Au

g

Se

p

Oct

No

v

De

c

2014 2015 2016

MA

E

Slide 89

Real-time solar forecast

0%

1%

2%

3%

4%

5%

6%

Oct

2014 2015 2016 2016_withCurtailedMW

MA

E

2016’s October MAE

becomes more comparable

to previous years when the

Curtailed Solar MW are

added back into Actuals.

Slide 90

Load Forecast Adjustments

Gabe Murtaugh

Sr. Market Monitoring Analyst,

Department of Market Monitoring

Slide 91

Growth in EIM transfer capacity significantly increases

market competiveness.

Slide 92

Puget

300 MW300 MW

PacifiCorpWest

126 MW85 MW

CAISO 899 MW

872 MWNV

Energy

924 MW

1,874 MW

APS

PacifiCorpEast

468 MW

710 MW

0 MW

293 MW

216 MW 321 MW

Total average transfer capacity (May-Oct 2016)

Congestion into EIM areas is very infrequent.

Puget1%

(187 MW)

1%(205 MW)

PacifiCorpWest

20%

(27 MW)

2%(221 MW)

CAISO 2% MW(790 MW)

.2%

(611 MW)

NVEnergy

0%

.3% (143 MW)

APS

PacifiCorpEast

.3% (156 MW)

7% (463 MW)

4% (105 MW)

7%(150 MW)

1% (119 MW)

Frequency of congestion in 15-minute market (May-Oct 2016)*

* Average transfer

MW during

congested intervals

in parentheses.

23% (0 MW)

Slide 7

EIM areas separated by congestion from the ISO

only 1-3 percent of intervals.

Slide 94

Settlement prices in Arizona largely reflected prices in

the ISO during October.

Slide 95

$0

$10

$20

$30

$40

$50

$60

$70

$80

$90

$100

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24

Av

era

ge h

ou

rly p

rice (

$/M

Wh

)

Arizona Public Service settlement price

Southern California Edison settlement price

Bilateral price benchmark

Settlements prices in Puget Sound were lower than

the ISO and reflected PacifiCorp West prices.

Slide 96

$0

$10

$20

$30

$40

$50

$60

$70

$80

$90

$100

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24

Av

era

ge h

ou

rly p

rice (

$/M

Wh

)

Pacific Gas and Electric settlement price

Puget Sound Energy settlement price

PacifiCorp West settlement price

Bilateral price benchmark

Positive load adjustments were more frequent in NV

Energy and the ISO, while negative load adjustments

were more frequent in the PacifiCorp areas.

Slide 97

Percent of

intervals

Average

MW

Percent of

total load

Percent of

intervals

Average

MW

Percent of

total load

California ISO

15-minute market 44% 471 1.4% 14% -274 1.1% 169

5-minute market 56% 438 1.4% 27% -300 1.1% 162

PacifiCorp East

15-minute market 5% 91 1.6% 42% -101 1.9% -38

5-minute market 9% 88 1.5% 63% -125 2.4% -71

PacifiCorp West

15-minute market 3% 38 1.5% 43% -49 2.2% -20

5-minute market 4% 42 1.7% 49% -58 2.6% -27

NV Energy

15-minute market 48% 132 2.3% 1% -171 3.6% 62

5-minute market 44% 95 1.7% 11% -83 1.7% 32

Positive load adjustments Negative load adjustments Average

hourly bias

MW

Load adjustments in NV Energy tended to be greatest

in the late afternoon, while PacifiCorp East adjusted by

the greatest quantity in the morning.

Slide 98

-150

-100

-50

0

50

100

150

200

250

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24

MW

15-minute market (PacifiCorp East) 5-minute market (PacifiCorp East)

15-minute market (PacifiCorp West) 5-minute market (PacifiCorp West)

15-minute market (NV Energy) 5-minute market (NV Energy)

Policy Update

Brad Cooper

Manager, Market Design and Regulatory Policy

Slide 99

Ongoing policy stakeholder initiatives

• Contingency modeling enhancements

– Technical analysis results targeted Dec

– Stakeholder call on technical analysis targeted Dec

– May 2017 Board Meeting

• Generator contingency and remedial action scheme

modeling

– Revised straw proposal targeted Jan 2017

– Jul 2017 Board Meeting

• Stepped transmission constraints

– New schedule being developed

– Board Meeting TBD

Slide 100

Ongoing policy stakeholder initiatives (continued)

• Flexible resource adequacy criteria and must-offer

obligation – phase 2

– Stakeholder call on supplemental issue paper Dec 9

– Revised straw proposal Feb 2017


• Bid cost recovery enhancements

– Draft final proposal Dec 2016

– Q1 2017 Board meeting

– Projected Fall 2018 implementation

• Self schedules BCR allocation

– Added to the bid cost recovery enhancements

initiative

Slide 101

• Commitment Costs and Default Energy Bid Enhancements

– February 2017 Straw proposal

– July 2017 Board Meeting

– 2018 Implementation

• Metering rules enhancements

– Dec 2016 Board Meeting

• Energy storage and distributed energy resources (ESDER)

Phase 2

– Q1 2017 Board Meeting

Slide 102



• Aliso Canyon - Phase 2

– FERC Order accepting filing Nov 28

– Jan 2017 Implementation

• Stakeholder initiatives catalog

– Final 2017 policy initiatives roadmap Dec 15

– Stakeholder call Dec 22

– Feb 2017 EIM Governing Body and Board Meeting

• Frequency response – phase 2

– Issue paper targeted Dec 2016

– Schedule TBD

Slide 103


• Regional integration and EIM greenhouse gas compliance

– Stakeholder meeting on straw proposal Dec 1

– Draft final proposal Jan 5


• Transmission access charge options

– Framework published Dec 6

– Stakeholder meeting Dec 13

– No planned Board action at this time

• Regional resource adequacy

– Framework published Dec 1

– Stakeholder meeting Dec 8

– No planned Board action at this time

Slide 104

Policy stakeholder initiatives coming soon

• Planned to start in Q1 2017

– Resource adequacy enhancements

– Economic and maintenance outages

Slide 105

Release Plan Update

Janet Morris

Director, Program Office

Slide 106

The ISO offers comprehensive training programs

Slide 107

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

Contact us - [email protected]

Date Training

January 11 Welcome to the ISO (webinar)

February 7 Settlements 101 (Folsom)

February 8 Settlements 201 (Folsom)

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

mailto:[email protected]

Release Plan 2016

Slide 108

Implementations by end of 2016

• Demand Response Registration Enhancements

• ADS Client Replacement (Mandatory)

• Acceptable Use Policy - CMRI

Release Plan 2017

Slide 109

Independent 2017

• RTD Local Market Power Mitigation (LMPM) Enhancements

• CRR Clawback Modifications

• MRI-S ACL Groups+ CPG Enhancements (formerly OMAR Replacement)

• PIRP System Decommissioning

• Reactive Power Requirements and Financial Compensation – no system changes

• RIMS Functional Enhancements

• Metering Rules Enhancements

Fall 2017 (tentative, to be confirmed)

• Bidding Rules Enhancements – Part B

• Reliability Services Initiative Phase 1B

• Reliability Services Initiative Part 2

• Commitment Cost Enhancement Phase 3

• EIM 2017 Enhancements

• EIM Portland General Electric (PGE)

Release Plan – 2018 and subject to further planning

Slide 110

Spring 2018

• EIM 2018 Idaho Power Company

Fall 2018 – tentative, subject to impact assessment

• Stepped Transmission Constraints

• Bid Cost Recovery Enhancements

• Generation Contingency and Remedial Action Scheme

• Flexible Resource Adequacy Criteria and Must-offer Obligation Phase 2

• ESDER Phase 2

• Regional Resource Adequacy

• Transmission Access Charge Options

• ADS User Interface Replacement

Subject to further release planning:

• Additional Data Transparency Enhancements (OASIS API changes) – work starting after Fall

2016 release; ISO will make it available for market participants to adopt as they need.

• Contingency Modeling Enhancements

2016 – Demand Response Registration Enhancements

Project Info Details/Date

Application Software Changes

Enhance Demand Response Registration functionality and processes

Develop new registration user interface for DRRS

Develop new APIs for support of enhanced registration processes

BPM Changes Metering

Business Process Changes Automation of internal registration-related processes

Slide 111

Milestone Type Milestone Name Dates Status

Board Approval Board Approval N/A

BPMs Publish Final Business Practice Manuals (Metering) Aug 29, 2016

Post Draft BPM changes (Metering) Aug 04, 2016

External BRSExternal BRS - Enabling Demand Response Phase 2 -

RegistrationJun 04, 2015

Tariff Tariff N/A

Config Guides Config Guide N/A

Tech Spec Tech Specs - DRRS Phase 2 - Registration Sep 17, 2015

Market Sim Market Sim Window Sep 19, 2016 - Nov 18, 2016

Production Activation Post-Mrkt Consol - DRRS Phase 2 - Reg Nov 30, 2016

2016– ADS Client Replacement (Mandatory)



Scope includes updates to work with TLS version 1.0. After

January 6, 2017, all prior supported ADS client versions (which

includes 5.2.8.0 and 5.2.4.0) will be decommissioned and

inaccessible.

Slide 112

ADS Client certified for Windows 7 and 10



BPMs BPMs N/A

External BRS External BRS N/A

Tariff Tariff N/A


Tech Spec Tech Spec N/A

Market Sim Market Sim Window Oct 12, 2016 - Jan 06, 2017

Production Activation ADS TLS Risk Remediation Jan 06, 2017

2016 – Acceptable Use Policy – CMRI



Scope includes enforcement of Acceptable Use Policy for CMRI

services to support the full implementation of 1 call per service per

identity (as designated by certificate) every 5 seconds. An error

code of 429 will be returned for any violation instance of the use

policy.

Slide 113



BPMs BPMs N/A

External BRS External BRS N/A

Tariff Tariff N/A


Tech Spec Tech Spec N/A

Market Sim Market Sim Window Aug 23, 2016 - Sep 23, 2016

Production Activation Acceptable Use Policy - CMRI Jan 06, 2017

2016 CMRI URL Standardization

Service Version #

Existing URL

https://wsstas.caiso.com:4445/sst/runtime.asvc

https://wsstas.ecn.wepex.net:4445/sst/runtime.asvc

Standardized URL

https://ws.caiso.com/sst/cmri

https://ws.ecn.wepex.net/sst/cmri

MarketAwards

v2 Decommission on 12/01/2016 None exists

v3 Decommission on 12/01/2016 Supported

v4 None exists Supported

MarketSchedules




SchedulePrices




ExpectedEnergyAllocationDetails




GreenHouseGasCapData

v1

None exists Supported

EIMInterchangeScheduleData

v1

ResourceMovementPoint

v1

ResourceLevelMovement

v1

EIRForecast v1

ElectricityPriceIndex v1

All other pre Fall 2016 existing services

existing Decommission on 12/01/2016 Supported

https://wsstas.caiso.com:4445/sst/runtime.asvc

https://wsstas.ecn.wepex.net:4445/sst/runtime.asvc

https://ws.caiso.com/sst/cmri

https://ws.ecn.wepex.net/sst/cmri

2016-2017 Projects - Major Milestones Summary

Project Market Simulation Deployment/Activation Decommissioning

Demand Response Registration Enhancements Completed Completed N/A

ADS Client Replacement (Mandatory)

ADS Client ver 6.0.0.0

made available for testing in

MAP Stage on 10/12/2016

ADS Client production-level

version 6.0.x available as of

10/28/2016

Availability of production level

ADS version started a grace

period of approx 2 months for

market participants to transition

to the new version

After January 6, 2017, all prior

supported ADS client versions (which

includes 5.2.8.0 and 5.2.4.0) will be

decommissioned and inaccessible.

Acceptable Use Policy - CMRI Completed Jan 6, 2017 N/A

ACL Groups (formerly OMAR Replacement and

PIRP Decommissioning)TBD TBD

ISO decommissions PIRP based upon a

two-month buffer period between ACL

group functionality being active in

Production.

MRI-S Customer Partnership Group identified

enhancements (formerly OMAR Replacement)TBD TBD

OMAR will be decommissioned after a

four month grace period starting when

MRI-S enhancements deploy to MAP

Stage (market simulation).

2017 - Real Time Dispatch Local Market Power Mitigation



• CMRI – Display mitigated bids from RTD process

• OASIS (Open Access Sametime Information System): Display RTD

reports for Market Clearing, the Pnode clearing, similar to current

RTPD reports

• RTM (Real Time Market)

• RTPD: Perform the LMPM run as an integral part of the binding

interval RTPD run

• RTD: Proposed mitigation in RTD run would work the same way

as the current RTPD run

BPM Changes

• Energy Imbalance Market (EIM): under the proposed RTD method,

bids are not necessarily mitigated for the whole hour

• RTD MPM will work the same way as the current RTPD MPM

Business Process Changes

• Manage Markets & Grid

• ATF – System Operations: Add MPM Application to Real Time and

annotate inputs and outputs

• ATF – System Operations, Real Time: Add MPM to diagram with inputs

and outputs

• Level II – Manage Real Time Operations – maintain balancing area

Slide 116

2017 - Real Time Dispatch Local Market Power Mitigation (cont.)

Slide 117

ProjectCMRI OASIS ADS

RTD LMPM Update (add RTD results):

MPMResults v3

Update (add RTD results)-

- PRC_MPM_RTM_LMP

- PRC_MPM_RTM_NOMOGRAM

- PRC_MPM_RTM_NOMOGRAM_CMP

- PRC_MPM_RTM_FLOWGATE

- PRC_MPM_CNSTR_CMP

- PRC_MPM_RTM_REF_BUS

-ENE_MPM

N/A


Board Approval Board of Governors (BOG) approval Mar 24, 2016

BPMs Posted Market Operations BPM PRR 945 Nov 04, 2016

Post draft EIM BPM Dec 29, 2016

External BRS Post External BRS Apr 05, 2016

Tariff Received FERC approval Nov 08, 2016

Config Guides Configuration Guide N/A

Tech Spec Publish Technical Specification - OASIS Apr 08, 2016

Publish Technical Specification - CMRI Apr 14, 2016

Market Sim Market Sim Window Jan 17, 2017 - Feb 03, 2017

Production Activation RTD - Local Market Power Mitigation Enhancement Mar 01, 2017

2017 – Congestion Revenue Rights (CRR) Clawback Modifications



MQS/CRR Clawback:

If import bid <= day-ahead price, then the import is not considered a virtual award.

If export bid >= day-ahead price, then the export is not considered a virtual award.

If an import/export bid/self-schedule in real-time market is less than the day-ahead

schedule, then the difference shall be still subject to CRR Clawback rule.

CRR Clawback rule should include convergence bids cleared on trading hubs and

load aggregation points in the flow impact used to determine if the 10% threshold

is reached.

Inform Market Participants of CRR annual allocation/auction for 2017.

BPM Changes Market Operations Appendix F

Business Process Changes TBD

Slide 118


Board Approval Board of Governors Approval Jun 28, 2016

BPMs Publish Final Business Practice Manuals Jan 30, 2017

External BRS Post External BRS Nov 29, 2016

Tariff File Tariff Jan 20, 2017

Receive FERC order Mar 21, 2017

Production Activation CRR Clawback Modification Apr 01, 2017

2017 - MRI-S ACL Groups+ CPG Enhancements



The MRI-S metering (MRI-S) application cannot currently support ACL (Access Control

List) groups functionality for defining a subset of resources belonging to an SCID.

Enhancements to the Application Identity Management (AIM) application will enable the

use of ACL groups for SCID-level read-only access for MRI-S.

Conducted a Customer Partnership Group meeting on October 20 and reviewed

proposed solutions.

BPM Changes None

Business Process ChangesPotential Level-II business process changes under –

• Manage Market & Reliability Data & Modeling

• Manage Operations Support & Settlements

Slide 119



BPMs Metering BPM Changes N/A

External BRS Post External BRS Nov 14, 2016

Tariff Pre-Tariff Filing QRB N/A

Tech Spec Publish Tech Specs Nov 02, 2016

Market Simulation Phase 1 - ACL Groups TBD

Phase 2 - MRI-S Metering Enhancements TBD

Production Activation Phase 1 - ACL Groups TBD

Phase 2 - MRI-S Metering Enhancements TBD

MRI-S ACL Groups + CPG Enhancements

Slide 120

* ACL group creation to filter for a read only role at the resource level is not

currently available

# System Summary Status Estimated Fix

Date

1 MRI-S CIDI 183777, 183993 - MRI-S for Metering Limitation of

100,000 records.

Under review See previous slide

2 MRI-S Option to choose UOM is missing on the UI

3 MRI-S CIDI 184018 - Time zone is missing on the UI

4 MRI-S CIDI 183777, 183993 - Modification to AUP policy on data

retrieval to include querying by last updated time

5 MRI-S Option to request for data in various time interval in UI

6 MRI-S Ability to view log files within the same organization

7 MRI-S Ability to provide SC ID in the data retrieve request

MRI-S *ACL Group – filter read-only at the resource level In process See previous slide

2017 – PIRP DecommissioningProject Info Details/Date

Application Software Changes:

PIRP/CMRI

• Forecast Data Reporting (resource-level) that was performed in PIRP will be done in

CMRI. Rolling Hour Ahead, Locked Hour Ahead, and Rolling Day-Ahead forecasts.

• PIRP Decommissioning to occur in 2017

• CMRI to receive the Electricity Price Index for each resource and publish it to the

Market Participants.

• 60 Day PIRP / CMRI parallel production to start when AIM/ACL becomes available.

BPM Changes CMRI Technical Specification; New APIs will be described.

Data Transparency

• Independent changes, won’t

impact existing services

• Will be made available in

Production and cutover

schedule is discretionary

Atlas Reference:

1. Price Correction Messages (ATL_PRC_CORR_MSG)

2. Scheduling Point Definition (ATL_SP)

3. BAA and Tie Definition (ATL_BAA_TIE)

4. Scheduling Point and Tie Definition (ATL_SP_TIE)

5. Intertie Constraint and Scheduling Point Mapping (ATL_ITC_SP)

6. Intertie Scheduling Limit and Tie Mapping (ATL_ISL_TIE)

Energy

• EIM Transfer Limits By Tie (ENE_EIM_TRANSFER_LIMITS_TIE)

• Wind and Solar Summary (ENE_WIND_SOLAR_SUMMARY)

Prices

• MPM Default Competitive Path Assessment List (PRC_MPM_DEFAULT_CMP)

Business Process Changes MPs will receive the VER reports from CMRI rather than PIRP.

Slide 121

2017 – PIRP Decommissioning

Slide 122



BPMs Publish Draft Business Practice Manuals (Market Instruments; PRR 936) Sep 06, 2016

External BRS External Business Requirements Jun 29, 2015

Tariff Tariff Filing Activities N/A

Config Guides Settlements Configuration N/A

Tech Spec Publish Technical Specifications (CMRI: PIRP Decommissioning) Feb 05, 2016

Publish Technical Specifications (CMRI; Wind and Solar) Apr 15, 2016

Market Sim CMRI Reports; VER Forecast & EPI (Fall 2016 Release) Aug 23 - Sep 23, 2016

PIRP Decommissioning TBD

Production Activation CMRI Reports; VER Forecast & EPI (Fall 2016 Release) Oct 01, 2016

AIM / ACL Production Deployment TBD

OASIS API Enhancements; 9 Reports TBD

PIRP Decommissioning TBD

2017 – Reactive Power Requirements and Financial Compensation


Application Software Changes None

BPM Changes

Generator Interconnection and Deliverability Allocation Procedures

• Reactive power delivery interconnection condition for asynchronous resources.

Generator Interconnection Procedures

• Reactive power delivery interconnection condition for asynchronous resources.

Generator Management

• Generators’ AVR Requirements.


Develop Infrastructure (DI) (80001)

• Level II - Manage Generator Interconnection Process (GIP) (Logical Group):

Slide 123


BPMs Draft BPM changes TBD

Post Draft BPM changes TBD

Publish Final Business Practice Manuals TBD

Tariff File Tariff 12/5/2016

Tariff Receive FERC order 2/1/2017

Production Activation Reactive Power and Financial Compensation activation 4/1/2017

2016 – RIMS Functional Enhancements

Project Info Details/Date Status

Application Software ChangesFunctional enhancements resulting from the Customer Partnership Group CPG.

More details to be provided in the future.

BPM Changes

Generator Interconnection and Deliverability Allocation Procedures

Generator Interconnection Procedures

Managing Full Network Model

Metering

Generator Management

Transmission Planning Process

Customer Partnership Group 10/16/15

Application and Study Webinar 3/31/16

Slide 124


Board Approval Board approval not required N/A

BPMs Generator Interconnection and Delivery Allocation Apr 29, 2016

External BRS External BRS not Required N/A

Tariff No Tariff Required N/A

Config Guides Configuration Guides not required N/A

Tech Spec No Tech Specifications Required N/A

Production Activation RIMS5 App & Study Mar 21, 2016

RIMS5 Queue Management, Transmission and Generation TBD

2017 – Metering Rules Enhancements


Application Software Changes N/A

BPM Changes

Metering

• EIM BPM will be updated to explain Metering data reporting access

based on transitions from ISOME to SCME (shall transition to

submission of SQMD meter data to Metering Data submission portal) or

SCME to ISOME (shall be able to review historical meter data in MRI-S

when resource was SCME).

Definitions & Acronyms BPM Changes

• New Tariff and Business Process/System acronyms.


• Manage Transmission & Resource Implementation

• Manage Market & Reliability Data & Modeling (MMR) (80004)

• ISO Meter Certification (MMR LII)

• Metering Systems Access (Production) (MMR LII)

• Metering System Configuration for Market Resources (MMR

LII)

• Station Power Implementation (MMR LIII)

• Application Flow - Billing & Settlements

• Analyze Missing Measurement Report (MOS LIII)

• Manage Market Billing & Settlements (MOS LII)

• Manage Market Quality System (MOS LII)

• Manage Rules of Conduct (MOS LII)

• Meter Data Acquisition & Processing (MOS LII)

• SCME Self Audit (MOS LII)

Slide 125

2017 – Metering Rules Enhancements

Slide 126


Board Approval Obtain Board of Governors Approval Dec 14, 2016

BPMs Metering BPM TBD

Energy Imbalance Market BPM TBD


External BRS External Business Requirements N/A

Tariff File Tariff N/A

Receive FERC order N/A

Config Guides Settlements N/A

Tech Spec Tech Specs N/A

Market Sim Market Sim Window N/A

Production Activation Metering Rules Enhancements Apr 01, 2017

Fall 2017 - Bidding Rules Enhancements – Part B

Slide 127



• MasterFile:

• Provide ability to submit requests for new fuel regions (Policy Section 8.1.1.3)

• Include resource-specific start-up electricity costs in proxy costs based on wholesale

projected electricity price, unless resource verifies costs incurred are retail rates (RDT

change)

• Allow ability to submit a weighting when using a more than one fuel region.

• Automation of the Aliso Canyon process for creating NEW Fuel Regions

• OASIS:

• Publish fuel regions (public information)

Business Process Change

• Manage Transmission & Resource Implementation

• Manage Entity & Resource Maintenance Updates

• Manage Full Network Model Maintenance

• Manage Market Quality System (MQS)

BPMs Market Instruments, Market Operations, Reliability Requirements


Board Approval BOG Approval Mar 25, 2016




External BRS Post External BRS Dec 15, 2016

Tariff File Tariff TBD

Receive FERC order TBD

Config Guides Prepare Draft Configuration Guides Apr 01, 2017

Tech Spec Create ISO Interface Spec (Tech spec) Apr 01, 2017

Market Sim Market Sim Window Jul 05, 2017 - Jul 31, 2017

Production Activation Bidding Rules Part B Oct 01, 2017

Fall 2017 - Reliability Services Initiative Phase 1BProject Info Details/Date Status


Developments under consideration include:

Scope:• Default flexible qualifying capacity provisions for phase 2 consideration (we might need data collection

performed in order to support RSI Phase 2

• Redesign of Replacement Rule for System RA and Monthly RA Process

• RA Process and Outage Rules for implementation for 2017 RA year

• Scope not delivered in RSI Phase 1A (Grandfathered Contracts, RAAM Decommissioning – SCP & CPM

screens from RAAM to CIRA, Acquired Contracts, OASIS reporting, web services related to APIs for CSP

offers, APIs for Generic/Flex Substitutions, and Release of Generic/Flex Subs – UI & API)

Impacted Systems:• CIRA

• OASIS

• Integration (B2B)

• Settlements

• Decommission RAAM

Business Process Changes Manage Market & Reliability Data & Modeling

Slide 128


Board Approval Board Approval May 12, 2015

BPMs Draft BPM Changes - Outage Mgmt, Reliability Reqmts TBD






Config Guides Config Guide Apr 01, 2017



Production Activation Reliability Services Initiative Phase 1B Oct 01, 2017



Scope:

1. Clarify use-limited registration process and documentation to determine opportunity

costs

2. Each submission evaluated on a case-by-case basis to determine if the ISO can

calculate opportunity costs

• ISO calculated; Modeled limitation

• Market Participant calculated; Negotiated limitation

3. Enhanced definition of “use-limited” in response to FERC’s rejection of the proposed

definition in Cost Commitment Enhancements Phase 2

4. Change Nature of Work attributes (Outage cards)

1. Modify use-limited reached for RAAIM Treatment

2. Add new demand response nature of work attribute for RDRR and PDR

5. Market Characteristics

1. Maximum Daily Starts

2. Maximum MSG transitions

3. Ramp rates

Impacted Systems:

1. CIRA

2. CMRI

3. IFM/RTN

4. SIBR

5. MasterFile

6. OASIS

7. OMS

8. Settlements

BPM ChangesMarket Instruments, Outage Management, Reliability Requirement, Market Operations,

Settlements & Billing

Business Process ChangesLevel II – Manage Reliability Requirements

Level II – Manage Day Ahead Market

Slide 129

Fall 2017 - Commitment Cost Enhancements Phase 3

Fall 2017 - Commitment Cost Enhancements Phase 3 (cont.)


Board Approval Board of Governors (BOG) Approval Mar 25, 2016







Config Guides Config Guide Apr 01, 2017



Production Activation Commitment Costs Phase 3 Oct 01, 2017

Fall 2017 – EIM Enhancements 2017



Addresses the following enhancements identified by policy, operations,

technology, business and market participants.

The following requirements are being defined:

• EIM Entity access reports

• BAAOP provisioning in AIM

• EIM Data report enhancements to support EIM Entity settlements

• Joint Owned Units modeling

• Allow MSG resource to send actual configuration in telemetry for RTM

• Comprehensive model for startup and transition energy in DAM, RTM,

RTBS, MQS

BPM Changes TBD

Business Process Changes TBD

Slide 131

Fall 2017 – EIM Enhancements 2017 (cont.)


Board Approval Obtain Board of Governors Approval N/A




External BRS External BRS complete Dec 30, 2016



Config Guides Design review - BPM and Tariff SMEs Apr 01, 2017

Tech Spec Publish Technical Specifications Apr 06, 2017


Production Activation EIM Enhancements 2017 Oct 01, 2017

Fall 2017 – EIM Portland General Electric


Application Software Changes Implementation of Portland General Electric as an EIM Entity.

BPM ChangesEIM BPM will be updated to reflect new modeling scenarios identified

during PGE implementation and feedback from PGE.

Market Simulation

ISO promoted market network model including PGE area to non-

production system and allow PGE exchange data in advance of Market

Simulation.

Parallel Operations August 1 – September 30, 2017

Slide 133


Board Approval Board approval not required N/A

BPMs BPMs N/A

External BRS No external BRS N/A

Tariff Tariff filing at FERC N/A

Config Guides Settlements N/A

Tech Spec Tech Specs N/A

Market Simulation Market Sim Environment Window Jun 29, 2017 – Jul 31, 2017

Production Activation EIM - Portland General Electric Oct 01, 2017

Annual Functional Release Lifecycle

Slide 134

The ISO has published the Annual Functional Release Lifecycle draft on the

Release Planning page

• http://www.caiso.com/Documents/AnnualFunctionalReleaseLifecycle.pdf

This document describes the planning through execution phases of the ISO annual

functional release lifecycle process including

• Introduction

• Background

• Scope

• Annual Functional Release Lifecycle

• Exceptions

• Contingency Planning

• External Deliverables

• Process Interfaces

• Stakeholder Implementation Interactions

The ISO encourages Market Participants to review the document and provide any

feedback.

http://www.caiso.com/Documents/AnnualFunctionalReleaseLifecycle.pdf

Market Performance and Planning Forum

2017 Schedule – Mark Your Calendars

• January 18

• March 14

• May 16

• July 18

• September 19

• November 14

Questions or meeting topic suggestions:

Submit through CIDI - select the “Market Performance and

Planning Forum” category

Slide 135

Market Performance and Planning Forum · Market Performance and Planning Forum Agenda –December...

Documents

Transcript of Market Performance and Planning Forum · Market Performance and Planning Forum Agenda –December...