market performance and planning forum - california review key market performance topics • share...

Market Performance and

Planning Forum

May 16, 2017

Objective: Enable dialogue on implementation

planning and market performance issues

• Review key market performance topics

• Share updates to 2017 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 – May 16, 2017

Time: Topic: Presenter:

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

10:05 – 10:20 May 3 CAISO Stage 1 System Emergency Tim Beach

10:20 – 12:00 Market Performance and Quality Update Guillermo Bautista Alderete

Amber Motley

James Lynn

12:00 – 1:00 Lunch

1:00 – 1:30 Policy Update Brad Cooper

1:30 – 2:00 Flexible Capacity Update Amelia Blanke

David Robinson

2:00 – 3:00 Release Update Adrian Chiosea

Janet Morris

Slide 3

May 3 CAISO Stage 1 System Emergency

Tim Beach

Shift Manager, Operations

Slide 4

May 3, 2017 Stage 1 Emergency Summary

• Peak load at 17:45 with sufficient capacity and operating

reserves

• Actual Net Scheduled Interchange (including dynamics) was

~1,150 MW below Day Ahead schedules

• ~600 MW of forced generation outages

• The HA market awarded 1,230 MW of supplemental energy

on the interties for HE20 (19:00 to 20:00) but 830 MW of that

was declined

• At 19:01 a Stage 1 Emergency was declared and all DR

verbally dispatched (PDR & RDRR)

– Two Contingency dispatches issued, RDRR enabled in the

market in the second dispatch (and actually dispatched

during manual implementation of DR.)

• Operating reserves recovered at 19:56

• 21:00 Stage 1 Emergency terminatedSlide 5

Market Performance and Quality Update

James Lynn

Senior Advisor, Market Settlements Design

Amber Motley

Manager, Short Term Forecasting

Guillermo Bautista Alderete, Ph.D.

Director, Market Analysis and Forecasting

Congestion Revenue Right Analysis Effort

CRR Auction Effort

• Initiative is split in two phases

– Analysis phase

– Policy phase

• CRR Working group session held on April 18 to discuss

the Analysis scope

• Analysis phase needed to have in-depth analysis of the

auction efficiency, and identify drivers and guide the

policy phase

Slide 8

Market Analysis done in three phases along the

following areas

• Auction results

• Participation

• Transparency

• Modeling

– Accuracy

– ISO practices/procedures

– Market events

– Systemic differences

• Constraint by constraint analysis

– Analyze constraints that did not bind in the auction but had

payouts in the DAM

– Analyze constraints with large payouts

• Impact of changes over timeSlide 9

Over Supply Update

Frequency of negative system prices has steadily

increased year over year

Slide 11

0%

5%

10%

15%

20%

25%

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

Freq

uen

cy

2014 2015 2016 2017

Distribution of negative prices have shifted from early

morning hours to midday hours*

Slide 12* Metric of 2017 may be over-estimated since it includes only January through April.

0%

5%

10%

15%

20%

25%

30%

35%

40%

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

Freq

uen

cy

2014 2015 2016 2017

ISO total monthly VERS schedules and forecasts

IFM under-scheduling of wind generation

Monthly wind (VERS) downward flexibility in FMM

Slide 15

Monthly solar (VERS) downward flexibility in FMM from

11 AM to 5 PM

Slide 16

Hydro production higher than recent historical production

RTD renewable (VERS) curtailment continued to increase

in March and April

The trend of curtailments is accelerating

Slide 19

0

10,000

20,000

30,000

40,000

50,000

60,000

70,000

80,000

90,000

May Jun

Jul

Au

g

Sep

Oct

No

v

Dec Jan

Feb

Mar

Ap

r

May Jun

Jul

Au

g

Sep

Oct

No

v

Dec Jan

Feb

Mar

Ap

r

May Jun

Jul

Au

g

Sep

Oct

No

v

Dec Jan

Feb

Mar

AP

R

2014 2015 2016 2017

ENER

GY

CU

RTA

ILM

ENTS

(M

WH

)

Local Economical System Economical Local ED System ED Self Sch System Self Sch Local

Solar production and net load records have been

observed this Spring

Slide 20

. Saturday May 13 Sunday May 14

Maximum load 26,120 MW at 20:36 25,644 MW at 20:36

Minimum load 20,342 MW at 03:44 19,428 MW at 03:58

Minimum net load 8,804 MW at 14:44 8,493 MW at 13:03

How are curtailments determined?

• All curtailments are driven by prices, either economical bids or

penalty prices.

• Effective April 11, 2017 the step-size of the power balance constraint

relaxation for over-supply conditions was reduced to 30 MW.

• Only April 30 and May 8 have observed self schedule curtailments

and by less than 100MW

Slide 21

TOR/ETC

IFM self schedule

RMT

Price taker

PBC violation

Economical bids

Hydro production is trending upward for Spring but still

lower than historical high hydro year of 2006

0

1,000

2,000

3,000

4,000

5,000

6,000

Ja

n

Feb

Mar

Ap

r

May

Ju

n

Ju

l

Au

g

Se

p

Oct

No

v

De

c

Ja

n

Feb

Mar

Ap

r

May

Ju

n

Ju

l

Au

g

Se

p

Oct

No

v

De

c

Ja

n

Feb

Mar

Ap

r

May

Ju

n

Ju

l

Au

g

Se

p

Oct

No

v

De

c

Ja

n

Feb

Mar

Ap

r

May

Ju

n

Ju

l

Au

g

Se

p

Oct

No

v

De

c

Ja

n

Feb

Mar

Ap

r

2006 2014 2015 2016 2017

GW

h

Hydro vs. Solar Monthly Production

Hydro Solar

Self scheduled interties in the real-time market remain high

Flexible Ramp Update

Flexible Ramp Product Up Requirement

Slide 25

Flexible Ramp Product Down Requirement

Slide 26

Flexible Ramp Product Up Awards

Slide 27

Flexible Ramp Product Down Awards

Slide 28

How is FRP settled?

Slide 29

Forecasted

Upper limit

Lower limit

Net system demand at t

t+1 (advisory interval)t (binding interval) Time

Net system demand

Minimum

requirement

Demand curve

Demand curve

Forecasted movement known with certainty - e.g. self-schedule supply expected to ramp (up) from t to t+1; or load forecast that’s known to increase

from time t to t+1, requires an equivalent ramp up.

Uncertainty movement (forecast error)- the requirements for this is derived from demand curve modeling based on historical forecast errors

Demand Curve to Meet FRD Uncertainty

Slide 30

t (binding interval) t+1 (advisory interval)

Forecast net demand

FRU forecasted net load change

FRD uncertainty FRD max expected forecast error

t (binding interval) t+1 (advisory interval)

Forecast net demand

FRU forecasted net load change

FRD max expected forecast error

No FRD procured

First figure – need to procure FRD uncertainty; second figure – no need to procure

Forecasted Movement has a direct settlement,

uncertainty is awarded and allocated as an uplift

Binding Advisory …

B A …

Forecasted Movement (Market)

Uncertainty

A ARTD1

RTD2

Slide 31

• Supply and Interties resources (CC 7070)

– Separate FMM and Incremental RTD forecasted

movement qty

– (-1) * Forecasted Movement Qty * (FRU price - FRD

price)

– Rescind portion of forecasted movement in case of

deviation (UIE/OA)

• Load resources (CC 7076)

– Allocate to SCs based on SC’s metered EIM Demand

or metered CAISO Demand

Forecasted movement settlement

Slide 32

• Dispatchable Resources (CC 7071: FRU & CC 7081: FRD)

– Uncertainty award for FRU/FRD in FMM is settled at FMM FRU/FRD price

– Uncertainty award for FRU/FRD in RTD which is incremental to FMM uncertainty award is settled at the RTD FRU/FRD price

– Price has breakdown, which differentiates BAA constraint from EIM Area constraint contribution

– Rescind portion of Uncertainty Capacity where resource deviation (UIE/OA) overlaps

Uncertainty Award Settlement

Slide 33

FRP Uncertainty Cost Allocation

Slide 34

I

E

Flexible ramping up Flexible ramping down

E

I

I

E E

I

Total

Uncertainty

MW by FRP

Constraint

Category’s

Uncertainty

MW

Allocate to

individual resource

Uncertainty

Forecasted Movement Settlement ISO – From

November 1 to February 28, 2017

Scheduled Settlement

Correction

Slide 35

Uncertainty Up Settlement – From Jan 2015 – April

2017

Slide 36

Once normalized for capacity procured, FRP uncertainty

settlements in the same range as in prior months

Slide 37

FRP Up Uncertainty Payment Amount in EIM areas

Slide 38

FRP Down Uncertainty Payment Amount in EIM areas

Slide 39

FRP Up Payment – Hourly Distribution correlated to

hourly profile

Slide 40

FRP Down Payment – Hourly Distribution correlated to

hourly profile

Slide 41

Persistency Model Enhancement

Current Data Transfer Time Needed for External

Forecast Service Provider (FSP)

Slide 43

CAISO is working on an enhancement based on

persistency

• For Wind

– Recommendation is to use the simple lag

persistence model.

• For Solar

– Recommendation is to use a persistence contour

model.

Slide 44

Accounting of Market Dispatches/Curtailments of

Renewables is also considered

• Market software will also handle cases of market

dispatches or curtailments of renewables

– As soon as the market dispatches an EIR resource,

logic will be included to take into consideration the

supplemental dispatch of resource to be the EIR

Resource Forecast.

Slide 45

Mean Average Percent Error for January 2017

Slide 46

PCM and Lag methods reduced External FSP MAPE by 50% for

RTD

Wind Solar

External FSP 6.5% 8.5%

Lag 3.2% 5.9%

PCM 3.5% 4.9%

Forecast Type

RTD

Total Mae Value for RTD SOLAR Forecast

Slide 47

0%

1%

2%

3%

4%

5%

6%0

:00

1:1

0

2:2

0

3:3

0

4:4

0

5:5

0

7:0

0

8:1

0

9:2

0

10

:30

11

:40

12

:50

14

:00

15

:10

16

:20

17

:30

18

:40

19

:50

21

:00

22

:10

23

:20

MA

E

Unit A

lag pcm

0%

2%

4%

6%

8%

10%

12%

0:0

0

1:1

0

2:2

0

3:3

0

4:4

0

5:5

0

7:0

0

8:1

0

9:2

0

10

:30

11

:40

12

:50

14

:00

15

:10

16

:20

17

:30

18

:40

19

:50

21

:00

22

:10

23

:20

MA

E

Unit B

lag pcm

0%

2%

4%

6%

8%

10%

12%

0:00

1:25

2:50

4:15

5:40

7:05

8:30

9:55

11:2

012

:45

14:1

015

:35

17:0

018

:25

19:5

021

:15

22:4

0

MAE

Unit C

lag pcm

0%

2%

4%

6%

8%

10%

12%

14%

0:00

1:25

2:50

4:15

5:40

7:05

8:30

9:55

11:2

012

:45

14:1

015

:35

17:0

018

:25

19:5

021

:15

22:4

0

MAE

Unit D

lag pcm

APPENDIX

Slide 48

Simple Lag Persistence Model

• Name Convention:

A (actual),

F (forecast),

E (Error) = F – A

• FH = Forecast Horizon (RTD)

• Lag Model

– F(t) = A(t-FH) (Forecast for time t = Actuals from time t-FH)

Slide 49

Recommendation for Solar Resources

Persistence Counter Market Model

• Let F(t) be forecast, A(t) be actual, and FPI(t) be

estimate of full power output taking into consideration

sun angle.

• The persistent forecast is then:

– F(t) = A(t-lag) / FPI(t-lag)* FPI(t)

– Where A(t-lag) / FPI (t-lag) is the estimate “cloud”

factor to A(t)/FPI(T)

The premise is the lag forecast A(t-lag) should adjust

according the track of performance under different

cloudiness condition at lag time point

Slide 50

Example

• Sunny Day:

– A(t-lag) / FPI(t-lag) = 1

• Cloudy Day:

– A(t-lag) / FPI(t-lag) = .3

Slide 51

Market Update

Good price convergence in April based.

Note: Metric Based on System Marginal Energy Component (SMEC)

RT prices higher than DA prices for both NP15 and SP15 in

April.

Insufficient upward ramping capacity in ISO continued to be

at low levels since last November.

Insufficient downward ramping capacity declined since

February.

Congestion revenue rights market revenue inadequacy

without auction revenues.

Congestion revenue rights market revenue sufficiency

including auction revenues.

Exceptional dispatch volume in the ISO area decreased

since February.

Real-time Bid cost recovery dropped in April

Bid cost recovery (BCR) by Local Capacity Requirement area

Minimum online commitment (MOC)

MOC San Onofre Bus

Pmax of MOC Cleared Units

Enforcement of minimum online commitments in March

and April

MOC NameNumber (frequency) of hours in

January and February

Humboldt 7110 SVC In 1196

MOC Pease 994

Orange County 7630 801

Humboldt 7110 215

MOC East Nicolaus 96

MOC SAN ONOFRE BUS 90

MOC Devers Bus 41

SDGE 7820 CFEIMP_BG 34

MOC Placer 4551087 26

MOC Moss 4575683 15

SDGE 7820 9

SCIT MOC 8

MOC NP15 7

Orange county outage 7630 2

Renewable (VERS) schedules including net virtual supply

and aligns with VER forecast in March and April

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

Hourly distribution of maximum RTD renewable (VERS)

curtailment in April

ISO area RTIEO increased since February.

2016 2017 (YTD)

RTCO $50,398,946 $9,701,084

RTIEO -$3,706,211 $18,633,447

Total Offset $46,692,735 $28,334,531

CAISO Price correction events increased in March and April

0

1

2

3

4

5

6

7

8

9

10

Jan

-16

Feb

-16

Mar

-16

Ap

r-1

6

May

-16

Jun

-16

Jul-

16

Au

g-1

6

Sep

-16

Oct

-16

No

v-1

6

De

c-1

6

Jan

-17

Feb

-17

Mar

-17

Ap

r-1

7

Co

un

t o

f Ev

ents

Process Events Software Events Data Error Events Tariff Inconsistency

EIM-Related Price correction events decreased in March and

April

0

2

4

6

8

10

12

14

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

2016 2017

Co

un

t o

f Ev

ents

Process Events Software Events Data Error Events Tariff Inconsistency

EIM Price trends

Slide 70

Robust Energy transfers observed in in 1st

quarter, 2017

Average – 259MW

Maximum – 1196MW

Average – 186MW

Maximum – 739MW

Average – 108MW

Maximum – 300MW

Average – 173MW

Maximum – 506MW

Average – 0MW

Maximum – 0MW

Average – 84MW

Maximum – 150MW

Average – 80MW

Maximum – 300MW

Average – 118MW

Maximum – 300MW

Average – 231MW

Maximum – 871MW

Average – 222MW

Maximum – 791MW

Average – 141MW

Maximum – 330MW

Average – 136MW

Maximum – 360MW

Average – 165MW

Maximum – 909MW

Average – 184MW

Maximum – 945MW

Average – 144MW

Maximum – 857MW

Average – 0MW

Maximum – 0MW

PACE

CAISO

PACW

NEVP

AZPS

PSEI

Slide 71

EIM BCR observed a modest increased in April

EIM Manual Dispatch increased in April and is mostly

concentrated in APS area

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

2015 2016 2017

MA

PE

Slide 74

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

2015 2016 2017

MA

PE

Slide 75

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

2015 2016 2017

MA

E

**In 2015-2016, Economic dispatches are not added back in to the generation data.

**The 2017 generation data used for accuracy calculation contains the economically dispatched MW.

Slide 76

Day-ahead solar 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

2015 2016 2017

MA

E

**In 2015-2016, Economic dispatches are not added back in to the generation data.

**The 2017 generation data used for accuracy calculation contains the economically dispatched MW.

Slide 77

Real-time wind forecast

0.0%

0.5%

1.0%

1.5%

2.0%

2.5%

3.0%

3.5%

4.0%Jan

Fe

b

Ma

r

Ap

r

Ma

y

Jun

Jul

Au

g

Se

p

Oct

No

v

De

c

2015 2016 2017

MA

E

**2015-2016 represent the accuracy of the forecast made each hour at xx:55 for the following hour, i.e. the 5-65

minute ahead forecast. Economic dispatches are not added back in to the generation data.

**2017 has been changed to track the RTD accuracy, i.e. the forecast made 7.5 minutes before the binding

interval. The 2017 generation data used for accuracy calculation contains the economically dispatched MW.

**This forecast accuracy is pulled directly from the CAISO Forecasting System.

Slide 78

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

2015 2016 2017

MA

E

**2015-2016 represent the accuracy of the forecast made each hour at xx:55 for the following hour, i.e. the 5-65

minute ahead forecast. Economic dispatches are not added back in to the generation data.

**2017 has been changed to track the RTD accuracy, i.e. the forecast made 7.5 minutes before the binding

interval. The 2017 generation data used for accuracy calculation contains the economically dispatched MW.

**This forecast accuracy is pulled directly from the CAISO Forecasting System.

Slide 79

Market Performance and Planning ForumMay 16, 2017

We are on lunch break, returning at 1:00 p.m. If you have

questions, send to Kristina Osborne at [email protected]

or call on cell at 916-802-7631.

mailto:[email protected]

Policy Update

Brad Cooper

Manager, Market Design and Regulatory Policy

Ongoing policy stakeholder initiatives

• Energy storage and distributed energy resources (ESDER)

Phase 2

– Publish draft final proposal in June

– July EIM Governing Body and CAISO Board meetings

• Contingency modeling enhancements

- Fourth revised straw proposal including prototype results in late

June

- September CAISO Board meeting

• Generator contingency and remedial action scheme

modeling

– Draft final proposal in June

– Sept EIM Governing Body and CAISO Board meetings

Slide 82

Ongoing policy stakeholder initiatives (continued)

• Commitment costs and default energy bid enhancements

– Recent stakeholder working groups

– Straw proposal in June

– November 2017 EIM Governing Body and CAISO board

meetings

• Temporary suspension of resource operations

– Recently posted issue paper

– Nov CAISO Board meeting

• Capacity Procurement Mechanism risk-of-retirement

process enhancements

– Recently posted issue paper

– Nov CAISO Board meeting

Slide 83


• EIM Greenhouse Gas Enhancements

– Draft final proposal in late May

– July 2017 EIM Governing Board and ISO Board meetings

(briefing)

– Report evaluating two-pass solution in late Q4 2017

– Early 2018 EIM Governing Body and ISO Board meetings for

approval

• Flexible resource adequacy criteria and must-offer

obligation – phase 2

– Second revised straw proposal in July

– Q2 2018 ISO Board meeting

• Congestion revenue right auction efficiency

– Stakeholder working group on analysis in April

– Analysis phase in progress

– Policy development phase starting after analysis complete in Q4Slide 84


• Frequency response – phase 2

– Developing new schedule

– Early 2018 CAISO board meeting

• Bid cost recovery enhancements

– Suspended due to FERC uplift allocation NOPR

Slide 85

Upcoming policy stakeholder initiatives

• Aliso Canyon mitigation measures extension

– Straw and draft final proposals in June

– July EIM Governing Body and ISO Board meetings

• Management of EIM Imbalance settlement for bilateral

schedule changes

– Issue paper in June

– Oct EIM Governing Body and Nov ISO Board meetings

• Donation by third party of transmission capacity available

for EIM transfers

– Issue paper in June

– Oct EIM Governing Body and Nov ISO Board meetings

Slide 86

Upcoming policy stakeholder initiatives (continued)

• Planned to start in Q3 2017

– EIM net wheeling charge

– Review Transmission Access Charge Structure

– Resource adequacy reform

– Real-time market enhancements

Slide 87

2016 Annual Report

Amelia Blanke

Manager, Monitoring & Reporting

Department of Market Monitoring

Total market costs were down by about 4 percent after

accounting for natural gas and greenhouse gas price

changes.

Slide 89

$0

$1

$2

$3

$4

$5

$6

$7

$0

$10

$20

$30

$40

$50

$60

$70

2012 2013 2014 2015 2016

Ave

rage

an

nu

al g

as p

rice

($

/MM

Btu

)

Ave

rage

an

nu

al c

ost

($

/MW

h)

Average cost (nominal)

Average cost normalized to gas price, including greenhouse gas adjustment

Average daily gas price, including greenhouse gas adjustments ($/MMBtu)

Estimated average wholesale energy costs per MWh

(2012 – 2016)

Slide 90

2012 2013 2014 2015 2016

Change

'15-'16

Day-ahead energy costs 32.57$ 44.14$ 48.57$ 34.54$ 30.70$ (3.84)$

Real-time energy costs (incl. flex ramp) 0.99$ 0.57$ 1.98$ 0.69$ 1.02$ 0.33$

Grid management charge 0.80$ 0.80$ 0.80$ 0.80$ 0.81$ 0.01$

Bid cost recovery costs 0.45$ 0.47$ 0.40$ 0.39$ 0.33$ (0.06)$

Reliability costs (RMR and CPM) 0.14$ 0.10$ 0.14$ 0.12$ 0.11$ (0.01)$

Average total energy costs 34.96$ 46.08$ 51.89$ 36.54$ 32.97$ (3.58)$

Reserve costs (AS and RUC) 0.37$ 0.26$ 0.30$ 0.27$ 0.54$ 0.26$

Average total costs of energy and reserve 35.33$ 46.34$ 52.19$ 36.81$ 33.50$ (3.31)$

Markets continued to perform close to competitive

benchmarks.

Slide 91

$0

$10

$20

$30

$40

$50

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

Ave

rag

e p

ric

e (

$/M

Wh

)

Competitive baseline ($/MWh) Average load-weighted day-ahead price

Average load-weighted 15-minute price Average load-weighted 5-minute price

Estimated net revenue of a hypothetical new unit 2012 - 2015

$0

$20

$40

$60

$80

$100

$120

$140

$160

$180

$200

$220

2012 2013 2014 2015

$/k

W-y

ear

Net revenues (NP15)

Net revenues (SP15)

Levelized fixed cost target

$0

$20

$40

$60

$80

$100

$120

$140

$160

$180

$200

$220

2012 2013 2014 2015

$/k

W-y

ear

Net revenues (NP15)

Net revenues (SP15)

Levelized fixed cost target

Combined Cycle Combustion Turbine

Slide 92

DMM updated net revenue analysis assumptions in 2016

• Not directly comparable to prior analysis

• Optimized dispatch of hypothetical resource

– Objective: maximize profit subject to resource

constraints

– 2016 NP15 and SP15 prices

• Combined cycle: day-ahead and five minute prices

• Combustion turbine: 15 and 5 minute prices

– Incremental energy cost = default energy bid

– Commitment cost = proxy start up and minimum load

http://www.caiso.com/Documents/2016AnnualReportonMarketIssuesandPerformance.pdf

Slide 93

Financial analysis of new combined cycle unit (2016)

Slide 94

Zone Scenario Capacity factorTotal energy

revenues ($/kW-yr)

Operating costs

($/kW-yr)

Net revenue

($/kW-yr)

Day-ahead prices and default energy bids 21% $75.88 $64.65 $11.23

Day-ahead prices and default energy bids without adder 23% $83.12 $70.45 $12.67

Day-ahead commitment with dispatch to day-ahead and

5-minute prices using default energy bids22% $79.73 $66.82 $12.91

Day-ahead prices and default energy bids 29% $104.92 $84.40 $20.52

Day-ahead prices and default energy bids without adder 32% $111.20 $88.83 $22.37

Day-ahead commitment with dispatch to day-ahead and

5-minute prices using default energy bids30% $108.51 $86.38 $22.13

NP15

SP15

Significantly below California Energy Commission’s estimate of annualized fixed costs for a hypothetical combined cycle is $166/kW-yr

Financial analysis of new combustion turbine (2016)

Slide 95

Zone Scenario Capacity factorReal-time energy

revenues ($/kW-yr)

Operating costs

($/kW-yr)

Net revenue

($/kW-yr)

15-minute prices and default energy bids 4.5% $23.46 $18.67 $4.80

15-minute prices and default energy bids without

adder5.6% $27.85 $22.17 $5.68

15-minute commitment with dispatch to 15-minute

and 5-minute prices using default energy bids5% $31.41 $21.03 $10.38

15-minute prices and default energy bids 7% $41.37 $28.87 $12.50

15-minute prices and default energy bids without

adder9% $48.20 $34.33 $13.87

15-minute commitment with dispatch to 15-minute

and 5-minute prices using default energy bids8% $50.07 $32.79 $17.29

NP15

SP15

Significantly below California Energy Commission’s estimate of annualized fixed costs for a hypothetical combustion turbine is $177/kW-yr

Flexible ramping payments

Slide 96

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Puget Sound Energy Arizona Public Service

Payments per MWh of load

Flexible ramping product implementation

Release Plan Update

Janet Morris

Director, Program Office

Adrian Chiosea

Manager, Strategic Initiative Management

Release Plan 2017

Slide 98

Independent 2017

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

• RIMS Functional Enhancements

• Black Start and System Restoration Phase 2

• Forecasting & Data Transparency Improvements (PIRP System Decommissioning)

• Aliso Canyon mitigation measures extension

Fall 2017 (11/1/17)

• EIM Portland General Electric (PGE) – 10/1/17

• Bidding Rules Enhancements – Part B

• Commitment Cost Enhancement Phase 3

• RM & EIM 2017 Enhancements

• Gas Burn Report

• SIBR UI Upgrade

Release Plan – 2018 and subject to further planning

Slide 99

Spring 2018

• Reliability Services Initiative 2017

• EIM 2018 Idaho Power Company

Fall 2018 – tentative, subject to impact assessment

• Contingency Modeling Enhancements

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

• Commitment Costs and Default Energy Bid Enhancements

• Energy Storage and DER Phase 2

• Temporary Suspension of Resource Operations

• Capacity Procurement Mechanism – risk-of-retirement process enhancements

• Management of EIM imbalance settlement for bilateral schedule changes

• ADS User Interface Replacement

• CIRA Technology Upgrade

Spring 2019

• EIM 2019 Seattle City Light

• EIM 2019 Balancing Authority of Northern California (BANC)

Fall 2019 – tentative, subject to impact assessment

• Regional Integration and EIM Greenhouse Gas Compliance

• Generation Contingency and Remedial Action Scheme

• Frequency Response Phase 2

• Congestion Revenue Right auction efficiency

Spring 2020

• EIM 2020 Salt River Project

Subject to further release planning:

• DRS Replacement

2017 - MRI-S ACL Groups+ CPG Enhancements

Project Info Details/Date

Application Software Changes

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.

A customer partnership group is scheduled for May 11, 2017 to address issues

encountered during market sim, and to discuss the steps necessary for cut-over from

OMAR Online to MRI-S Metering.

OMAR Online will be decommissioned four months after the May 2nd re-opening of the

MRI-S Metering: September 1, 2017.

BPM Changes None

Business Process ChangesPotential Level-II business process changes under –

• Manage Market & Reliability Data & Modeling

• Manage Operations Support & Settlements

Slide 100

Milestone Type Milestone Name Dates Status

Board Approval Board Approval N/A

BPMs BPMs N/A

External BRS Post External BRS Nov 14, 2016

Tariff Tariff N/A

Config Guides Config Guide N/A

Tech Spec Publish Tech Specs Nov 02, 2016

Market Simulation Phase 2 - MRI-S Metering Enhancements Mar 13, 2017 – June 9, 2017

Production Activation Phase 1 - ACL Groups Mar 10, 2017

Phase 2 - MRI-S Metering CPG Enhancements Jun 13, 2017

2017 – 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 101


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

Tech Spec No Tech Specifications Required N/A

Production Activation Ph1 RIMS5 App & Study Mar 21, 2016

Production Activation Ph2 RIMS5 Queue Management, Transmission and Generation Dec 14, 2017

2017- Black Start and System Restoration Phase 2



Settlements:

• Modifications to existing charge codes for Black Start capacity and

Black Start allocations will need to occur.

MPP (Market Participant Portal):

• Possibility to use current functionality for receiving RMR invoices

for Black Start units.

BPM Changes

Definitions & Acronyms:

• Revision of the following definitions to match the Tariff language:

• Ancillary Services (AS)

• Black Start Generator

• Black Start Generating Unit

• Interim Black Start Agreement

• Reliability Services Costs

Settlements & Billing:

• Pending Settlements review. Revisions will be directly based on

Tariff changes.

Business Process Changes N/A

Slide 102


Board Approval Board approval May 1, 2017

BPMs BPM Changes Required TBD

External BRS External BRS not Required N/A

TariffDraft tariff

Web Conference to finalize tariff

May 1, 2017

May 15, 2017

Tech Spec No Tech Specifications Required N/A

2017 – Forecasting and Data Transparency Improvements

(PIRP System Decommissioning)


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 103




User-Provisioning process for

CMRI in preparation of Market

Simulation and subsequently for

production

• Client Services will reach out to the User Access Administrator (UAA)

• Updated AIM User Guide, detailing how to create new ACL groups, was posted on

February 21, 2017 - The market notice was posted on February 23, 2017

• If a user is at the SC level, there is no need to provision ACL access

• Exceptions - (Non-SC Level Users) – provisioning via AIM will be required

• Provisioning will be required to be done prior to Market Simulation

• Provisioning for PIRP via AARF will discontinue on Feb 16, 2017 for Map Stage and

Mar 20, 2017 for Production.

• Participants should begin to download their PIRP data (all reports) as soon as possible

as the data will not be available after June 20, 2017

• PIRP application including all the UI and API reports will be decommissioned June 20,

2017

• If you have any questions please contact your client services representative

Slide 104



Slide 105



BPMsPublish 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; Wind and Solar) Apr 15, 2016

Publish Technical Specifications (CMRI: PIRP

Decommissioning)Feb 05, 2016

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

New Renewables CMRI reports and APIs Market

SimulationApr 04, 2017 - Apr 18, 2017

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

OASIS API Enhancements; 9 Reports Dec 20, 2016

New Renewables CMRI reports and APIs Production

DeploymentApr 20, 2017

PIRP Decommission PIRP Decommissioning Jun 20, 2017

Fall 2017 Release – Overview

Slide 106

Board Approval

BPMs External BRS Tariff Config Guide Tech Spec Market SimProduction Activation

Fall 2017 Release

EIM Portland General Electric N/A N/A N/A 8/31/17 N/A N/A6/6/17 -7/6/17

10/1/17

Bidding Rules Enhancements - Part B 3/25/16

6/15/17

1/13/17 6/1/17

6/27/17

• 4/3/17 (MF)

• 4/3/17 (OASIS)

• 4/17/17 (CMRI)

• 4/25/17(CMRI)

• 5/2/17 (OASIS)

8/8/17 -9/8/17

11/1/17

Commitment Cost Enhancement Phase 3 3/25/161/6/17

4/10/176/15/17

RM & EIM 2017 Enhancements N/A N/A1/23/172/17/174/10/17

N/A

Gas Burn Reports N/A N/A 7/29/16 N/A N/A N/A

SIBR UI Upgrade N/A N/A N/A N/A N/A N/A N/A

COMPLETE

N/A

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 SimulationPGE continues Day in the Life and unstructured scenario testing in a non-

production environment in preparation for Market Simulation.

Parallel Operations August 1 – September 30, 2017

Slide 107


Tariff File Readiness Certification Aug 31, 2017

Market Sim Market Sim Window Jun 6, 2017 – Jul 6, 2017

Parallel Operations Parallel Operations Window Aug 1, 2017 – Sep 30, 2017

Production Activation EIM - Portland General Electric Oct 01, 2017

Fall 2017 - Bidding Rules Enhancements – Part B

Slide 108



• MasterFile:

• Electric Region added to GRDT as non-modifiable

• CMRI:

• Resource-level monthly EPI (calculated on daily basis) based on wholesale or reatil

electric region type.

• CAISO.COM:

• Only publish total monthly fuel region GPI (existing) and eliminate publishing the

monthly fuel region GPI components as PDF file. (public information)

Business Process Change• Manage Transmission & Resource Implementation

• Manage Entity & Resource Maintenance Updates

• Manage Full Network Model Maintenance

BPMs Market Instruments


BPMs Post Draft BPM changes June 15, 2017

Board Approval BOG Approval Mar 25, 2016

External BRS Post External BRS Jan 13, 2017

Config Guides Prepare Draft Configuration Guides Jun 27, 2017

Tech Spec Publish CMRI Tech Specs Apr 17, 2017

Publish MF Tech Specs Apr 03, 2017

Market Sim Market Sim Window Aug 08, 2017 - Sep 08, 2017

Production Activation Bidding Rules Part B Nov 01, 2017


Application Software

Changes

Scope:1. Clarify use-limited registration process and documentation to determine opportunity costs2. Determine if the ISO can calculate opportunity costs

• ISO calculated; Modeled limitation Start/run hour/energy output• Market Participant calculated; Negotiated limitation

3. Clarify definition of “use-limited” 4. Change Nature of Work attributes (Outage cards)

• Modify use-limited reached for RAAIM Treatment• Allow PDR to submit use-limit outage card for fatigue break.

5. Market Characteristics• Maximum Daily Starts• Maximum MSG transitions• Ramp rates

Impacted Systems:1. Master File: Set use-limited resource types and limits; Set market-based values2. ECIC: Process use limited resource input values for and Receive opportunity cost adders from

opportunity cost tool3. CIRA: RAAIM exempt rule for “use-limited reached”4. CMRI: Publish opportunity cost5. IFM/RTN: Use market-based values MDS, MDMT and RR6. SIBR: Add Opportunity cost adders on bid caps, remove daily bid RR7. MasterFile: Set use-limited resource types and limits; Set market-based values8. OMS: “Use-Limited Reached” nature of work attribute for Generation Outage Card9. Settlements: Publish the actual start up, run hour and energy output for the use-limited

resources10. Opportunity cost calculator (OCC): Calculate and publish opportunity costs for start-up, MLC and

DEB

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

Business Process Changes• Manage Market & Reliability Data & Modeling• Manage Markets & Grid

Slide 109

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

BPMs Post Draft BPM changes Jun 15, 2017


Tariff File Tariff Jun 15, 2017

Config Guides Config Guide Jun 27, 2017

Tech Spec

Publish ISO Interface Spec (Tech spec) – MF

Publish ISO Interface Spec (Tech spec) – CMRI

Apr 03, 2017

Apr 17, 2017

Market Sim Market Sim Window Aug 08, 2017 – Sep 8, 2017

Production Activation Commitment Costs Phase 3 Nov 01, 2017

Fall 2017 – RM & EIM Enhancements 2017Project Info Details/Date


Address enhancements identified by policy, operations, technology, business

and market participants.

Scope:

1. Access & Integration Enhancements: EIM Entity Access in ALFS, MF,

OASIS, WebOMS, and CMRI.

2. EIM data report enhancements to support market participant and EIM entity

settlements

3. EIM software enhancements

4. Change to ETSR formulation to separate base energy transfer to distinct

non-optimizable ETSRs.

Out of Scope:

1. BAAOP provisioning in AIM

2. Joint Owned Unit/Shared BAA Resource Modeling

BPM Changes

Energy Imbalance Market: Access & Integration, Data Report

Outage Management: Access & Integration

Market Instruments: Access & Integration, Data Reports

Market Operations: Data Report

Settlements & Billing: Data Report

Business Process Changes N/A

Slide 111

Fall 2017 – RM & EIM Enhancements 2017

Slide 112



Post Updated External BRS Feb 17, 2017

Post Updated (v1.2) External BRS to public site Apr 10, 2017


Tech Spec Publish Technical Specifications (CMRI) Apr 17, 2017

Publish Technical Specifications (OASIS) Apr 03, 2017

Publish Technical Specifications (MF) Apr 03, 2017

Market Sim Market Simulation Aug 08 – Sept 08, 2017

Production Activation RM & EIM Enhancements 2017 Nov 01, 2017

Fall 2017 – Gas Burn Report

Slide 113



CMRI - implement ISO Market software functionality to calculate and present gas burn

estimates to gas companies serving electric generation located within the CAISO BAA

OASIS - Control Area Generating Capability List report

Business Process Change• Develop Infrastructure

• Manage Market & Reliability Data & Modeling


Board Approval BOG Approval N/A

BPMs Post Draft BPM changes N/A

External BRS External Business Requirements Jul 29, 2016

Tariff Receive FERC order N/A

Config Guides Configuration Guides N/A

Tech Spec Publish Technical Specifications - CMRI Apr 25, 2017

Publish Technical Specifications - OASIS May 02, 2017

Market Sim Market Sim Window N/A

Production Activation GenDB MF Consol and Gas Burn Report Nov 01, 2017

Fall 2017 – SIBR UI Upgrade

Slide 114



SIBR – The CASIO will be upgrading the underlying SDK platform utilized for displaying the

user interface. This latest SDK version will strengthen the security of the SIBR application

and will improve compatibility with the latest version of Internet Explorer.

It is anticipated no functional changes or API will be impacted by this upgrade.



BPMs Publish Final Business Practice Manuals N/A

External BRS Post Draft BRS N/A

Tariff Receive FERC order N/A

Tech Spec Publish Tech Specs N/A

Market Sim Market Sim Window N/A

Production Activation SIBR UI Upgrade Nov 01, 2017

Spring 2018 - Reliability Services Initiative 2017



Developments under consideration include:

Scope:Redesign of Replacement Rule for System RA and Monthly RA Process.

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

• CSP Offer Publication (RSI 1A scope)

• Local and system RA capacity designation

• RA showing requirements for small load serving entities (LSEs)

• RA showing tracking and notification

Impacted Systems:

• OASIS

• Settlements

• CIRA

CIRA:• Modifications to the RA and Supply Plan to show breakdown of local and system. Validation

rules need to be updated.

• Update planned/forced outage substitution rules

• Allow market participants to select how much system/local MWs to substitute.

• Modification of UI screens to accommodate system/local MW split.

• Enhance system to allow exemption from submission of RA Plans for LSE that have a RA

obligation < 1 MW for a given capacity product.

Settlements:• Splitting local from system in upstream RA system could potentially impact the RAAIM

calculation.

BPM Changes• Reliability Requirements: Changes to the monthly RA process

• Settlements and Billing

Business Process Changes

Manage Market & Reliability Data & Modeling- Manage Monthly & Intra-Monthly Reliability Requirements

- Manage Yearly Reliability Requirements

Slide 115

Spring 2018 - Reliability Services Initiative 2017

Slide 116


Board Approval Board Approval May 12, 2015

BPMs Post Draft BPM changes Jun 15, 2017

External BRS Post Updated External BRS v1.1 (RSI 2) Apr 07, 2017

Post Updated External BRS v1.3 (RSI 1B) Mar 03, 2017

Post RSI 2017 External BRS v2.0 Apr 19, 2017

Tariff File Tariff Q3 2017


Tech Spec Publish Technical Specifications Apr 03, 2017

Market Sim Market Sim Window Oct 30, 2017 - Dec 08, 2017

Production Activation RSI 2017 Feb 13, 2018

Spring 2018 – EIM Idaho Power Company


Application Software Changes Implementation of Idaho Power Company as an EIM Entity.

BPM Changes

EIM BPM will be updated if needed to reflect new modeling scenarios

identified during Idaho Power implementation and feedback from Idaho

Power.

Market Simulation

The ISO approved the Idaho Power network model and continues to make

progress integrating the Idaho model into the ISO non-production

environment in preparation for integration testing.

Parallel Operations February 1, 2018 – March 30, 2018

Slide 117


Tariff File Readiness Certification Feb 28, 2018

Market Sim Market Sim Window Dec 01, 2017 - Jan 31, 2018

Parallel Operations Parallel Operations Window Feb 01, 2018 - Mar 30, 2018

Production Activation EIM - Idaho Power Apr 04, 2018

The ISO offers comprehensive training programs

Slide 118

All classes are offered at our Folsom, CA location unless noted otherwise.

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

Contact us - [email protected]

Date Training

May 24-25 Get to Know the ISO

Jul 6 Welcome to the ISO - webinar

Aug 16 Settlements 101

Aug 17 Settlements 201

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

mailto:[email protected]

ISO Daily Briefing

• A digest version of ISO market notices

• Distributed daily, Mon-Fri around 1:30 p.m. (PST)

• NEW: Upcoming Events - Every Thursday the briefing

will include stakeholder activities for the following week

• To subscribe to the Daily Briefing:

Go to www.caiso.com

Under “Stay Informed” tab

Select “Notifications”

Click under Market notices heading

Select Daily Briefing from the list of categories

Note: If you currently receive ISO market notices and you re-subscribe, the system will override your previous

category selections. If you still want to receive market notices in other categories, you’ll need to reselect those

categories of interest.

Slide 119

http://www.caiso.com/

http://www.caiso.com/informed/Pages/Notifications/MarketNotices/MarketNoticesSubscriptionForm.aspx




Market Performance and Planning Forum

2017 Schedule

• July 18

• October 5 – Rescheduled from September 19

• November 14

Questions or meeting topic suggestions:

Submit through CIDI - select the “Market Performance and

Planning Forum” category

Slide 120