Market Performance and Planning Forum - California · PDF file• Discuss external impacts of implementation plans • Launch joint implementation ... (BCR) by Local Capacity Requirement

Market Performance and

Planning Forum

January 18, 2017

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

Page 2

Last updated: January 17, 2017

Market Performance and Planning ForumAgenda – January 18, 2017

Time: Topic: Presenter:

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

10:05 – 10:20 Capacity Procurement Market Update Dede Subakti

10:20 – 11:30 Market Performance and Quality Update Amber Motley

Guillermo Bautista Alderete

11:30 – 12:00 Flexible Ramping Sufficiency Test Keith Collins

12:00 – 1:00 Lunch

1:00 – 1:30 Policy Update Brad Cooper

1:30 – 1:45 Sub-LAP Area Definition Updates Jim Price

Jim McClain

1:45 – 2:00 Model Enhancement for DERs

*w/update on Sub-Lap revision implementation for PDR/RDRR

Jill Powers

2:00 – 3:00 Release Update Janet Morris

Capacity Procurement Market Update

Dede Subakti

Director, Operations Engineering Services

Slide 4

CPM and CSP update

• New CPM and CSP process went live on Nov 1, 2016

• On Nov 8, CAISO issued ED to Mandalay due to transmission

outage in Santa Clara sub-area. Unit CPM’d

• On Nov 9, CAISO issued EDs to 8 resources needed to mitigate the

emergency event caused by a market disruption. Emergency event

involved area control error and low system frequency. The market

tool did not work, so ED done manually. Units were CPM’d.

• On Dec 14, CAISO issued EDs to 2 resources in Bay Area due to

transmission outage. Units were CPM’d.

• On Dec 18, CAISO issued ED to Moss Landing Due to the cold

temperatures, potential gas supply issues, and potential loss of

imports into the California ISO Balancing Authority. The market tool

did not work, so ED done manually. Unit was CPM’d

• On Dec 19, CAISO issued ED to Mountain View due to outages in

West of Devers sub-area. Unit was CPM’d.

Observations

• After the fact analysis (following Nov 8 event), showed

that some SCs did not provide CSP offer because the

SC operators were not aware that CSP went live on Nov

1, 2016

Page 6

Other Observation (optional slide)

• If SC does not submit CSP offer, then the SC may reject the CPM

designation following an ED. Under Tariff, SC must do this within

the 24 hour window. If ED is done over the weekend, CAISO

reminds all SCs to watch for this notification (CAISO notes that in

order for an SC for a resource to know that they have received a

CPM designation, they must subscribe to the email notification. Not

everyone is doing this.)

• We observe that some resources offer Flex RA > Generic RA.

Sometimes, there is 0 MW for generic RA, but non-zero for Flex RA .

Under tariff, the ISO cannot grant an intra-monthly CPM to capacity

that is Committed RA Capacity on the day the CPM designation

would begin. Take for example a resource with 0 MW of generic RA

capacity and Flex RA capacity greater than zero. The resource is not

eligible to receive an intra-monthly CPM designation for the MW of

capacity that is Flex RA.

Page 7

Market Performance and Quality Update

Amber Motley

Manager, Short Term Forecasting

Guillermo Bautista Alderete, Ph.D.

Director, Market Quality and Forecasting

Slide 8

Flexible Ramp Update

Page 9


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 area enforced in the real-time

market.

• 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.

Page 10


What is driving the flexible ramp requirement profile?

• The requirement for RTPD is based off the difference

between the RTD net load and the RTPD net load.

• The FRU requirement is typically lower for ramp up

periods because the RTD net load forecast is more

accurate than the RTPD net load.

Page 11


Why is the individual EIM areas FRP procurement

volatile?

• Raw FRP requirements are adjusted first for Net

Import/Export Capability (NIC/NEC) or diversity credit.

• Generally, the NIC/NEC will largely offset the raw

requirement and thus the individual requirement

constraints will often not bind

• The system-wide EIM area constraint still has to be in

place and will usually bind.

• Individual EIM areas may procure FRP towards the EIM

area based on economics, and influenced by

– Energy bid ranges among areas, and

– transfers

Page 12


Individual versus EIM area procurement

Page 13


Flexible Ramp requirements and prices

Page 14


$0

$50

$100

$150

$200

-1,500

-1,000

-500

0

500

1,000

1,500

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

Ave

rage

Ho

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y Fl

ex R

amp

Pri

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$/M

W)

Ave

rage

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url

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ex R

amp

Req

uir

emen

t (M

W)

Flex Ramp Down Average Requirement Flex Ramp Up Average Requirement

Flex Ramp Down Average Price Flex Ramp Up Average Price

Why there is procurement in excess of the

requirement?

• The procurement of the flex Ramp is actually driven by

the requirements of the system-wide EIM area.

• The capacity is not unlimited, and individual areas meet

the procurement of the overall EIM area

• There may be capacity in excess but it will be at $0

price

• Usually changes in commitment or deviations may make

more capacity available at $0 price.

Page 15


Regulation Update

Page 16


Examples: December Regulation RequiredSolid – Sunny Weather Conditions

Dotted – Partly Cloudy/Cloudy weather conditions

Page 17


December Regulation Cost Comparison

March 2016 vs December 2016

Page 18


Market Update

Page 19


Page 20

Good price convergence in December.

Page 21

RT prices higher than DA prices for NP15 in November but

lower than DA prices for both NP15 and SP15 in

December.

Page 22

Insufficient upward ramping capacity in ISO dropped in

December.

Page 23

Insufficient downward ramping capacity stayed low in 2016.

Page 24

Congestion revenue rights market revenue inadequacy

without including auction revenues.

Page 25

Congestion revenue rights market revenue sufficiency

including auction revenues.

Page 26

Exceptional dispatch volume in the ISO area remained low in

November and December.

Page 27

Daily exceptional dispatches by reason

Page 28

Real-time Bid cost recovery increased since September

Page 29

Bid cost recovery (BCR) by Local Capacity Requirement area

Page 30

Minimum online commitment (MOC)

Page 31

Pmax of MOC Cleared Units

Page 32

Enforcement of minimum online commitments in

November and December

MOC NameNumber (frequency) of hours in


Humboldt 7110 1459

MOC East Nicolaus 1374

MOC Moorpark 101

MOC Palermo Hi Volt 4462683 80

MOC Moss 3919104 78

Orange County 7630 68

MOC SAN ONOFRE BUS 57

SCIT MOC 27

MOC PLACER 4371261 25

HNTBH 7820 7

SDGE 7820 2

Page 33

IFM under-scheduling of solar generation

Page 34

IFM under-scheduling of wind generation declined in


Page 35

Renewable (VERS) schedules including net virtual supply

and aligns with VER forecast in November and December

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

Page 36

RTD renewable (VERS) curtailment trended upward since

August

Page 37

Hourly distribution of maximum RTD renewable (VERS)

curtailment in December

Page 38

Wind, solar and hydro production

Monthly wind (VERS) downward flexibility in FMM

Page 39

Monthly solar (VERS) downward flexibility in FMM

Page 40

Monthly solar (VERS) downward flexibility in FMM from

11 AM to 5 PM

Page 41

Page 42

ISO area RTCO and RTIEO remains at low levels in

November and December.

2015 2016

RTCO $55,376,805 $50,506,525

RTIEO $13,648,680 -$691,475

Total Offset $69,025,485 $49,815,050

Page 43

CAISO Price correction events increased in November but

decreased in December

0

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Jan

-15

Feb

-15

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-15

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r-1

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Sep

-15

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Process Events Software Events Data Error Events Tariff Inconsistency

Page 44

EIM-Related Price correction events increased in November

and December

0

2

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18

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

2015 2016

Co

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t o

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ents

Process Events Software Events Data Error Events Tariff Inconsistency

EIM Price trends

Page 45

EIM transfers

Page 46

Page 47

EIM BCR in November and December

Page 48

EIM Manual Dispatch in November and December

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

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2014 2015 2016

MA

PE

Day-ahead peak to peak forecast accuracy

0.0%

0.5%

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1.5%

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2.5%

3.0%

3.5%Jan

Fe

b

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r

Ap

r

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Jun

Jul

Au

g

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v

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2014 2015 2016

MA

PE

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

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

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

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2014 2015 2016

MA

E

Real-time solar forecast

0%

1%

2%

3%

4%

5%

6%Jan

Fe

b

Ma

r

Ap

r

Ma

y

Jun

Jul

Au

g

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Oct

No

v

De

c

2014 2015 2016

MA

E

Flexible ramping sufficiency test

Keith Collins

Manager, Monitoring and Reporting

Department of Market Monitoring

Page 55


• Ensures that each EIM balancing authority area

has sufficient upward and downward ramping

capability over an hour to meet expected ramp

as well as uncertainty

• If a balancing area does not have sufficient

ramping capacity, then:

– It cannot increase EIM transfers into its area to

meet upward ramping limitations

– It cannot decrease EIM transfers from its area to

meet downward ramping limitations

Page 56


• In order to pass the hourly flexible ramping sufficiency test in a given

direction (upward or downward), an EIM entity needs to show

sufficient ramping capability from the start of the hour to each of the

four 15-minute intervals in the hour.

• An EIM entity must pass all four 15-minute interval tests in order to

pass the hourly flexible ramping sufficiency test for upward and

downward ramping.

𝐹𝑙𝑒𝑥 𝑅𝑎𝑚𝑝 𝑈𝑝 𝑅𝑒𝑞𝑢𝑖𝑟𝑒𝑚𝑒𝑛𝑡

= ∆𝐿𝑜𝑎𝑑 + 𝐹𝑙𝑒𝑥 𝑈𝑝 𝑈𝑛𝑐𝑒𝑟𝑡𝑎𝑖𝑛𝑡𝑦 + max−𝑁𝑒𝑡 𝐼𝑚𝑝𝑜𝑟𝑡 𝐶𝑎𝑝𝑎𝑏𝑖𝑙𝑖𝑡𝑦,

−𝐷𝑖𝑣𝑒𝑟𝑠𝑖𝑡𝑦 𝐵𝑒𝑛𝑒𝑓𝑖𝑡 − 𝐹𝑙𝑒𝑥 𝑅𝑎𝑚𝑝 𝑈𝑝 𝐶𝑟𝑒𝑑𝑖𝑡

Page 57

Forecasted

component

Uncertainty component

(Same used in flexible

ramping product)

Diversity benefit and credit reduction

capped at net import capability

Flexible ramping sufficiency test –

Modifiers

• Diversity Benefit Factor – A fraction that represents a

balancing authority area’s share of the net load forecast error

for the combined EIM area. It is equal to the EIM area

uncertainty requirement divided by the sum of the individual

balancing authority area uncertainty requirements. It

represents the smoothing effect that happens when

combining net load forecast errors across a larger footprint.

• Flexible ramping credit – The ability to reduce exports to

increase upward ramping capability or reduce imports to

increase downward ramping capability.

Page 58


Modifiers

• Net import capability – The amount of import capacity a

balancing authority area has in each interval. The reduction

in the upward sufficiency test requirement because of any

diversity benefit or flexible ramping up credit may not be

greater than the available net import capability.

• Net export capability – The amount of export capacity a

balancing authority area has in each interval. The reduction

in the downward sufficiency test requirement because of any

diversity benefit or flexible ramping down credit may not be

greater than the available net export capability.

Page 59

Sufficiency test example – diversity benefit• PacifiCorp West upward sufficiency test on December 2, hour 17

• Diversity benefit factor =514

1,210= 42%

• PACW diversity benefit reduction = 97 − 97 ∗ 42% = 56 MW

Page 60

0

200

400

600

800

1,000

1,200

1,400

MW

CAISO PACE PACW PSEI NEVP AZPS EIM area

Pro rata diversity benefit reduction = 56 MW

BAA uncertainties EIM area uncertainty PACW uncertainty PACW uncertainty *

diversity benefit factor

Sum of BAA uncertainties = 1,210 MW

EIM area uncertainty = 514 MW

PACW

uncertainty

= 97 MW

Sufficiency test example – net transfer capability and credits

• Upward sufficiency test on December 2, hour 17

• PacifiCorp West flexible ramping up credit = 158 MW

• PacifiCorp West net import capability = 1,064 MW

Page 61

-400

-200

0

200

400

600

800

1,000

PACW

HMWY import limit

MALIN import limit

BPAT import limit

With PACE on HMWY

With PSEI on BPAT

With CAISO on MALIN

Total import limit

Net transfer

Flex ramp up credit =

net EIM export = 158 MW

(zero down credit)

Net import capability =

1,064 MW

Total import limit = 906 MW

Ex

po

rts

Imp

ort

s

Sufficiency test example –

PacifiCorp West Hour 17

𝐹𝑙𝑒𝑥 𝑅𝑎𝑚𝑝 𝑈𝑝 𝑅𝑒𝑞𝑢𝑖𝑟𝑒𝑚𝑒𝑛𝑡

= ∆𝐿𝑜𝑎𝑑 + 𝐹𝑙𝑒𝑥 𝑈𝑝 𝑈𝑛𝑐𝑒𝑟𝑡𝑎𝑖𝑛𝑡𝑦 + max−𝑁𝑒𝑡 𝐼𝑚𝑝𝑜𝑟𝑡 𝐶𝑎𝑝𝑎𝑏𝑖𝑙𝑖𝑡𝑦,

−𝐷𝑖𝑣𝑒𝑟𝑠𝑖𝑡𝑦 𝐵𝑒𝑛𝑒𝑓𝑖𝑡 − 𝐹𝑙𝑒𝑥 𝑅𝑎𝑚𝑝 𝑈𝑝 𝐶𝑟𝑒𝑑𝑖𝑡

• 𝐹𝑙𝑒𝑥 𝑅𝑎𝑚𝑝 𝑈𝑝 𝑅𝑒𝑞𝑢𝑖𝑟𝑒𝑚𝑒𝑛𝑡 = 197 + 97 +max−1,064,−56 − 158

= 80

• 𝑈𝑝𝑤𝑎𝑟𝑑 𝑟𝑎𝑚𝑝𝑖𝑛𝑔 𝑐𝑎𝑝𝑎𝑐𝑖𝑡𝑦 𝑎𝑣𝑎𝑖𝑎𝑏𝑙𝑒 = 218

• PacifiCorp West passes the test for the fourth 15-minute

interval of the hour

Page 62

• PacifiCorp West failed sufficiency test in hour ending 9.

Flexible ramping sufficiency test example –

PacifiCorp West

Page 63

-600

-400

-200

0

200

400

600

800

123412341234123412341234123412341234123412341234123412341234123412341234123412341234123412341234

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

Hour and test #

Import capability reduction Diversity benefit reduction Flex ramp credit reduction

Forecasted component Uncertainty component Net requirement

Upward ramping capacity

• There was a significant uptick in sufficiency failures after launch of the

flexible ramping product on November 1. Many were due to issues in

counting available supply to meet the requirement.


Upward ramping sufficiency failures

Page 64

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October November December

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ile

d

PACE PACW NEVP PSEI AZPS


Downward ramping sufficiency failures

Page 65

• The downward sufficiency test was added on November 1.

• There have been a significant set of failures in the APS area since launch.

0

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November December

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PACE PACW NEVP PSEI AZPS

Policy Update

Brad Cooper

Manager, Market Design and Regulatory Policy

Page 66

Ongoing policy stakeholder initiatives

• Stakeholder Initiatives Catalog

– Feb EIM Governing Body and ISO Board Meetings

• Energy Storage and Distributed Energy Resources

(ESDER) - Phase 2

– Schedule TBD

• Bid Cost Recovery Enhancements

– Revised straw proposal in Jan

– Remaining schedule TBD

• Contingency Modeling Enhancements

– Technical analysis results and stakeholder call targeted

for Jan-Feb

– May ISO Board Meeting

Page 67

Ongoing policy stakeholder initiatives (continued)

• Stepped Constraint Parameters

– Incorporating parameter changes needed for FERC

Order 831 compliance

– Straw proposal targeted for Feb

– May EIM Governing Body and ISO Board Meetings

• Generator Contingency and Remedial Action Scheme

Modeling

– Revised straw proposal targeted for Jan

– July EIM Governing Body and ISO Board Meetings

Page 68

• Commitment Costs and Default Energy Bid Enhancements

– Straw proposal targeted for February 2017

– July EIM Governing Board and ISO Board Meetings

– Will address bid cost verification for FERC Order 831

compliance

• Frequency Response – Phase 2

– Working groups meetings in Feb, March

– Straw proposal targeted for April

– Sept ISO Board Meeting

• Flexible Resource Adequacy Criteria and Must-Offer

Obligation – Phase 2

– Revised straw proposal targeted for Feb 2017

– Board Meeting TBD

Page 69



• Regional Integration and EIM Greenhouse Gas Compliance

– ARB 15-Day Notice comments due Jan 20

– Draft final proposal TBD

– EIM Governing Body and ISO Board Meeting TBD

• Transmission Access Charge Options, Regional Resource

Adequacy

– Frameworks published Dec 2016

– ISO response to comments targeted Jan-Feb

– Further policy development on hold pending regional

governance structure development

Page 70

Policy stakeholder initiatives coming soon

• Planned to start in Q1 2017

– Resource Adequacy Enhancements

– Economic and Maintenance Outages

– CRR Auction Efficiency Analysis Working

– Blackstart and System Restoration

Page 71

Sub-LAP Areas Update

Jim Price

Senior Advisor, Market Development & Analysis

Slide 72

Recap: Sub-LAPs within default load aggregation points

(DLAPs) have been implemented as of 1/1/2017

• Other than publication of locational marginal prices (LMPs),

Sub-LAPs have two purposes:– Aggregations of demand response and distributed resources

– More precise congestion costs than default LAPs and award of

additional CRRs when congestion limits DLAPs.

• Existing Sub-LAPs were identified when current market

design was implemented in MRTU, and were outdated

• Basing Sub-LAP boundaries on RA local capacity areas will

allow demand response to qualify as local RA resources.

• Several Sub-LAP boundaries have shifted slightly to reflect

RA areas, and some could be merged.

• Updates do not change Custom LAPs of Participating Loads.

• If RA local capacity areas change, Sub-LAPs will follow.Page 73

Most Sub-LAPs retain same name. Name changes

indicate splitting or merging areas.

Current Sub-

LAPNew Sub-LAP

Current Sub-

LAP

New Sub-

LAP

SLAP_PGCC SLAP_PGCC SLAP_SCEC SLAP_SCEC

SLAP_PGEB SLAP_PGEB SLAP_SCEN SLAP_SCEN

SLAP_PGF1 SLAP_PGF1 SLAP_SCEW SLAP_SCEW

SLAP_PGFG SLAP_PGFG SLAP_SCHD SLAP_SCHD

SLAP_PGHB SLAP_PGHB SLAP_SCLD SLAP_SCLD

SLAP_PGLPSLAP_PGZP SLAP_SCNW SLAP_SCNW

SLAP_PGKN (New

LCA)SLAP_SDG1 SLAP_SDG1

SLAP_PGNB SLAP_PGNB Not defined SLAP_VEA

SLAP_PGNC SLAP_PGNC

SLAP_PGNV SLAP_PGNP

SLAP_PGP2 SLAP_PGP2

SLAP_PGSA SLAP_PGSI

SLAP_PGSB SLAP_PGSB

SLAP_PGSF SLAP_PGSF

SLAP_PGSI SLAP_PGSI

SLAP_PGSN SLAP_PGNP

SLAP_PGST SLAP_PGST

Page 74

CRR Modeling of change to Sub-LAPs

• Sub-LAP Changes

– Changes to Sub-LAP definitions were initially

intended for implementation on 1/1/2017

– A few days before the 2017 annual auction was to

open the ISO received notice of a concern with the

implementation of this change

– After review it was determined that there was a

possible exposure to the market and that the best

solution was to update the model to be used for the

annual auction ahead of schedule

CRR Modeling of change to SLAPs

• Sub-LAP Changes created multiple revisions to CRR FNM

– Since the process for developing the new Sub-LAPs was

outside of the normal process for developing this data

there were multiple revisions made to the CRR FNM

– These revisions created additional workload for our

participants as well as the ISO

– The CAISO recognizes the additional effort this required

for our participants

– Going forward we are not expecting the significant

changes that were seen this time and the updates will flow

through our normal change process and not be

implemented as they were this time

with update on Sub-Lap revision implementation for PDR/RDRR

Jill Powers

Smart Grid Solutions Manager, Smart Grid Technologies and Strategy

Slide 77

Model Enhancement for Distributed Energy Resources

UPDATE: SubLap Redefinition Implementation

Completed for PDR/RDRR

ISO and Demand Response Providers coordinated

PDR/RDRR registration activities to successfully transition

to new Sub-Laps

Page 78

• Effective 1/1/2017 Locations and Registrations reflect new

Sub-Lap areas

• Pre-defined Resources were made available for revised

Sub-Laps prior to 1/1/2017 to meet Resource Adequacy

(RA) processing timelines

Activities were completed prior to the Demand Response

Registration System (DRRS) Phase 2 Enhancements

November 30, 2016 deployment.

1/1/2017 Effective SubLap Selections Available in

DRRS

Slide 79

• Master file

effective dated

SubLaps

• Choices in

SUBLAP field are

determined by

Start Date/End

Date of location

• Any Location

created with Start

Date on or after

1/1/2017 can only

choose new

SUBLAPs

ISO Established Pre-Defined Resource ID Modeling Based

On 1/1/2017 Effective Sub-LAP Boundaries

80

2017 Sub-Lap Pre-Defined Modeling Impact

PGCC, PGEB, PGF1, PGFG, PGHB,

PGNC, PGP2, PGSB, PGSF, SCEW,

SCHD, SCNW, SDG1

No Change

PGNB, PGSI, PGST Distribution Factor Changes Only

SCEC, SCEN, SCLD Distribution Factor Change with added or

removed substation(s)

PGKN, PGNP, PGZP, VEA New

The ISO has posted a spreadsheet titled 2017 Sub-Load Aggregation

Point to California ISO Bus Mapping to its load participation and demand

response webpage

http://www.caiso.com/Documents/2017Sub-LoadAggregationPointToCaliforniaISOBusMapping.xls

A spreadsheet for 2017 Pre-Defined Resources Sub-LAP to Bus (Pnode)

to Distribution Factor association will be posted

http://www.caiso.com/Documents/2017Sub-LoadAggregationPointToCaliforniaISOBusMapping.xls

Model Enhancement Provides Ease of Resource ID

Implementation for all DERs

81

• Resource will be created on demand in the Masterfile when

requested through the GRDT process

– Significantly reduces processing timelines and management of

requests for a new Resource ID for DERAs

– Maintains Pre-Defined resource ID option for PDR/RDRRs

– Customizing DER resources no longer requires a Full Network

Model (FNM) update

More information on model change requirements are in the Energy Storage

and Distributed Energy Resource (ESDER) BRS:http://www.caiso.com/Documents/BusinessRequirementsSpecification-v10-EnergyStorageandDistributedEnergyResources.pdf

Deployed New Modeling Capability Before 1/1/2017

http://www.caiso.com/Documents/BusinessRequirementsSpecification-v10-EnergyStorageandDistributedEnergyResources.pdf

Release Plan Update

Janet Morris

Director, Program Office

Page 82

The ISO offers comprehensive training programs

83

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

Contact us - [email protected]

Date Training

February 7 Settlements 101 (Folsom)

February 8 Settlements 201 (Folsom)

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

mailto:[email protected]

Release Plan 2017

Page 84

Independent 2017

• Settlements Release - January 2017

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

• Reactive Power Requirements and Financial Compensation – no system changes

• Administrative Pricing Policy Update

• RIMS Functional Enhancements

Spring 2017

• Acceptable Use Policy – CMRI

• RTD Local Market Power Mitigation (LMPM) Enhancements

• CRR Clawback Modifications

• PIRP System Decommissioning

• Metering Rules Enhancement

Fall 2017

• Bidding Rules Enhancements – Part B

• Reliability Services Initiative Phase 1B

• Reliability Services Initiative Phase 2

• Commitment Cost Enhancement Phase 3

• RTM & EIM 2017 Enhancements

• EIM Portland General Electric (PGE)

Release Plan – 2018 and subject to further planning

Page 85

Spring 2018

• EIM 2018 Idaho Power Company

Fall 2018 – tentative, subject to impact assessment

• Bid Cost Recovery Enhancements

• Generation Contingency and Remedial Action Scheme

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

• Frequency Response Phase 2

• Contingency Modeling Enhancements

• Commitment Costs and Default Energy Bid Enhancements

• ADS User Interface Replacement

Subject to further release planning:

• ESDER Phase 2

• Stepped Transmission Constraints

• Regional Resource Adequacy

• Regional Integration and EIM Greenhouse Gas Compliance

• Transmission Access Charge Options

Page 86

Settlements Release – January 2017

ISSUE SUMMARY BPM IMPACTED

Update BPM for charge code 6478 real-time system imbalance energy offset and CC 6985 real-time marginal losses offset to align the documentation with the current active settlement configuration

PRR 946: ( CC 6478 and CC 6985) Documentation Only

Updated BPM for metered energy adjustment factor pre-calculation to clarify conversion of ramp rate in minutes to MWh

PRR 947: (PC Metered Energy Adjustment Factor)

Updated capacity procurement mechanism (CPM) related configuration guides to re-formulate the eligible CPM capacity designation quantity and pass through bill functionality

PRR 948: (PC Metered Demand over TAC Area, CC 7891, and CC 7896 )

Update BPM configuration guide for spin non-spin no pay pre-calculation to retroactively adjust calculation impacting resources without regulation schedules

PRR 949: (PC Spin Non-Spin No-Pay)

Update BPMs for start-up and minimum load cost and integrated forward market net amount pre-calculation to implement bidding rules enhancement Pmin rerate Pmax derate settlements

PRR 955: ( PC Start-up Metered Energy Adjustment Factor v.5.14, and PC IFM Net Amount)

Update configuration guides in accordance with administrative pricing initiative to settle congestion revenue rights at the average hourly fifteen minute market price when specific conditions are triggered

PRR 956: (CC 6700)

Update existing BPM for real-time net amount pre-calculation to exclude hourly block bid opted intertie resources flex ramp product settlement amounts in bid cost recovery

PRR 957: (PC RTM Net Amount)

Update real time market net amount pre-calculation for regulation up and regulation down bid cost recovery costs

PRR# 958 (PC RTM Net Amount)

Updated calculation of day ahead and real time self-scheduled bids for resource adequacy availability incentive mechanism

PRR# 959 (PC RA Availability Incentive Mechanism)

Updated calculations and business rules for RA Availability Incentive Mechanism settlement

PRR# 960 (PC RA Availability Incentive Mechanism, CC 8830, and CC 8831)

Page 87

Settlements Release – January 2017

Milestone Date Status

Configuration Guides Posted December 13, 2016

First DRAFT Configuration Output File Posted December 15, 2016

Second DRAFT Configuration Output File Posted January 13, 2017

Pre-Production DRAFT Configuration Output File Posted January 17, 2017

Production Deployment January 24, 2017

FINAL Configuration Output File Posted January 24, 2017

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.

BPM Changes None

Business Process ChangesPotential Level-II business process changes under –

• Manage Market & Reliability Data & Modeling

• Manage Operations Support & Settlements

Page 88

Milestone Type Milestone Name Dates Status

Board Approval Board Approval N/A

BPMs Metering BPM Changes N/A

External BRS Post External BRS Nov 14, 2016

Tariff Pre-Tariff Filing QRB N/A

Config Guides Configuration Guide N/A

Tech Spec Publish Tech Specs Nov 02, 2016

Market Simulation Phase 2 - MRI-S Metering Enhancements Feb 01, 2017 - Feb 28, 2017

Production Activation Phase 1 - ACL Groups Feb 01, 2017

Phase 2 - MRI-S Metering Enhancements Mar 08, 2017

MRI-S ACL Groups + CPG Enhancements

Page 89

* 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

MRI-S ACL Groups + CPG Enhancements

Page 90

Per last fall’s Customer Partnership Group discussions, the ISO will be not be

performing any user access migration, including the current third party access in

OMAR to AIM because:

• The platform and business logic for third party access are completely different

between OMAR and AIM, so no automation is possible

• Any effort by the ISO would be manual, and would require heavy market

participant involvement due to data integrity questions around security and

third-party access concerns

• The data in OMAR is historical (aged) and therefore must be vetted by the

Scheduling Coordinators to ensure its validity

2017 – Reactive Power Requirements and Financial Compensation


Application Software Changes None

BPM Changes None

Business Process Changes

Develop Infrastructure (DI) (80001)

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

Page 91


Board Approval BOG Approval N/A

BPMs Post Draft BPM changes N/A

External BRS Post External BRS N/A

TariffFile Tariff

FERC Approval

Dec 6

Feb 6

Config Guides Prepare Draft Configuration Guides N/A

Tech Spec Publish Tech Specs N/A

Market Sim Market Sim Window N/A

Production Activation Reactive Power Requirements and Financial Compensation March 6, 2017

2017 – Administrative Pricing Policy Updates

Page 92



• MQS:

• Part 1 (used under normal market conditions): If there are less than 12 RTDs and 4

RTPDs missing – leverage existing process (last price used)

• Part 2 (used under normal market conditions): If RTD prices are available copy over

to RTPD; RTPD prices available copy over RTD. If neither RTPD or RTD prices are

available use DA prices

• Part 3 (used Market Suspension conditions): Use DA prices. If we don’t have DA

prices, revert to prior DA prices (awards and prices)

Business Process Change • Manage Markets and Grid

BPMs Market Instruments, Market Operations


Board Approval BOG Approval Dec 10, 2014

BPMs Post Draft BPM changes Jan 6, 2017

External BRS Post External BRS Mar 20, 2015

Tariff File Tariff Nov 23, 2016

Config Guides Prepare Draft Configuration Guides Dec 2, 2016

Tech Spec Publish Tech Specs N/A


Production Activation Bidding Rules Part B Feb 01, 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

Page 93


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 TBD

Spring 2017 – 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.

Page 94



BPMs BPMs N/A

External BRS External BRS N/A

Tariff Tariff N/A

Config Guides Config Guide 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 Apr 1, 2017

Spring 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


• 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

Page 95

Spring 2017 - Real Time Dispatch Local Market Power Mitigation

Page 96

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

External BRS Post External BRS Apr 05, 2016

Tariff Received FERC approval Nov 08, 2016

Tech Spec Publish Technical Specification - OASIS Apr 08, 2016

Publish Technical Specification - CMRI Apr 14, 2016

Market Sim Market Sim Window Jan 31, 2017 - Feb 16, 2017

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

Spring 2017 – Congestion Revenue Rights (CRR) Clawback



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

Page 97


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

Spring 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.

Page 98

Spring 2017 – PIRP Decommissioning

Page 99



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 Mar 02, 2017 - Mar 20, 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 April 1, 2017

Spring 2017 – Metering Rules Enhancements


Application Software Changes N/A

BPM Changes

Metering

• Metering BPM will be updated to reflect the ISO ME vs SC ME role

options, changes to the metering entity election process, and impacts

for metering data access via the metering data submission portal.

• 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)

Page 100

Spring 2017 – Metering Rules Enhancements

Page 101


Board Approval Board of Governors (BOG) approval Dec 14, 2016

BPMs Market Operations BPM Feb 02, 2017

Energy Imbalance Market BPM Feb 02, 2017

External BRS External Business Requirements N/A

Tariff Tariff Filing at FERC Feb 01, 2017

Config Guides Config Guides N/A



Production Activation Metering Rules Enhancements Apr 01, 2017

Fall 2017 - Bidding Rules Enhancements – Part B

Page 102



• 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

BPMs Post Draft BPM changes Jun 15, 2017

External BRS Post External BRS Jan 13, 2017

Tariff File Tariff Jun 01, 2017

Config Guides Prepare Draft Configuration Guides Apr 03, 2017

Tech Spec Publish Tech Specs Apr 03, 2017

Market Sim Market Sim Window Aug 08, 2017 – Sept 08, 2017

Production Activation Bidding Rules Part B Nov 01, 2017

Fall 2017 - Reliability Services Initiative Phase 1B

Project 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

Page 103


Board Approval Board Approval May 12, 2015


External BRS Post External BRS Dec 23, 2016


Config Guides Config Guide Apr 03, 2017

Tech Spec Publish Technical Specifications Apr 03, 2017


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

Fall 2017 – Reliability Services Initiative Phase 2



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 handle EFC monthly updates similar to NQC

(workflow change)

• 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


Manage Market & Reliability Data & Modeling

- Manage Monthly & Intra-Monthly Reliability Requirements

- Manage Yearly Reliability Requirements

Page 104

Fall 2017 – Reliability Services Initiative Phase 2

Page 105


Board Approval Board of Governor's Approval Oct 27, 2016





Tech Spec Publish Technical Specifications Apr 03, 2017


Production Activation Reliability Services Initiative Phase 2 Nov 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

Page 106

Fall 2017 - Commitment Cost Enhancements Phase 3

Page 107

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


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


Publish Final Business Practice Manuals TBD


Tariff File Tariff TBD

Receive FERC order TBD


Tech Spec Create ISO Interface Spec (Tech spec) Apr 03, 2017


Production Activation Commitment Costs Phase 3 Nov 01, 2017

Fall 2017 – RTM & EIM Enhancements 2017



Address enhancements identified by policy, operations, technology,

business and market participants.

Requirements are being evaluated for the following:

• EIM Entity access reports

• BAAOP provisioning in AIM

• EIM data report enhancements to support market participant and EIM

entity shadow 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

• Combine the import/export under/over-scheduling histograms to a

single net interchange under/over-scheduling histogram

BPM Changes TBD

Business Process Changes TBD

Page 108

Page 109

Fall 2017 – RTM & EIM Enhancements 2017 (cont.)


BPMs Draft BPM changes TBD

Post Draft BPM changes TBD

Publish Final Business Practice Manuals TBD


Tariff File Tariff TBD

Receive FERC order TBD

Config Guides Design review - BPM and Tariff SMEs TBD

Tech Spec Fall 2017 - Technical Specifications due to external clients Apr 03, 2017


Production Activation EIM Enhancements 2017 Nov 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

Page 110


Board Approval Board of Governors (BOG) approval N/A

BPMs BPMs N/A

External BRS External Business Requirements N/A

Tariff File EIM Readiness Certification Aug 31, 2017


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

Production Activation EIM – Portland General Electric Oct 01, 2017

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

December 1, 2017 – January 31, 2018

ISO and Idaho Power continue progress to integrate the Idaho Power

network model with the ISO model in a non-production environment to

allow Idaho Power to exchange data in advance of Market Simulation.

Initial integration testing is expected to begin in August 2017.

Parallel Operations February 1, 2018 – March 31, 2018

Page 111



BPMs BPMs N/A

External BRS External BRS N/A

Tariff File Tariff Changes with FERC N/A

Receive Final FERC Order Tariff Changes N/A

Config Guides Config Guide N/A

Tech Spec Tech Specs N/A

Production Activation EIM - Idaho Power Apr 04, 2018

Short-Term Plan OASIS

The updated OASIS Technical Specifications v4.3.3 include changes

noted below:

Page 112

API Report Name Existing Version(XML & CSV) Proposed New Version(XML & CSV)

PRC_INTVL_LMP- Changes apply to

Group Zip Only

One file with all price components within the

same zip file- LMP, Congestion , Energy,

Loss and GHG

Separate file for each price component within the same

zip file - LMP, Congestion , Energy, Loss and GHG

PRC_RTPD_LMP - Changes apply to

Group Zip Only



Loss and GHG



PRC_HASP_LMP - Changes apply to

Group Zip Only


same zip file- LMP, Congestion , Energy and

Loss


zip file - LMP, Congestion , Energy and Loss

PRC_SPTIE_LMP(RTD,RTPD)-

Changes apply to Group Zip only



Loss and GHG



TRNS_CURR_USAGE

Request allows for past , current and future

trade dates

No change to current and future trade dates . System

will throw - "Invalid Request Error" for requests with

past trade dates.

TRNS_CURR_USAGE &

TRNS_USAGE

No restriction on number of transmission id's

requested in single zip.

System will throw error 1017 which is “Please select a

maximum of 10 nodes or use the ALL option.” when

you are requesting data for more than 10 transmission

id's for single zip.


OASIS API changes based on query type:

XML Report Name Market Run ID Version Query Type Response file

PRC_INTVL_LMP RTM 3 Single node

One file with all price components within the same zip file- LMP,

Congestion , Energy, Loss and GHG

PRC_INTVL_LMP RTM 3 ALL_APNODES



PRC_INTVL_LMP RTM 3 ALL

Separate file for each price component within the same zip file -

LMP, Congestion , Energy, Loss and GHG

PRC_HASP_LMP HASP 3 Single node



PRC_HASP_LMP HASP 3 ALL_APNODES



PRC_HASP_LMP HASP 3 ALL



PRC_RTPD_LMP RTPD 3 Single node



PRC_RTPD_LMP RTPD 3 ALL_APNODES



PRC_RTPD_LMP RTPD 3 ALL



PRC_SPTIE_LMP RTD,RTPD 5 Single node



PRC_SPTIE_LMP RTD,RTPD 5 ALL_APNODES



PRC_SPTIE_LMP RTD,RTPD 5 ALL



Page 113


OASIS API New Versions - Transition Schedule :

Market Simulation Testing Period : 1/3/2017 - 1/22/2017

Production Transition Period : 1/23/2017 – 2/19/2017

Page 114

XML Report Name Market Run ID Group Name Version

Transition Period in

Production

(01/23/2017-2/19/2017)

After Transition Period(2/20/2017

onwards)

PRC_INTVL_LMP RTM RTM_LMP_GRP 1 Supported Not Supported/ Invalid Request

PRC_INTVL_LMP RTM RTM_LMP_GRP 2 Supported Not Supported/ Invalid Request

PRC_INTVL_LMP RTM RTM_LMP_GRP 3 Supported Supported

PRC_HASP_LMP HASP HASP_LMP_GRP 1 Supported Not Supported/ Invalid Request

PRC_HASP_LMP HASP HASP_LMP_GRP 2 Supported Not Supported/ Invalid Request

PRC_HASP_LMP HASP HASP_LMP_GRP 3 Supported Supported

PRC_RTPD_LMP RTPD RTPD_LMP_GRP 1 Supported Not Supported/ Invalid Request

PRC_RTPD_LMP RTPD RTPD_LMP_GRP 2 Supported Not Supported/ Invalid Request

PRC_RTPD_LMP RTPD RTPD_LMP_GRP 3 Supported Supported

PRC_SPTIE_LMP RTD,RTPD

RTD_SPTIE_LMP_GRP,

RTPD_SPTIE_LMP_GRP 3 Supported Not Supported/ Invalid Request


RTD_SPTIE_LMP_GRP,

RTPD_SPTIE_LMP_GRP 4 Supported Not Supported/ Invalid Request


RTD_SPTIE_LMP_GRP,

RTPD_SPTIE_LMP_GRP 5 Supported Supported

CAISO Web Layer Maintenance

• CAISO is in the process of upgrading UI, web services, and ads web

layer technology to newer versions

– Maintain vendor recommended and supported software versions

• Linux Operating System, Apache, Actional Intermediary

– Add support for newer security protocols

• TLS 1.1 and TLS 1.2

– Improve supportability – Add additional logging forensics and

diagnostics to help address Production issues

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• URL’s which will be affected by this upgrade:– Note: MAPStage has already been upgraded!

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MAPStage Production

https://portalmap.caiso.com https://portal.caiso.com

https://portaleimmap.caiso.com https://portaleim.caiso.com

https://wsmap.caiso.com https://ws.caiso.com

https://wsstas.caiso.com:4445

https://idpmap.caiso.com https://idp.caiso.com

https://reportingmap.caiso.com https://reporting.caiso.com

https://adsmap.caiso.com:447 https://adssta.caiso.com:447

https://ads.caiso.com:447

https://portalmap.caiso.com/

https://portal.caiso.com/

https://portaleimmap.caiso.com/

https://portaleim.caiso.com/

https://wsmap.caiso.com/

https://ws.caiso.com/

https://wsstas.caiso.com:4445/

https://idpmap.caiso.com/

https://idp.caiso.com/

https://reportingmap.caiso.com/

https://reporting.caiso.com/

https://adsmap.caiso.com:447/

https://adssta.caiso.com:447/

https://ads.caiso.com:447/


• Changes participants should expect:

– Brief system failovers (will communicate and keep to a minimum)

– HTTP error page look/feel will be standardized

– B2B WSDL’s generated by the new software @ CAISO may have slight formatting

differences or namespace declarations.

– RESOLVED: SOAPAction HTTP header is now required to be set for web service

transactions

• Note: This item was required as a vendor product default setting; we have disabled.

Sorry for the confusion

• What will not be changing:

– oasis.caiso.com and www.caiso.com sites will not be upgraded as part of this effort

– AUP (Acceptable Use Policy)

• Additional enforcement is not scheduled to be implemented alongside this work; but will

be communicated via a separate market notices. May go in around the same time.

• AUP violation HTTP return code will remain using HTTP code 429

– URL’s, naming conventions. We will keep all the same current domain names, and URI’ as

provided in the System Access Information document

– IP Addresses including ECN traffic, routing, and AT&T NAT addressing will not change

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http://www.caiso.com/


• What we would like from you now:

– Please test your critical web service calls in MAPStage

– We would like help testing MNS messages as before

• Other upcoming web layer changes scheduled or proposed for 2017:

– The Legacy webservices URL https://wsstas.caiso.com:4445 will be scheduled for

decommission soon. These URL’s will all work when pointed to https://ws.caiso.com

• Exact date/process will be scheduled and communicated.

– The Production alias https://adssta.caiso.com:447 will be retired in 2017. We would like to

ensure all clients are using https://ads.caiso.com:447. This may require an ADS client

upgrade.


– Support for TLS 1.0 will be removed in 2017.


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https://wsstas.caiso.com:4445/

https://ws.caiso.com/

https://adssta.caiso.com:447/

https://ads.caiso.com:447/


• Questions???

– Please create CIDI tickets for tracking purposes

– You may call the CAISO Help Desk @ 916-351-2309

– You may reach John Huetter, Systems Integration @ 916-608-5839

For all support tickets, please provide (the more information, the

quicker we can resolve):

– CAISO URL you attempted

– Error Message, Error Code, Screenshot

– Time of transaction, please include seconds if possible

– Certificate Used

– Source IP (If available)

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ISO Daily Briefing

• A digest version of ISO market notices

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

• To subscribe:

Go to www.caiso.com

Under “Stay Informed” tab

Select “Notifications”

Click Subscribe here under Market notices heading

Note: If you currently receive ISO market notices and

you re-subscribe, the system will override your previous

category selections. You’ll need to reselect categories

of interest.

Page 120

http://www.caiso.com/

Market Performance and Planning Forum

2017 Schedule

• 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

Page 121