Market Performance and Planning Forum - California ISO · Market Performance and Planning Forum March 14, 2017 Last updated: March 15, 2017. Objective: Enable dialogue on implementation

Market Performance and

Planning Forum

March 14, 2017

Last updated: March 15, 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

Page 2

Market Performance and Planning ForumAgenda – March 14, 2017

Time: Topic: Presenter:

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

10:05 – 10:20 - SDG&E Crosstrip Nomogram

- Peak RC Process Update

Dede Subakti

10:20 – 11:30 Market Performance and Quality Update Guillermo Bautista Alderete

Nancy Traweek

Amber Motley

11:30 – 12:00 Policy Update Brad Cooper

12:00 – 1:00 Lunch

1:00 – 1:30 Renewable generation market impacts Gabe Murtaugh

1:30 – 2:30 Release Update Adrienne Chiosea

Janet Morris

Slide 4

Dede Subakti

Director, Operations Engineering Services

SDG&E Crosstrip Nomogram

Background

• High East-West flow on 500 kV lines into Southern California system

• Contingency of TL50001 could cause overload in the underlying

parallel 230kV lines that would cause RAS to cross trip and open up

another 230kV line

• Objective of the mitigation is to avoid overload in the underlying

parallel 230kV lines and avoid cross tripping.

• Mitigation: nomogram 7820_TL23040_IV_SPS_NG

Page 5

Nomogram definition

• Nomogram definition is posted in CMRI

• The nomogram definition takes into account expected

RAS actions

– Note: Specific RAS information cannot be made public due to

the nature of the data classification

• Objective of the nomogram is to avoid overload in the

underlying parallel 230kV lines and avoid cross tripping

• Limit may be conformed up and down based on the real

time limit based on the real time condition and availability

of RAS

Page 6

Slide 7

Peak RC Process Update

Two New Processes Effective April 1, 2017

• New RC wide outage coordination process to meet the

new NERC IRO-017 Reliability Standard

• New RC System Operating Limit (SOL) methodology to

meet the spirit of the new NERC TOP/IRO Reliability

Standard

Page 8

Impact of IRO-017

• CAISO has filed modification to Section 9 of its Tariff and

the BPM for Outage Management is updated

• Every BES equipment outage requires RC’s

approval/confirmation

– webOMS is updated accordingly to show the RC’s

approval/confirmation

Page 9

Impact of New SOL Methodology

• It impacts how CAISO calculate System Operating Limit

• Excerpt from the new methodologyWECC Paths do not have single uniquely monitored SOLs unless the WECC

Path is associated with an established transient or voltage stability limit;

however, WECC Paths that are associated with scheduling will continue to have

TTCs

...

This SOL Methodology does not recognize WECC Path Ratings as SOLs.

WECC Path Ratings are determined in the planning horizon per the voluntary

WECC three-phase rating process. As stated earlier, this SOL Methodology

recognizes SOLs to be the Facility Ratings, System Voltage Limits and stability

limitations used in operations. If a WECC Path Rating is determined to be

“stability limited” per the WECC three-phase rating process, this information can

be used by TOPs and the RC to perform further analysis to determine if a

stability limit should be established for use in the Operations Horizon; however,

the “stability limited” WECC Path Rating itself is not automatically

considered as a stability limit (SOL) for use in the Operations Horizon

Page 10


• Excerpt from the new methodologyWhile Peak will continue to monitor WECC Path flow relative to WECC Path

TTC values for situational awareness purposes, Peak does not acknowledge the

TTC as a SOL and does not require operation within TTC values or WECC Path

Ratings. Peak monitors the entire BES for SOL exceedance (as described in the

SOL Methodology) and implements Operating Plans as required to address

instances of SOL exceedances as determined by RTAs

Nomograms may be used to provide System Operators with helpful guidance as

part of an Operating Plan; however, they are not considered to be SOLs unless

the nomogram represents a region of stability (i.e., the nomogram defines a

stability limit).

Page 11


• Nomogram naming convention are going to changed

• Since they are not considered SOL, the name SOL will

be taken out of nomogram that are non-stability related

• The new naming convention will utilize the term “Control

Point” (CP)

• Procedure:

– Control Point (CP): ####_CP#_NG

– Stability Limitation: ####_SOL#_NG

• Outage:

– OMS_#######_CP#_NG

– OMS_#######_SOL#_NG

Page 12

Market Performance and Quality Update

Guillermo Bautista Alderete, Ph.D.

Director, Market Analysis and Forecasting

Nancy Traweek

Executive Director, System Operations

Amber Motley

Manager, Short Term Forecasting

Slide 13

Over-Supply Update

Page 14

Page 15

ISO total monthly VERS schedules and forecasts

Page 16

IFM under-scheduling of solar generation

Page 17

IFM under-scheduling of wind generation

Monthly wind (VERS) downward flexibility in FMM

Page 18

Monthly solar (VERS) downward flexibility in FMM from

11 AM to 5 PM

Page 19

Page 20

Hydro production already higher than recent historical

production

Page 21

RTD renewable (VERS) curtailment trended upward since

last August

How are curtailments determined?

• Priority on real-time schedule types are managed based

on synchronized relaxation parameters that are listed in

BPM

• If economic bids are exhausted self-schedules may be

curtailed pursuant to priority

• Any self-schedule curtailment based relaxation

parameter is communicated through ADS

Page 22TOR/ETC

IFM self schedule

RMT

Price taker

PBC violation

Economical bids

Frequency of negative system prices has steadily

increased year over year

Page 23

0%

2%

4%

6%

8%

10%

12%

14%

16%

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*

Page 24

0%

5%

10%

15%

20%

25%

30%

35%

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

* Metric of 2017 may be over-estimated since it includes only January and February.

Page 25

Hydro production is trending higher for Spring

Page 26

Self schedules in the real-time market remain high

Transfer from the ISO to other EIM areas has

increased

Page 27


0

50

100

150

200

250

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

Ave

rage

Tra

nsf

er (

MW

)

2016 2017

The gross volume of transfers out of the ISO BAA

occurs during midday hours

Page 28


0

50

100

150

200

250

300

350

400

450

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

Tran

sfer

(M

W)

2016 2017

The maximum transfer from the ISO to other BAAs in

in 2017 have been the highest

Page 29


0

500

1000

1500

2000

2500

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

Max

imu

m T

ran

sfer

(M

W)

2016 2017

Load profile in Spring sets conditions for oversupply

Page 30


15,000

20,000

25,000

30,000

35,000

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

(MW

)

March 2016

Net Gross

15,000

20,000

25,000

30,000

35,000

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

(MW

)

April 2016

Net Gross

15,000

20,000

25,000

30,000

35,000

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

(MW

)

May 2016

Net Gross

15,000

20,000

25,000

30,000

35,000

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

(MW

)

June 2016

Net Gross

Gross versus Net Load in Spring 2016

Generation oversupply leading to potential

curtailments expected this Spring

• Real Time Operations is expecting significant oversupply

of generation this spring due to load system demand,

exceptional hydro condition, increases solar and wind

production.

• Generation that is not scheduled in the Day Ahead

Market will impact Real Time operations leading to

potential self scheduled generation curtailments

• Identifying oversupply indicators in the D+2 and D+1

timeframe to provide MPs advanced notice of low

demand and oversupply conditions

• Operators will manage real time conditions in

accordance with Overgeneration procedure 2390

Slide 31

Very short term forecast of potential oversupply

Page 32


Oversupply Risk

Net Load

< 20,000 MW

VER Forecast

> 5,000 MW

Cloud Cover Forecast

Wind Speed Forecast

Load Forecast < 25,000 MW

Temperature Forecast

Hydro Self Schedule

> 3,500MW

Current solar capacity is capable of increasing the risk of oversupply without factoring in wind or

hydro schedule

Using daily average numbers

Very short term forecast of potential oversupply

Page 33


Oversupply Risk

Net Load

< 16,000 MW

VER Forecast

> 5,500 MW

Cloud Cover Forecast

Wind Speed Forecast

Load Forecast < 21,500 MW

Temperature Forecast

Hydro Self Schedule

> 4,000 MW

Current solar capacity is capable of increasing the risk of

oversupply without factoring in wind or hydro schedule

Using daily average numbers

Aliso Canyon Nomogram

SoCalGas issued natural gas curtailment watches this

winter.

• SoCalGas issued curtailment watches from January 23

through January 26 arising from cold temperatures and

forecasted high gas demand

• The CAISO implemented gas burn constraints in the

day-ahead and real-time markets to limit the gas burn by

electric generation in SCE and SDG&E areas

• SoCalGas withdrew gas from Aliso Canyon on January

24-25 to maintain gas pressures in its system

• No gas curtailments to date necessary

Slide 35

Additional safety measures for natural gas storage will

further constrain SoCalGas operations.

• Constraints at Aliso Canyon for withdraws or injections

this summer will likely continue

• On February 23, 2017 SoCalGas posted a notice

outlining a Storage Safety Enhancement Plan

• Beginning March 1, SoCalGas will implement storage

enhanced safety measures at La Goleta, Playa del Rey

and Honor Rancho

• SoCalGas forecasts reductions in the maximum

withdrawal capabilities at these gas storage facilities

Slide 36

Gas conditions in the market were managed using gas

nomograms

• The ISO enforced two gas nomograms during the

curtailment watches.

MAXBURN_ALISO_SDGE and

MAXBURN_ALISO_TOTAL

• Shadow prices posted on OASIS

• Pricing locations do not reflect the shadow prices of the

gas nomograms

Shadow Prices of MAXBURN_ALISO_SDGE Nomogram

show instances where the nomogram had to be relaxed

Shadow Prices of MAXBURN_ALISO_TOTAL show

constraint relaxation in some instances

Compare RTD, IFM and RUC Gas Burn for all gas

resources (fuel provided by SoCalGas)

Date RTD (Mmcfd) IFM (Mmcfd) RUC (Mmcfd)

1/23/2017 410 427 501

1/24/2017 441 448 507

1/25/2017 446 455 484

1/26/2017 458 428 486

Comparison among IFM, RUC and RTD gas burns

Flexible Ramp Update

Flexible Ramp Product Up Requirement

Flexible Ramp Product Down Requirement

Flexible Ramp Product Up Awards

Flexible Ramp Product Down Awards

Most of the time the EIM area is binding.

Average Flexible Ramp Up Price ($/MWh)

Average Flexible Ramp Down Price ($/MWh)

Settlement of Flexible Ramp Product

• FMM Forecasted Movement Settlement = -1*FMM

forecasted movement quantity * (FMM FRU Price – FMM

FRD Price)

• RTD Forecasted Movement Settlement = -1*(RTD

forecasted movement quantity – FMM forecasted

movement quantity) * (RTD FRU Price – RTD FRD

Price)

• Allocation – Scheduling Coordinators with metered

demand (pro-rata share).

Forecasted Movement

Binding Advisory …

Forecasted Ramp

A A

Binding Advisory A

RTD Upward example 9:15 9:20 9:25 9:30

Run time

9:07.5 for 9:15

90 MW 100 MW 110 MW

…

Forecasted Movement = 100 – 90 = 10 MW (upward)

Settlement = -1*10 MW * ($20 (FRU) - $10 (FRD)) = -$100 (Payment)

Binding Advisory A

RTD downward example 9:15 9:20 9:25 9:30

Run time

9:07.5 for 9:15

90 MW 85 MW 75 MW

…

Forecasted Movement = 90 – 85 = 5 MW (downward)

Settlement = -1*5 MW * ($10(FRU) - $15 (FRD)) = $25 (Charge)

Forecasted Movement Settlement ISO – From

November 1 to February 28, 2017

Scheduled Settlement

Correction

Uncertainty Movement – Example

Binding Advisory

B A …

ARTD Run 1

RTD Run 2

9:15 9:20 9:25 9:30

Run time

9:07.5 for 9:15

Run time

9:12.5 for 9:20

90 MW 100 MW 110 MW

107 MW 113 MW

…

Uncertainty movement = 107 – 100 MW = 7 MW (upward)

Uncertainty Up Settlement has increased in recent

months

Once normalized for capacity procured, FRP

settlements in the same range as in prior months

FRP Up Uncertainty Payment Amount – Nov 1, 2016

to February 2017

FRP Down Uncertainty Payment Amount – Nov 1,

2016 to February 28, 2017

Flex Ramp Up Payment following hourly ramp profile

Flex Ramp Down Payment – Hourly Distribution

Market Update

Page 59


Page 60

Good price convergence between FMM and RTD in February.

Page 61

RT prices lower than DA prices for both NP15 and SP 15 in

January and February.

Page 62

Insufficient upward ramping capacity in ISO stayed at low

levels since last November.

Page 63

Insufficient downward ramping capacity increased in


Page 64

Congestion revenue rights market revenue inadequacy

without auction revenues.

Page 65

Congestion revenue rights market revenue sufficiency

including auction revenues.

Page 66

Exceptional dispatch volume in the ISO area remained low in


Page 67

Daily exceptional dispatches by reason

Page 68

Real-time Bid cost recovery increased slightly in January

and February

Page 69

Bid cost recovery (BCR) by Local Capacity Requirement area

Page 70

Minimum online commitment (MOC)

Page 71

Pmax of MOC Cleared Units

Page 72

Enforcement of minimum online commitments in

November and December

MOC NameNumber (frequency) of hours in

January and February

Humboldt 7110 1397

MOC East Nicolaus 1128

Orange County 7630 383

DEVERS SOUTH MOC 68

MOC Devers South 35

MOC Drum 30

MOC SAN ONOFRE BUS 25

MOC Wise 4611490 15

MOC Pease 10

MOC Moss 4513897 10

SCIT MOC 9

SDGE 7820 All In Service 4

Page 73

Renewable (VERS) schedules including net virtual supply

and aligns with VER forecast in January and February

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 74

Hourly distribution of maximum RTD renewable (VERS)

curtailment in February

Page 75

ISO area RTIEO increased in January and February.

2016 2017 (YTD)

RTCO $50,468,470 $3,434,789

RTIEO -$3,797,744 $9,402,400

Total Offset $46,670,726 $12,837,189

Page 76

CAISO Price correction events increased in February

0

1

2

3

4

5

6

7

8

9

10Ja

n-1

6

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

Co

un

t o

f Ev

ents

Process Events Software Events Data Error Events Tariff Inconsistency

Page 77

EIM-Related Price correction events increased in February

0

2

4

6

8

10

12

14

16

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

2016 2017

Co

un

t o

f Ev

ents

Process Events Software Events Data Error Events Tariff Inconsistency

EIM Interruption in NV Energy balancing area

• 3/6/17 17:35 to 3/10/17 18:00 EIM Interruption in NVE

BAA declared due to planned transmission outage

resulting in split of NVE system

• Interruption declared to mitigate potential abnormal

conditions resulting from split of imbalance conditions

• During interruption EIM transfer to/from NVE were

limited while NVE maintained balance

• Posted prices are being reviewed and subject to

administrative pricing or price corrections.

EIM Price trends

Page 79

EIM transfers between BAAs*

Page 80

PAC

W

PAC

E

NEV

P

AZP

S

PSE

I

(304MW, 1230MW)

(123MW, 917MW)

(88MW, 300MW)

(24

4M

W, 9

63

MW

)

(93

MW

, 7

66

MW

)

(0MW, 0MW)

*Notation: (average, maximum)

Page 81

EIM BCR declined in February

Page 82

EIM Manual Dispatch increased in February

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

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

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.

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.

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.

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.

Policy Update

Brad Cooper

Manager, Market Design and Regulatory Policy

Page 89

Ongoing policy stakeholder initiatives

• Bid cost recovery enhancements

– Suspended due to FERC uplift allocation NOPR

• Stepped constraint parameters

– Closed initiative

– Will address changes to penalty prices appropriate for for increased

bid cap under FERC Order 831 separately

• Contingency modeling enhancements

- Fourth revised straw proposal including prototype results in late

March to early April

- July CAISO Board Meeting

Page 90

• Generator contingency and remedial action scheme

modeling

– Revised straw proposal posted March 15

– July EIM Governing Body and CAISO Board Meeting

• Energy storage and distributed energy resources (ESDER)

Phase 2

– Publish third revised straw proposal in April

– July CAISO Board meeting

– Publish ESDER Phase 3 issue paper in September

Page 91

Ongoing policy stakeholder initiatives (continued)


• Commitment Costs and Default Energy Bid Enhancements

– Stakeholder workshops in late March and April

– Straw proposal in May

– September 2017 EIM Governing Board and CAISO Board

Meetings

• EIM Greenhouse Gas Enhancements

– Coordinating with ARB

– Developing approach to evaluate two-step model prior to

finalizing design

– Late 2017/early 2018 EIM Governing Board and CAISO Board

Meetings

Page 92


• Flexible resource adequacy criteria and must-offer

obligation – phase 2

– Q1 2018 CAISO Board Meeting

– Q2 2018 FERC Filing

• Frequency response – phase 2

– Late March workshop

– 2018 CAISO Board Meeting

• Review Transmission Access Charge Structure

– Background white paper published in late March

– Publish issue paper first week of July

• Blackstart and system restoration phase 2

– Final draft proposal and stakeholder call in March

– May CAISO Board meeting with associated Tariff changes

Page 93

Policy stakeholder initiatives coming soon

• Planned to start in Q2 2017

– Resource adequacy enhancements

• Stakeholder engagement estimated in Q3

– Economic and maintenance outages

• Publish Issue paper in in April

– CRR auction efficiency

• Stakeholder working group on analysis in late March – early

April

– Management of EIM Imbalance Settlement for Bilateral

Schedule Changes

• Schedule TBD

– Risk-of-Retirement Process Enhancements

• Schedule TBD

Page 94

Renewable generation market impacts

Gabe Murtaugh

Senior Analyst, Monitoring and Reporting

Department of Market Monitoring

Page 95

Solar generation increased by almost 33

percent in 2016.

Page 96

0

5,000

10,000

15,000

20,000

25,000

Solar Wind Geothermal Biogas/Biomass

Ge

ne

rati

oin

(G

Wh

)

2013 2014 2015 2016

Prices mirrored net load patterns in 2016.

Page 97

0

5,000

10,000

15,000

20,000

25,000

30,000

35,000

$0

$10

$20

$30

$40

$50

$60

$70

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

rag

e n

et

sys

tem

lo

ad

(M

W)

Pri

ce

($/M

Wh

)

Day-ahead 15-minute Average net load

As the ISO integrated more renewables,

prices have been negative more frequently.

Page 98

0%

1%

2%

3%

4%

5%

6%

2012 2013 2014 2015 2016

Pe

rce

nt

of

5-m

inu

te in

terv

als

Below -$145 -$145 to -$50 -$50 to $0

As more solar has been added, negative

price patterns have shifted.

Page 99

0%

2%

4%

6%

8%

10%

12%

14%

16%

18%

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

Pe

rce

nt

of

ne

ga

tive

5-m

inu

te i

nte

rva

ls

2012 2014 2016

Participants typically bid solar into the

market between -$25/MWh and $0/MWh.

Page 100

-1,500

-1,000

-500

0

500

1,000

1,500

2,000

2,500

3,000

below -$50 -$50 to -$25 -$25 to $0 $0 to $25 $25 to $50 above $50

Ave

rag

e h

ou

rly M

W

Natural Gas Hydro Geothermal Wind Solar Other

Despite more frequent negative prices,

curtailments decreased in 2016.

Page 101

0

500

1,000

1,500

2,000

2,500

3,000

3,500Ja

n

Fe

b

Ma

r

Apr

Ma

y

Ju

n

Ju

l

Aug

Sep

Oct

Nov

Dec

Ja

n

Fe

b

Ma

r

Apr

Ma

y

Ju

n

Ju

l

Aug

Sep

Oct

Nov

Dec

2015 2016

Se

lf s

ch

ed

ule

cu

rta

ilm

en

t M

Wh

Solar Wind Water Natural Gas Other Geothermal Nuclear

California exported energy to neighboring

EIM areas during midday hours in 2016.

Page 102

-200

-150

-100

-50

0

50

100

150

200

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

Imp

ort

s in

to N

V E

ne

rgy (

MW

)

California ISO to NV Energy

Release Plan Update

Janet Morris

Director, Program Office

Page 103

Release Plan 2017

Page 104

Independent 2017

• Settlements Release - Spring 2017

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

• Reactive Power Requirements and Financial Compensation

• Administrative Pricing Policy Update

• RIMS Functional Enhancements

Spring 2017 (4/1/17)

• Acceptable Use Policy – CMRI

• RTD Local Market Power Mitigation (LMPM) Enhancements

• CRR Clawback Modifications

• Forecasting & Data Transparency Improvements ( PIRP System Decommissioning)

• Metering Rules Enhancement

Fall 2017 (11/1/17)

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

• Bidding Rules Enhancements – Part B

• Reliability Services Initiative Phase 1B

• Reliability Services Initiative Phase 2

• Commitment Cost Enhancement Phase 3

• RM & EIM 2017 Enhancements

• Gas Burn Report

Release Plan – 2018 and subject to further planning

Page 105

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

Spring 2019

• EIM 2019 Seattle City Light

• EIM 2019 Balancing Authority of Northern California (BANC)

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 106

Settlements Release – Spring 2017

ISSUE SUMMARY BPM IMPACTED

Update configuration guide to compare the Balancing Authority Area Meter Load Quantity to the Balancing Authority Area Base Load Schedule instead of comparing Balancing Authority Area Meter Demand Quantity to Balancing Authority Area Base Load Scheduling when assessing Over and Under Scheduling EIM Settlement.

PRR 969: (CC 6045)

Update Pre-calculation RTM Net Amount to resolve two issues that relate to (1) the application of the Persistent Deviation Metric (PDM) and (2) the determination of BCR bid cost for a net-settled MSS.

PRR 970: (RTM Net Amount PC)

Settlement BPM and Charge Code updates for T+33M Settlement Statement implementation (Documentation Only)

PRR TBD: (CC 7989, CC 7999, Settlement Main Body BPM)

RAAIM - Flex Categories 2 and 3 Assessment Hour Updates (Documentation Only)

PRR 968: (RA Availability Incentive Mechanism PC)

Page 107

Settlements Release – Spring 2017

Milestone Date Status

Configuration Guides Posted February 10, 2017

DRAFT Configuration Output File Posted March 10, 2017

SAMPLE statement for trade date 3/8/2017 Published March 14, 2017

Pre-Production DRAFT Configuration Output File Posted March 20, 2017

Production Deployment March 27, 2017

FINAL Configuration Output File Posted March 27, 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.

There will be no market simulation of AIM ACL groups but this functionality will be live in

production to support the MRI-S Metering CPG enhancements market simulation.

A customer partnership group will be scheduled to address the upcoming market sim.

BPM Changes None

Business Process ChangesPotential Level-II business process changes under –

• Manage Market & Reliability Data & Modeling

• Manage Operations Support & Settlements

Page 108

Milestone Type Milestone Name Dates Status

Board Approval Board Approval N/A

BPMs Business Practice Manuals 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 MRI-S Metering Enhancements Mar 13, 2017 - Apr 07, 2017

Production Activation Phase 1 – ACL Groups Mar 10, 2017

Phase 2 - MRI-S Metering Enhancements Apr 05, 2017

OMAR Decommissioning OMAR System Decommissioning (+4 month transition) July 14

MRI-S ACL Groups + CPG Enhancements

Page 109

* 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.

In process 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

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 Project Info Details/Date

Application Software Changes None

BPM Changes None

Business Process Changes

Develop Infrastructure (DI) (80001)

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

Requirement for non-synchronous resources providing dynamic reactive power pursuant to FERC Order No. 827 to

employ an automatic voltage regulator system.

Page 110


Board Approval BOG Approval N/A

BPMs Post Draft BPM Changes N/A

External BRS Post External BRS N/A

Tariff File Tariff Dec 6, 2016

FERC Approval March 2, 2017

Configuration 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

Mar 06, 2017

FERC approved filing subject to

refund and further FERC order

2017 – Administrative Pricing Policy Updates

Page 111



• 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 Mar 13, 2017

External BRS Post External BRS Mar 20, 2015

Tariff Tariff Approval Jan 30, 2017

Config Guides Prepare Draft Configuration Guides Dec 2, 2016

Tech Spec Publish Tech Specs N/A


Production Activation Administrative Pricing Policy Updates Apr 18, 2017 – no later than 5/16

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 112


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

Spring 2017 Release – Overview

Page 113

Board Approval

BPMsExternal

BRSTariff

ConfigGuide

Tech Spec

Market Sim

Production Activation

Spring 2017 Release

Acceptable Use Policy - CMRI N/A N/A N/A N/A N/A N/A8/23/16 -9/23/16

4/1/17

RTD LMPM Enhancements 3/24/16 11/4/16 4/5/16FERC approved

effective date of4/1/17

N/A 4/14/162/7/17 -2/24/17 Target 4/18,

no later than 5/16

CRR Clawback Modifications 6/28/16 2/10/17 11/29/16FERC approved

effective date of4/1/17

N/A N/A N/A

Forecasting and Data Transparency Improvements (PIRP Decommissioning)

N/A 9/6/16 6/29/15 N/A N/A 4/15/163/21/17 -

4/4/174/5/17

Metering Rules Enhancement

12/14/16 2/2/17 N/AFiled with FERC

on 2/8/17N/A N/A N/A 4/10/17

COMPLETE

N/A

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 114



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 01, 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 115

Spring 2017 - Real Time Dispatch Local Market Power Mitigation

Page 116

Updated OASIS technical specifications 4.3.5

• http://www.caiso.com/Documents/OASIS-

InterfaceSpecification_v4_3_5Clean_Spring2017Release.pdf

• Updated the following MPM Services ( Spring 2017)

• Updated PRC_MPM_RTM_REF_BUS to add support for RTD LMPM.

• Updated PRC_MPM_RTM_NOMOGRAM_CMP to add support for RTD LMPM.

• Updated PRC_MPM_CNSTR_CMP to add support for RTD LMPM.


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

Received FERC approval for 4/1 Jan 27, 2017

File updated APR 1 deployment date Jan 13, 2017

Tech Spec Publish Technical Specification - OASIS Apr 08, 2016

Publish Technical Specification - CMRI Apr 14, 2016

Market Sim Market Sim Window Feb 06, 2017 - Feb 24, 2017

Production Activation RTD - Local Market Power Mitigation Enhancement Apr 18, 2017 – no later than 5/16

http://www.caiso.com/Documents/OASIS-InterfaceSpecification_v4_3_5Clean_Spring2017Release.pdf

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 117


Board Approval Board of Governors Approval Jun 28, 2016

BPMs Posted Market Operations BPM PRR 972 Feb 10, 2017

External BRS Post External BRS Nov 29, 2016

Tariff File Tariff Jan 25, 2017

Tariff Receive FERC order Mar 7, 2017

Production Activation CRR Clawback Modification Apr 18, 2017 – no later than 5/16

Spring 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.

Page 118




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 1, 2017

• PIRP application including all the UI and API reports will be decommissioned June 6,

2017

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

Page 119



Page 120



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 Simulation Mar 21, 2017 - Apr 04, 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 05, 2017

PIRP Decommission PIRP System Decommissioning Jun 06, 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 121

Spring 2017 – Metering Rules Enhancements

Page 122


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

BPMs Metering BPM Feb 02, 2017

Energy Imbalance Market BPM Feb 02, 2017

External BRS External Business Requirements N/A

Tariff Tariff Filing at FERC Feb 08, 2017

Config Guides N/A N/A

Tech Spec N/A N/A

Production Activation Metering Rules EnhancementsApr 10, 2017 upon FERC

approval

Fall 2017 Release – Overview

Page 123

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

8/8/17 -9/8/17

11/1/17

Reliability Services Initiative Phase 1B 5/12/15 12/23/16

Reliability Services Initiative Phase 2 10/27/16 1/31/17

Commitment Cost Enhancement Phase 3 3/25/16 1/6/17 TBD

RM & EIM 2017 Enhancements TBD TBD2/17/17

(Updates)7/31/17

Gas Burn Reports N/A N/A 7/29/16 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 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 124


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

Page 125



• MasterFile:

• Electric Region added to GRDT as non-modifiable

• OASIS:

• Publish fuel regions (public information)

Business Process Change• Manage Transmission & Resource Implementation

• Manage Entity & Resource Maintenance Updates

• Manage Full Network Model Maintenance

BPMs Market Instruments, 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 June 27, 2017

Tech Spec Publish CMRI Tech Specs Apr 03, 2017


Production Activation Bidding Rules Part B Nov 01, 2017

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


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.

• Scope not delivered in RSI Phase 1A (OASIS reporting),

Impacted Systems:

• CIRA

• OASIS

• Settlements

Business Process Changes Manage Market & Reliability Data & Modeling

Page 126


Board Approval Board Approval May 12, 2015


External BRS Post Updated External BRS v1.3 Mar 03, 2017


Config Guides Config Guide June 27, 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 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 ChangesManage Market & Reliability Data & Modeling- Manage Monthly & Intra-Monthly Reliability Requirements

- Manage Yearly Reliability Requirements

Page 127

Fall 2017 – Reliability Services Initiative Phase 2

Page 128


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 129

Fall 2017 - Commitment Cost Enhancements Phase 3

Page 130

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

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 2017



Address enhancements identified by policy, operations, technology,

business and market participants.

The following requirements are being evaluated:

• EIM Entity access reports

• BAAOP provisioning in AIM

• EIM data report enhancements to support market participant and EIM

entity shadow settlements

• Shared BAA Resource Modeling

• Change to ETSR formulation to separate base energy transfer to

distinct non-optimizable ETSRs.

BPM Changes TBD

Business Process Changes TBD

Page 131

Page 132

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


BPMs Draft BPM changes TBD

Post Draft BPM changes TBD

Publish Final Business Practice Manuals TBD

External BRS Post Updated External BRS to public site Feb 17, 2017

Tariff File Tariff Jul 31, 2017

Receive FERC order Nov 01, 2017

Config Guides Design review - BPM and Tariff SMEs TBD

Configuration Guides due June 27, 2017

Tech Spec Technical Specifications due Apr 03, 2017


Production Activation EIM Enhancements 2017 Nov 01, 2017

Fall 2017 – Gas Burn Reports

Page 133


Application Software ChangesCMRI - implement ISO Market software functionality to calculate and present gas burn

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

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 Prepare Draft Config Guide N/A

Tech Spec Publish Technical Specifications - CMRI Apr 03, 2017


Production Activation GenDB MF Consol and Gas Burn Report Nov 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

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

Page 134


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

Short-Term Plan OASIS

OASIS API New Versions - Transition Schedule :

Market Simulation Testing : Available from 1/3/2017

Production Deployment – 2/2/2017

Production Transition Period : 2/02/2017 – 3/31/2017

Page 135

XML Report Name Market Run ID Group Name VersionTransition Period in

Production

After Transition Period(4/1/2017

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 DAM,RTD,RTPD

DAM_SPTIE_LMP_GRP,

RTD_SPTIE_LMP_GRP,

RTPD_SPTIE_LMP_GRP 3 Supported Not Supported/ Invalid Request


DAM_SPTIE_LMP_GRP,

RTD_SPTIE_LMP_GRP,

RTPD_SPTIE_LMP_GRP 4 Supported Not Supported/ Invalid Request


DAM_SPTIE_LMP_GRP,

RTD_SPTIE_LMP_GRP,

RTPD_SPTIE_LMP_GRP 5 Supported Supported


The updated OASIS Technical Specifications v4.3.3 include changes

noted below:

Page 136

API Report Name Existing Proposed Changes

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

New Version -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







PRC_HASP_LMP - Changes apply

to Group Zip Only



Energy and Loss



Congestion , Energy and Loss

PRC_SPTIE_LMP(DAM,RTD,RTPD)-

Changes apply to Group Zip only




New Version - Separate file for each price



TRNS_CURR_USAGE

Request allows for past , current and

future trade dates

Existing Version - 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.

Existing Version - 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,


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 DAM,RTD,RTPD 5 Single node



PRC_SPTIE_LMP DAM,RTD,RTPD 5 ALL_APNODES



PRC_SPTIE_LMP DAM,RTD,RTPD 5 ALL



Page 137

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.

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http://www.caiso.com/

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




Market Performance and Planning Forum

2017 Schedule

• May 16

• July 18

• September 19

• November 14

Questions or meeting topic suggestions:

Submit through CIDI - select the “Market Performance and

Planning Forum” category

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