Market Performance and Planning Forum May 16, 2017 Objective: - - PowerPoint PPT Presentation

Market Performance and Planning Forum

May 16, 2017

Objective: Enable dialogue on implementation planning and market performance issues

• Review key market performance topics
• Share updates to 2017 release plans, resulting from

stakeholders inputs

• Provide information on specific initiatives

–to support Market Participants in budget and resource planning

• Focus on implementation planning; not on policy
• Clarify implementation timelines
• Discuss external impacts of implementation plans
• Launch joint implementation planning process

Slide 2

Market Performance and Planning Forum

Agenda – May 16, 2017

Time: Topic: Presenter: 10:00 – 10:05 Introduction, Agenda Kristina Osborne 10:05 – 10:20 May 3 CAISO Stage 1 System Emergency Tim Beach 10:20 – 12:00 Market Performance and Quality Update Guillermo Bautista Alderete Amber Motley James Lynn 12:00 – 1:00 Lunch 1:00 – 1:30 Policy Update Brad Cooper 1:30 – 2:00 Flexible Capacity Update Amelia Blanke David Robinson 2:00 – 3:00 Release Update Adrian Chiosea Janet Morris

Slide 3

May 3 CAISO Stage 1 System Emergency

Tim Beach Shift Manager, Operations

Slide 4

May 3, 2017 Stage 1 Emergency Summary

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

reserves

• Actual Net Scheduled Interchange (including dynamics) was

~1,150 MW below Day Ahead schedules

• ~600 MW of forced generation outages
• The HA market awarded 1,230 MW of supplemental energy
• n the interties for HE20 (19:00 to 20:00) but 830 MW of that

was declined

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

verbally dispatched (PDR & RDRR) – Two Contingency dispatches issued, RDRR enabled in the market in the second dispatch (and actually dispatched during manual implementation of DR.)

• Operating reserves recovered at 19:56
• 21:00 Stage 1 Emergency terminated

Slide 5

Market Performance and Quality Update

James Lynn Senior Advisor, Market Settlements Design Amber Motley Manager, Short Term Forecasting Guillermo Bautista Alderete, Ph.D. Director, Market Analysis and Forecasting

Congestion Revenue Right Analysis Effort

CRR Auction Effort

• Initiative is split in two phases

– Analysis phase – Policy phase

• CRR Working group session held on April 18 to discuss

the Analysis scope

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

auction efficiency, and identify drivers and guide the policy phase

Slide 8

Market Analysis done in three phases along the following areas

• Auction results
• Participation
• Transparency
• Modeling

– Accuracy – ISO practices/procedures – Market events – Systemic differences

• Constraint by constraint analysis

– Analyze constraints that did not bind in the auction but had payouts in the DAM – Analyze constraints with large payouts

• Impact of changes over time

Slide 9

Over Supply Update

Frequency of negative system prices has steadily increased year over year

Slide 11

0% 5% 10% 15% 20% 25% Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec

Frequency

2014 2015 2016 2017

Distribution of negative prices have shifted from early morning hours to midday hours*

Slide 12

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

0% 5% 10% 15% 20% 25% 30% 35% 40% 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24

Frequency

2014 2015 2016 2017

Slide 13

ISO total monthly VERS schedules and forecasts

Slide 14

IFM under-scheduling of wind generation

Monthly wind (VERS) downward flexibility in FMM

Slide 15

Monthly solar (VERS) downward flexibility in FMM from 11 AM to 5 PM

Slide 16

Slide 17

Hydro production higher than recent historical production

Slide 18

RTD renewable (VERS) curtailment continued to increase in March and April

The trend of curtailments is accelerating

Slide 19

10,000 20,000 30,000 40,000 50,000 60,000 70,000 80,000 90,000 May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar APR 2014 2015 2016 2017 ENERGY CURTAILMENTS (MWH) Local Economical System Economical Local ED System ED Self Sch System Self Sch Local

Solar production and net load records have been

• bserved this Spring

Slide 20

. Saturday May 13 Sunday May 14 Maximum load 26,120 MW at 20:36 25,644 MW at 20:36 Minimum load 20,342 MW at 03:44 19,428 MW at 03:58 Minimum net load 8,804 MW at 14:44 8,493 MW at 13:03

How are curtailments determined?

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

penalty prices.

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

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

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

and by less than 100MW

Slide 21

TOR/ETC IFM self schedule RMT Price taker PBC violation Economical bids

Slide 22

Hydro production is trending upward for Spring but still lower than historical high hydro year of 2006

1,000 2,000 3,000 4,000 5,000 6,000 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr 2006 2014 2015 2016 2017 GWh

Hydro vs. Solar Monthly Production

Hydro Solar

Slide 23

Self scheduled interties in the real-time market remain high

Flexible Ramp Update

Flexible Ramp Product Up Requirement

Slide 25

Flexible Ramp Product Down Requirement

Slide 26

Flexible Ramp Product Up Awards

Slide 27

Flexible Ramp Product Down Awards

Slide 28

How is FRP settled?

Slide 29

Forecasted Upper limit Lower limit Net system demand at t t+1 (advisory interval) t (binding interval) Time Net system demand

Minimum requirement Demand curve Demand curve

Forecasted movement known with certainty

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

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

Uncertainty movement (forecast error)

• the requirements for this is derived from demand curve modeling based on historical forecast errors

Demand Curve to Meet FRD Uncertainty

Slide 30

t (binding interval) t+1 (advisory interval) Forecast net demand FRU forecasted net load change FRD uncertainty FRD max expected forecast error t (binding interval) t+1 (advisory interval) Forecast net demand FRU forecasted net load change FRD max expected forecast error No FRD procured

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

Forecasted Movement has a direct settlement, uncertainty is awarded and allocated as an uplift

Binding Advisory

…

B A

…

Forecasted Movement (Market) Uncertainty A A RTD1 RTD2

Slide 31

• Supply and Interties resources (CC 7070)

– Separate FMM and Incremental RTD forecasted movement qty – (-1) * Forecasted Movement Qty * (FRU price - FRD price) – Rescind portion of forecasted movement in case of deviation (UIE/OA)

• Load resources (CC 7076)

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

• r metered CAISO Demand

Forecasted movement settlement

Slide 32

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

– Uncertainty award for FRU/FRD in FMM is settled at FMM FRU/FRD price – Uncertainty award for FRU/FRD in RTD which is incremental to FMM uncertainty award is settled at the RTD FRU/FRD price – Price has breakdown, which differentiates BAA constraint from EIM Area constraint contribution – Rescind portion of Uncertainty Capacity where resource deviation (UIE/OA) overlaps

Uncertainty Award Settlement

Slide 33

FRP Uncertainty Cost Allocation

Slide 34

Flexible ramping up Flexible ramping down

Total Uncertainty MW by FRP Constraint Category’s Uncertainty MW Allocate to individual resource

Uncertainty

Forecasted Movement Settlement ISO – From November 1 to February 28, 2017

Scheduled Settlement Correction

Slide 35

Uncertainty Up Settlement – From Jan 2015 – April 2017

Slide 36

Once normalized for capacity procured, FRP uncertainty settlements in the same range as in prior months

Slide 37

FRP Up Uncertainty Payment Amount in EIM areas

Slide 38

FRP Down Uncertainty Payment Amount in EIM areas

Slide 39

FRP Up Payment – Hourly Distribution correlated to hourly profile

Slide 40

FRP Down Payment – Hourly Distribution correlated to hourly profile

Slide 41

Persistency Model Enhancement

Current Data Transfer Time Needed for External Forecast Service Provider (FSP)

Slide 43

CAISO is working on an enhancement based on persistency

• For Wind

– Recommendation is to use the simple lag persistence model.

• For Solar

– Recommendation is to use a persistence contour model.

Slide 44

Accounting of Market Dispatches/Curtailments of Renewables is also considered

• Market software will also handle cases of market

dispatches or curtailments of renewables – As soon as the market dispatches an EIR resource, logic will be included to take into consideration the supplemental dispatch of resource to be the EIR Resource Forecast.

Slide 45

Mean Average Percent Error for January 2017

Slide 46

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

Wind Solar External FSP 6.5% 8.5% Lag 3.2% 5.9% PCM 3.5% 4.9% Forecast Type RTD

Total Mae Value for RTD SOLAR Forecast

Slide 47

0% 1% 2% 3% 4% 5% 6% 0:00 1:10 2:20 3:30 4:40 5:50 7:00 8:10 9:20 10:30 11:40 12:50 14:00 15:10 16:20 17:30 18:40 19:50 21:00 22:10 23:20

MAE Unit A

lag pcm 0% 2% 4% 6% 8% 10% 12% 0:00 1:10 2:20 3:30 4:40 5:50 7:00 8:10 9:20 10:30 11:40 12:50 14:00 15:10 16:20 17:30 18:40 19:50 21:00 22:10 23:20

MAE Unit B

lag pcm

0% 2% 4% 6% 8% 10% 12% 0:00 1:25 2:50 4:15 5:40 7:05 8:30 9:55 11:20 12:45 14:10 15:35 17:00 18:25 19:50 21:15 22:40

MAE Unit C

lag pcm 0% 2% 4% 6% 8% 10% 12% 14% 0:00 1:25 2:50 4:15 5:40 7:05 8:30 9:55 11:20 12:45 14:10 15:35 17:00 18:25 19:50 21:15 22:40

MAE Unit D

lag pcm

APPENDIX

Slide 48

Simple Lag Persistence Model

• Name Convention:

A (actual), F (forecast), E (Error) = F – A

• FH = Forecast Horizon (RTD)
• Lag Model

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

Slide 49

Recommendation for Solar Resources Persistence Counter Market Model

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

estimate of full power output taking into consideration sun angle.

• The persistent forecast is then:

– F(t) = A(t-lag) / FPI(t-lag)* FPI(t) – Where A(t-lag) / FPI (t-lag) is the estimate “cloud” factor to A(t)/FPI(T) The premise is the lag forecast A(t-lag) should adjust according the track of performance under different cloudiness condition at lag time point

Slide 50

Example

• Sunny Day:

– A(t-lag) / FPI(t-lag) = 1

• Cloudy Day:

– A(t-lag) / FPI(t-lag) = .3

Slide 51

Market Update

Slide 53

Good price convergence in April based.

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

Slide 54

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

Slide 55

Insufficient upward ramping capacity in ISO continued to be at low levels since last November.

Slide 56

Insufficient downward ramping capacity declined since February.

Slide 57

Congestion revenue rights market revenue inadequacy without auction revenues.

Slide 58

Congestion revenue rights market revenue sufficiency including auction revenues.

Slide 59

Exceptional dispatch volume in the ISO area decreased since February.

Slide 60

Real-time Bid cost recovery dropped in April

Slide 61

Bid cost recovery (BCR) by Local Capacity Requirement area

Slide 62

Minimum online commitment (MOC)

MOC San Onofre Bus

Slide 63

Pmax of MOC Cleared Units

Slide 64

Enforcement of minimum online commitments in March and April

MOC Name Number (frequency) of hours in January and February Humboldt 7110 SVC In 1196 MOC Pease 994 Orange County 7630 801 Humboldt 7110 215 MOC East Nicolaus 96 MOC SAN ONOFRE BUS 90 MOC Devers Bus 41 SDGE 7820 CFEIMP_BG 34 MOC Placer 4551087 26 MOC Moss 4575683 15 SDGE 7820 9 SCIT MOC 8 MOC NP15 7 Orange county outage 7630 2

Slide 65

Renewable (VERS) schedules including net virtual supply and aligns with VER forecast in March and April

http://www.caiso.com/Pages/documentsbygroup.aspx?GroupID=EFF75C 2E-F28E-4087-B88B-8DFFAED828F8

Slide 66

Hourly distribution of maximum RTD renewable (VERS) curtailment in April

Slide 67

ISO area RTIEO increased since February.

2016 2017 (YTD) RTCO $50,398,946 $9,701,084 RTIEO

• $3,706,211

$18,633,447 Total Offset $46,692,735 $28,334,531

Slide 68

CAISO Price correction events increased in March and April

1 2 3 4 5 6 7 8 9 10 Jan-16 Feb-16 Mar-16 Apr-16 May-16 Jun-16 Jul-16 Aug-16 Sep-16 Oct-16 Nov-16 Dec-16 Jan-17 Feb-17 Mar-17 Apr-17 Count of Events Process Events Software Events Data Error Events Tariff Inconsistency

Slide 69

EIM-Related Price correction events decreased in March and April

2 4 6 8 10 12 14 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr 2016 2017 Count of Events Process Events Software Events Data Error Events Tariff Inconsistency

EIM Price trends

Slide 70

Robust Energy transfers observed in in 1st quarter, 2017

Average – 259MW Maximum – 1196MW Average – 186MW Maximum – 739MW Average – 108MW Maximum – 300MW Average – 173MW Maximum – 506MW Average – 0MW Maximum – 0MW Average – 84MW Maximum – 150MW Average – 80MW Maximum – 300MW Average – 118MW Maximum – 300MW Average – 231MW Maximum – 871MW Average – 222MW Maximum – 791MW Average – 141MW Maximum – 330MW Average – 136MW Maximum – 360MW Average – 165MW Maximum – 909MW Average – 184MW Maximum – 945MW Average – 144MW Maximum – 857MW Average – 0MW Maximum – 0MW

PACE CAISO PACW NEVP AZPS PSEI

Slide 71

Slide 72

EIM BCR observed a modest increased in April

Slide 73

EIM Manual Dispatch increased in April and is mostly concentrated in APS area

Day-ahead load forecast

0.0% 0.5% 1.0% 1.5% 2.0% 2.5% 3.0% Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 2015 2016 2017

MAPE

Slide 74

Day-ahead peak to peak forecast accuracy

0.0% 0.5% 1.0% 1.5% 2.0% 2.5% 3.0% 3.5% Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 2015 2016 2017

MAPE

Slide 75

Day-ahead wind forecast

0.0% 1.0% 2.0% 3.0% 4.0% 5.0% 6.0% 7.0% 8.0% 9.0% 10.0% Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 2015 2016 2017

MAE

**In 2015-2016, Economic dispatches are not added back in to the generation data. **The 2017 generation data used for accuracy calculation contains the economically dispatched MW.

Slide 76

Day-ahead solar forecast

0.0% 1.0% 2.0% 3.0% 4.0% 5.0% 6.0% 7.0% 8.0% 9.0% 10.0% Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 2015 2016 2017

MAE

**In 2015-2016, Economic dispatches are not added back in to the generation data. **The 2017 generation data used for accuracy calculation contains the economically dispatched MW.

Slide 77

Real-time wind forecast

0.0% 0.5% 1.0% 1.5% 2.0% 2.5% 3.0% 3.5% 4.0% Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 2015 2016 2017

MAE

**2015-2016 represent the accuracy of the forecast made each hour at xx:55 for the following hour, i.e. the 5-65 minute ahead forecast. Economic dispatches are not added back in to the generation data. **2017 has been changed to track the RTD accuracy, i.e. the forecast made 7.5 minutes before the binding

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

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

Slide 78

Real-time solar forecast

0% 1% 2% 3% 4% 5% 6% Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 2015 2016 2017

MAE

**2015-2016 represent the accuracy of the forecast made each hour at xx:55 for the following hour, i.e. the 5-65 minute ahead forecast. Economic dispatches are not added back in to the generation data. **2017 has been changed to track the RTD accuracy, i.e. the forecast made 7.5 minutes before the binding

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

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

Slide 79

Market Performance and Planning Forum

May 16, 2017

We are on lunch break, returning at 1:00 p.m. If you have questions, send to Kristina Osborne at kosborne@caiso.com

• r call on cell at 916-802-7631.

Policy Update

Brad Cooper Manager, Market Design and Regulatory Policy

Ongoing policy stakeholder initiatives

• Energy storage and distributed energy resources (ESDER)

Phase 2

– Publish draft final proposal in June – July EIM Governing Body and CAISO Board meetings

• Contingency modeling enhancements
• Fourth revised straw proposal including prototype results in late

June

• September CAISO Board meeting
• Generator contingency and remedial action scheme

modeling

– Draft final proposal in June – Sept EIM Governing Body and CAISO Board meetings

Slide 82

Ongoing policy stakeholder initiatives (continued)

• Commitment costs and default energy bid enhancements

– Recent stakeholder working groups – Straw proposal in June – November 2017 EIM Governing Body and CAISO board meetings

• Temporary suspension of resource operations

– Recently posted issue paper – Nov CAISO Board meeting

• Capacity Procurement Mechanism risk-of-retirement

process enhancements

– Recently posted issue paper – Nov CAISO Board meeting

Slide 83

Ongoing policy stakeholder initiatives (continued)

• EIM Greenhouse Gas Enhancements

– Draft final proposal in late May – July 2017 EIM Governing Board and ISO Board meetings (briefing) – Report evaluating two-pass solution in late Q4 2017 – Early 2018 EIM Governing Body and ISO Board meetings for approval

• Flexible resource adequacy criteria and must-offer
• bligation – phase 2

– Second revised straw proposal in July – Q2 2018 ISO Board meeting

• Congestion revenue right auction efficiency

– Stakeholder working group on analysis in April – Analysis phase in progress – Policy development phase starting after analysis complete in Q4

Slide 84

Ongoing policy stakeholder initiatives (continued)

• Frequency response – phase 2

– Developing new schedule – Early 2018 CAISO board meeting

• Bid cost recovery enhancements

– Suspended due to FERC uplift allocation NOPR

Slide 85

Upcoming policy stakeholder initiatives

• Aliso Canyon mitigation measures extension

– Straw and draft final proposals in June – July EIM Governing Body and ISO Board meetings

• Management of EIM Imbalance settlement for bilateral

schedule changes

– Issue paper in June – Oct EIM Governing Body and Nov ISO Board meetings

• Donation by third party of transmission capacity available

for EIM transfers

– Issue paper in June – Oct EIM Governing Body and Nov ISO Board meetings

Slide 86

Upcoming policy stakeholder initiatives (continued)

• Planned to start in Q3 2017

– EIM net wheeling charge – Review Transmission Access Charge Structure – Resource adequacy reform – Real-time market enhancements

Slide 87

2016 Annual Report

Amelia Blanke Manager, Monitoring & Reporting Department of Market Monitoring

Total market costs were down by about 4 percent after accounting for natural gas and greenhouse gas price changes.

Slide 89

$0 $1 $2 $3 $4 $5 $6 $7 $0 $10 $20 $30 $40 $50 $60 $70 2012 2013 2014 2015 2016 Average annual gas price ($/MMBtu) Average annual cost ($/MWh) Average cost (nominal) Average cost normalized to gas price, including greenhouse gas adjustment Average daily gas price, including greenhouse gas adjustments ($/MMBtu)

Estimated average wholesale energy costs per MWh (2012 – 2016)

Slide 90

2012 2013 2014 2015 2016 Change '15-'16 Day-ahead energy costs 32.57 $ 44.14 $ 48.57 $ 34.54 $ 30.70 $ (3.84) $ Real-time energy costs (incl. flex ramp) 0.99 $ 0.57 $ 1.98 $ 0.69 $ 1.02 $ 0.33 $ Grid management charge 0.80 $ 0.80 $ 0.80 $ 0.80 $ 0.81 $ 0.01 $ Bid cost recovery costs 0.45 $ 0.47 $ 0.40 $ 0.39 $ 0.33 $ (0.06) $ Reliability costs (RMR and CPM) 0.14 $ 0.10 $ 0.14 $ 0.12 $ 0.11 $ (0.01) $ Average total energy costs 34.96 $ 46.08 $ 51.89 $ 36.54 $ 32.97 $ (3.58) $ Reserve costs (AS and RUC) 0.37 $ 0.26 $ 0.30 $ 0.27 $ 0.54 $ 0.26 $ Average total costs of energy and reserve 35.33 $ 46.34 $ 52.19 $ 36.81 $ 33.50 $ (3.31) $

Markets continued to perform close to competitive benchmarks.

Slide 91

$0 $10 $20 $30 $40 $50 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Average price ($/MWh) Competitive baseline ($/MWh) Average load-weighted day-ahead price Average load-weighted 15-minute price Average load-weighted 5-minute price

Estimated net revenue of a hypothetical new unit 2012 - 2015

$0 $20 $40 $60 $80 $100 $120 $140 $160 $180 $200 $220 2012 2013 2014 2015 $/kW-year Net revenues (NP15) Net revenues (SP15) Levelized fixed cost target $0 $20 $40 $60 $80 $100 $120 $140 $160 $180 $200 $220 2012 2013 2014 2015 $/kW-year Net revenues (NP15) Net revenues (SP15) Levelized fixed cost target

Combined Cycle Combustion Turbine

Slide 92

DMM updated net revenue analysis assumptions in 2016

• Not directly comparable to prior analysis
• Optimized dispatch of hypothetical resource

– Objective: maximize profit subject to resource constraints – 2016 NP15 and SP15 prices

• Combined cycle: day-ahead and five minute prices
• Combustion turbine: 15 and 5 minute prices

– Incremental energy cost = default energy bid – Commitment cost = proxy start up and minimum load

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

Slide 93

Financial analysis of new combined cycle unit (2016)

Slide 94

Zone Scenario Capacity factor Total energy revenues ($/kW-yr) Operating costs ($/kW-yr) Net revenue ($/kW-yr) Day-ahead prices and default energy bids 21% $75.88 $64.65 $11.23 Day-ahead prices and default energy bids without adder 23% $83.12 $70.45 $12.67 Day-ahead commitment with dispatch to day-ahead and 5-minute prices using default energy bids 22% $79.73 $66.82 $12.91 Day-ahead prices and default energy bids 29% $104.92 $84.40 $20.52 Day-ahead prices and default energy bids without adder 32% $111.20 $88.83 $22.37 Day-ahead commitment with dispatch to day-ahead and 5-minute prices using default energy bids 30% $108.51 $86.38 $22.13 NP15 SP15

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

Financial analysis of new combustion turbine (2016)

Slide 95

Zone Scenario Capacity factor Real-time energy revenues ($/kW-yr) Operating costs ($/kW-yr) Net revenue ($/kW-yr) 15-minute prices and default energy bids 4.5% $23.46 $18.67 $4.80 15-minute prices and default energy bids without adder 5.6% $27.85 $22.17 $5.68 15-minute commitment with dispatch to 15-minute and 5-minute prices using default energy bids 5% $31.41 $21.03 $10.38 15-minute prices and default energy bids 7% $41.37 $28.87 $12.50 15-minute prices and default energy bids without adder 9% $48.20 $34.33 $13.87 15-minute commitment with dispatch to 15-minute and 5-minute prices using default energy bids 8% $50.07 $32.79 $17.29 NP15 SP15

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

Flexible ramping payments

Slide 96

$0.00 $0.02 $0.04 $0.06 $0.08 $0.10 $0.0 $0.5 $1.0 $1.5 $2.0 $2.5 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 2015 2016 Payments per MWh load ($/MWh) Total payments ($ million) California ISO PacifiCorp East PacifiCorp West NV Energy Puget Sound Energy Arizona Public Service Payments per MWh of load

Flexible ramping product implementation

Release Plan Update Janet Morris Director, Program Office Adrian Chiosea Manager, Strategic Initiative Management

Release Plan 2017

Slide 98

Independent 2017

• MRI-S ACL Groups + CPG Enhancements (formerly OMAR Replacement)
• RIMS Functional Enhancements
• Black Start and System Restoration Phase 2
• Forecasting & Data Transparency Improvements (PIRP System Decommissioning)
• Aliso Canyon mitigation measures extension

Fall 2017 (11/1/17)

• EIM Portland General Electric (PGE) – 10/1/17
• Bidding Rules Enhancements – Part B
• Commitment Cost Enhancement Phase 3
• RM & EIM 2017 Enhancements
• Gas Burn Report
• SIBR UI Upgrade

Release Plan – 2018 and subject to further planning

Slide 99

Spring 2018

• Reliability Services Initiative 2017
• EIM 2018 Idaho Power Company

Fall 2018 – tentative, subject to impact assessment

• Contingency Modeling Enhancements
• Flexible Resource Adequacy Criteria and Must-offer Obligation Phase 2
• Commitment Costs and Default Energy Bid Enhancements
• Energy Storage and DER Phase 2
• Temporary Suspension of Resource Operations
• Capacity Procurement Mechanism – risk-of-retirement process enhancements
• Management of EIM imbalance settlement for bilateral schedule changes
• ADS User Interface Replacement
• CIRA Technology Upgrade

Spring 2019

• EIM 2019 Seattle City Light
• EIM 2019 Balancing Authority of Northern California (BANC)

Fall 2019 – tentative, subject to impact assessment

• Regional Integration and EIM Greenhouse Gas Compliance
• Generation Contingency and Remedial Action Scheme
• Frequency Response Phase 2
• Congestion Revenue Right auction efficiency

Spring 2020

• EIM 2020 Salt River Project

Subject to further release planning:

• DRS Replacement

2017 - MRI-S ACL Groups+ CPG Enhancements

Project Info Details/Date Application Software Changes

The MRI-S metering (MRI-S) application cannot currently support ACL (Access Control List) groups functionality for defining a subset of resources belonging to an SCID. Enhancements to the Application Identity Management (AIM) application will enable the use of ACL groups for SCID-level read-only access for MRI-S. A customer partnership group is scheduled for May 11, 2017 to address issues encountered during market sim, and to discuss the steps necessary for cut-over from OMAR Online to MRI-S Metering. OMAR Online will be decommissioned four months after the May 2nd re-opening of the MRI-S Metering: September 1, 2017.

BPM Changes

None

Business Process Changes

Potential Level-II business process changes under –

• Manage Market & Reliability Data & Modeling
• Manage Operations Support & Settlements

Slide 100

Milestone Type Milestone Name Dates Status

Board Approval Board Approval N/A BPMs BPMs N/A External BRS Post External BRS Nov 14, 2016



Tariff Tariff N/A Config Guides Config Guide N/A Tech Spec Publish Tech Specs Nov 02, 2016



Market Simulation Phase 2 - MRI-S Metering Enhancements Mar 13, 2017 – June 9, 2017 Production Activation Phase 1 - ACL Groups Mar 10, 2017



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

2017 – RIMS Functional Enhancements

Project Info Details/Date Status

Application Software Changes Functional enhancements resulting from the Customer Partnership Group CPG. More details to be provided in the future. BPM Changes Generator Interconnection and Deliverability Allocation Procedures Generator Interconnection Procedures Managing Full Network Model Metering Generator Management Transmission Planning Process Customer Partnership Group 10/16/15 Application and Study Webinar 3/31/16

Slide 101

Milestone Type Milestone Name Dates Status

Board Approval Board approval not required N/A BPMs Generator Interconnection and Delivery Allocation Apr 29, 2016



External BRS External BRS not Required N/A Tariff No Tariff Required N/A Tech Spec No Tech Specifications Required N/A Production Activation Ph1 RIMS5 App & Study Mar 21, 2016



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

2017- Black Start and System Restoration Phase 2

Project Info

Details/Date

Application Software Changes Settlements:

• Modifications to existing charge codes for Black Start capacity and

Black Start allocations will need to occur. MPP (Market Participant Portal):

• Possibility to use current functionality for receiving RMR invoices

for Black Start units. BPM Changes Definitions & Acronyms:

• Revision of the following definitions to match the Tariff language:
• Ancillary Services (AS)
• Black Start Generator
• Black Start Generating Unit
• Interim Black Start Agreement
• Reliability Services Costs

Settlements & Billing:

• Pending Settlements review. Revisions will be directly based on

Tariff changes. Business Process Changes N/A

Slide 102

Milestone Type Milestone Name Dates Status

Board Approval Board approval May 1, 2017



BPMs BPM Changes Required TBD External BRS External BRS not Required N/A Tariff Draft tariff Web Conference to finalize tariff May 1, 2017 May 15, 2017

 

Tech Spec No Tech Specifications Required N/A

2017 – Forecasting and Data Transparency Improvements (PIRP System Decommissioning)

Project 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.

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2017 – Forecasting and Data Transparency Improvements (PIRP System Decommissioning)

Project Info

Details/Date

User-Provisioning process for CMRI in preparation of Market Simulation and subsequently for production

• Client Services will reach out to the User Access Administrator (UAA)
• Updated AIM User Guide, detailing how to create new ACL groups, was posted on

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

• If a user is at the SC level, there is no need to provision ACL access
• Exceptions - (Non-SC Level Users) – provisioning via AIM will be required
• Provisioning will be required to be done prior to Market Simulation
• Provisioning for PIRP via AARF will discontinue on Feb 16, 2017 for Map Stage and

Mar 20, 2017 for Production.

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

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

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

2017

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

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2017 – Forecasting and Data Transparency Improvements (PIRP System Decommissioning)

Slide 105

Milestone Type Milestone Name Dates Status

Board Approval Board Approval N/A BPMs Publish Draft Business Practice Manuals (Market Instruments; PRR 936) Sep 06, 2016



External BRS External Business Requirements Jun 29, 2015



Tariff Tariff Filing Activities N/A Config Guides Settlements Configuration N/A Tech Spec Publish Technical Specifications (CMRI; 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 Apr 04, 2017 - Apr 18, 2017



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



OASIS API Enhancements; 9 Reports Dec 20, 2016



New Renewables CMRI reports and APIs Production Deployment Apr 20, 2017



PIRP Decommission PIRP Decommissioning Jun 20, 2017

Fall 2017 Release – Overview

Slide 106 Board Approval BPMs External BRS Tariff Config Guide Tech Spec Market Sim Production Activation

Fall 2017 Release

EIM Portland General Electric N/A N/A N/A 8/31/17 N/A N/A 6/6/17 - 7/6/17 10/1/17 Bidding Rules Enhancements - Part B 3/25/16 6/15/17 1/13/17 6/1/17 6/27/17

• 4/3/17

(MF)

• 4/3/17

(OASIS)

• 4/17/17

(CMRI)

• 4/25/17

(CMRI)

• 5/2/17

(OASIS) 8/8/17 - 9/8/17 11/1/17 Commitment Cost Enhancement Phase 3 3/25/16 1/6/17 4/10/17 6/15/17 RM & EIM 2017 Enhancements N/A N/A 1/23/17 2/17/17 4/10/17 N/A Gas Burn Reports N/A N/A 7/29/16 N/A N/A N/A SIBR UI Upgrade N/A N/A N/A N/A N/A N/A N/A COMPLETE N/A

Fall 2017 – EIM Portland General Electric

Project Info Details/Date Application Software Changes Implementation of Portland General Electric as an EIM Entity. BPM Changes EIM BPM will be updated to reflect new modeling scenarios identified during PGE implementation and feedback from PGE. Market Simulation PGE continues Day in the Life and unstructured scenario testing in a non- production environment in preparation for Market Simulation. Parallel Operations August 1 – September 30, 2017

Slide 107

Milestone Type Milestone Name Dates Status

Tariff File Readiness Certification Aug 31, 2017 Market Sim Market Sim Window Jun 6, 2017 – Jul 6, 2017 Parallel Operations Parallel Operations Window Aug 1, 2017 – Sep 30, 2017 Production Activation EIM - Portland General Electric Oct 01, 2017

Fall 2017 - Bidding Rules Enhancements – Part B

Slide 108

Project Info Details/Date Application Software Changes

• MasterFile:
• Electric Region added to GRDT as non-modifiable
• CMRI:
• Resource-level monthly EPI (calculated on daily basis) based on wholesale or reatil

electric region type.

• CAISO.COM:
• Only publish total monthly fuel region GPI (existing) and eliminate publishing the

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

Business Process Change

• Manage Transmission & Resource Implementation
• Manage Entity & Resource Maintenance Updates
• Manage Full Network Model Maintenance

BPMs

Market Instruments Milestone Type Milestone Name Dates Status

BPMs Post Draft BPM changes June 15, 2017 Board Approval BOG Approval Mar 25, 2016



External BRS Post External BRS Jan 13, 2017



Config Guides Prepare Draft Configuration Guides Jun 27, 2017 Tech Spec Publish CMRI Tech Specs Apr 17, 2017



Publish MF Tech Specs Apr 03, 2017



Market Sim Market Sim Window Aug 08, 2017 - Sep 08, 2017 Production Activation Bidding Rules Part B Nov 01, 2017

Project Info Details/Date

Application Software Changes Scope: 1. Clarify use-limited registration process and documentation to determine opportunity costs 2. Determine if the ISO can calculate opportunity costs

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

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

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

5. Market Characteristics

• Maximum Daily Starts
• Maximum MSG transitions
• Ramp rates

Impacted Systems: 1. Master File: Set use-limited resource types and limits; Set market-based values 2. ECIC: Process use limited resource input values for and Receive opportunity cost adders from

• pportunity cost tool

3. CIRA: RAAIM exempt rule for “use-limited reached” 4. CMRI: Publish opportunity cost 5. IFM/RTN: Use market-based values MDS, MDMT and RR 6. SIBR: Add Opportunity cost adders on bid caps, remove daily bid RR 7. MasterFile: Set use-limited resource types and limits; Set market-based values 8. OMS: “Use-Limited Reached” nature of work attribute for Generation Outage Card 9. Settlements: Publish the actual start up, run hour and energy output for the use-limited resources

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

DEB BPM Changes Market Instruments, Outage Management, Reliability Requirement, Market Operations Business Process Changes

• Manage Market & Reliability Data & Modeling
• Manage Markets & Grid

Slide 109

Fall 2017 - Commitment Cost Enhancements Phase 3

Slide 110

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

Milestone Type Milestone Name Dates Status

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



BPMs Post Draft BPM changes Jun 15, 2017 External BRS Post External BRS Jan 06, 2016



Tariff File Tariff Jun 15, 2017 Config Guides Config Guide Jun 27, 2017 Tech Spec Publish ISO Interface Spec (Tech spec) – MF Publish ISO Interface Spec (Tech spec) – CMRI Apr 03, 2017 Apr 17, 2017

 

Market Sim Market Sim Window Aug 08, 2017 – Sep 8, 2017 Production Activation Commitment Costs Phase 3 Nov 01, 2017

Fall 2017 – RM & EIM Enhancements 2017

Project Info

Details/Date

Application Software Changes

​Address enhancements identified by policy, operations, technology, business and market participants. Scope:

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

OASIS, WebOMS, and CMRI. 2. EIM data report enhancements to support market participant and EIM entity settlements 3. EIM software enhancements 4. Change to ETSR formulation to separate base energy transfer to distinct non-optimizable ETSRs. Out of Scope: 1. BAAOP provisioning in AIM 2. Joint Owned Unit/Shared BAA Resource Modeling

BPM Changes

Energy Imbalance Market: Access & Integration, Data Report Outage Management: Access & Integration Market Instruments: Access & Integration, Data Reports Market Operations: Data Report Settlements & Billing: Data Report

Business Process Changes

N/A

Slide 111

Fall 2017 – RM & EIM Enhancements 2017

Slide 112

Milestone Type Milestone Name Dates Status

External BRS Post External BRS Jan 23, 2017



Post Updated External BRS Feb 17, 2017



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



Config Guides Config Guide Jun 27, 2017 Tech Spec Publish Technical Specifications (CMRI) Apr 17, 2017



Publish Technical Specifications (OASIS) Apr 03, 2017



Publish Technical Specifications (MF) Apr 03, 2017



Market Sim Market Simulation Aug 08 – Sept 08, 2017 Production Activation RM & EIM Enhancements 2017 Nov 01, 2017

Fall 2017 – Gas Burn Report

Slide 113

Project Info Details/Date Application Software Changes

CMRI - implement ISO Market software functionality to calculate and present gas burn estimates to gas companies serving electric generation located within the CAISO BAA OASIS - Control Area Generating Capability List report

Business Process Change

• Develop Infrastructure
• Manage Market & Reliability Data & Modeling

Milestone Type Milestone Name Dates Status

Board Approval BOG Approval N/A BPMs Post Draft BPM changes N/A External BRS External Business Requirements Jul 29, 2016



Tariff Receive FERC order N/A Config Guides Configuration Guides N/A Tech Spec Publish Technical Specifications - CMRI Apr 25, 2017



Publish Technical Specifications - OASIS May 02, 2017



Market Sim Market Sim Window N/A Production Activation GenDB MF Consol and Gas Burn Report Nov 01, 2017

Fall 2017 – SIBR UI Upgrade

Slide 114

Project Info Details/Date Application Software Changes

SIBR – The CASIO will be upgrading the underlying SDK platform utilized for displaying the user interface. This latest SDK version will strengthen the security of the SIBR application and will improve compatibility with the latest version of Internet Explorer. It is anticipated no functional changes or API will be impacted by this upgrade. Milestone Type Milestone Name Dates Status

Board Approval Board Approval N/A BPMs Publish Final Business Practice Manuals N/A External BRS Post Draft BRS N/A Tariff Receive FERC order N/A Tech Spec Publish Tech Specs N/A Market Sim Market Sim Window N/A Production Activation SIBR UI Upgrade Nov 01, 2017

Spring 2018 - Reliability Services Initiative 2017

Project Info

Details/Date Application Software Changes

Developments under consideration include: Scope:

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

• RA Process and Outage Rules for implementation for 2017 RA year.
• CSP Offer Publication (RSI 1A scope)
• Local and system RA capacity designation
• RA showing requirements for small load serving entities (LSEs)
• RA showing tracking and notification

Impacted Systems:

• OASIS
• Settlements
• CIRA

CIRA:

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

rules need to be updated.

• Update planned/forced outage substitution rules
• Allow market participants to select how much system/local MWs to substitute.
• Modification of UI screens to accommodate system/local MW split.
• Enhance system to allow exemption from submission of RA Plans for LSE that have a RA
• bligation < 1 MW for a given capacity product.

Settlements:

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

calculation.

BPM Changes

• Reliability Requirements: Changes to the monthly RA process
• Settlements and Billing

Business Process Changes

Manage Market & Reliability Data & Modeling

• Manage Monthly & Intra-Monthly Reliability Requirements
• Manage Yearly Reliability Requirements

Slide 115

Spring 2018 - Reliability Services Initiative 2017

Slide 116

Milestone Type Milestone Name Dates Status

Board Approval Board Approval May 12, 2015



BPMs Post Draft BPM changes Jun 15, 2017 External BRS Post Updated External BRS v1.1 (RSI 2) Apr 07, 2017



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



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



Tariff File Tariff Q3 2017 Config Guides Config Guide Jun 27, 2017 Tech Spec Publish Technical Specifications Apr 03, 2017



Market Sim Market Sim Window Oct 30, 2017 - Dec 08, 2017 Production Activation RSI 2017 Feb 13, 2018

Spring 2018 – EIM Idaho Power Company

Project Info Details/Date Application Software Changes Implementation of Idaho Power Company as an EIM Entity. BPM Changes EIM BPM will be updated if needed to reflect new modeling scenarios identified during Idaho Power implementation and feedback from Idaho Power. Market Simulation The ISO approved the Idaho Power network model and continues to make progress integrating the Idaho model into the ISO non-production environment in preparation for integration testing. Parallel Operations February 1, 2018 – March 30, 2018

Slide 117

Milestone Type Milestone Name Dates Status Tariff File Readiness Certification Feb 28, 2018 Market Sim Market Sim Window Dec 01, 2017 - Jan 31, 2018 Parallel Operations Parallel Operations Window Feb 01, 2018 - Mar 30, 2018 Production Activation EIM - Idaho Power Apr 04, 2018

The ISO offers comprehensive training programs

Slide 118

All classes are offered at our Folsom, CA location unless noted otherwise. Training calendar - http://www.caiso.com/participate/Pages/Training/default.aspx Contact us - CustomerTraining@caiso.com Date Training May 24-25 Get to Know the ISO Jul 6 Welcome to the ISO - webinar Aug 16 Settlements 101 Aug 17 Settlements 201

ISO Daily Briefing

• A digest version of ISO market notices
• Distributed daily, Mon-Fri around 1:30 p.m. (PST)
• NEW: Upcoming Events - Every Thursday the briefing

will include stakeholder activities for the following week

• To subscribe to the Daily Briefing:
• Go to www.caiso.com
• Under “Stay Informed” tab
• Select “Notifications”
• Click under Market notices heading
• Select Daily Briefing from the list of categories

Note: If you currently receive ISO market notices and you re-subscribe, the system will override your previous category selections. If you still want to receive market notices in other categories, you’ll need to reselect those categories of interest.

Slide 119

Market Performance and Planning Forum 2017 Schedule

• July 18
• October 5 – Rescheduled from September 19
• November 14

Questions or meeting topic suggestions: Submit through CIDI - select the “Market Performance and Planning Forum” category

Slide 120