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

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 RTD Wind Solar Forecast Type External FSP 6.5% 8.5% Lag 3.2% 5.9% PCM 3.5% 4.9% PCM and Lag methods reduced External FSP MAPE by 50% for RTD Slide 46

MAE MAE 0% 1% 2% 3% 4% 5% 6% 10% 12% 0% 2% 4% 6% 8% 0:00 1:10 Total Mae Value for RTD SOLAR Forecast 0:00 2:20 1:25 3:30 2:50 4:40 4:15 5:50 5:40 7:00 7:05 8:10 lag lag 9:20 8:30 10:30 9:55 Unit A Unit C 11:40 11:20 12:50 12:45 pcm 14:00 pcm 14:10 15:10 15:35 16:20 17:00 17:30 18:25 18:40 19:50 19:50 21:00 21:15 22:10 22:40 23:20 MAE MAE 10% 12% 0% 2% 4% 6% 8% 10% 12% 14% 0% 2% 4% 6% 8% 0:00 0:00 1:10 1:25 2:20 3:30 2:50 4:40 4:15 5:50 5:40 7:00 7:05 8:10 lag lag 8:30 9:20 9:55 10:30 Unit B Unit D 11:40 11:20 12:50 12:45 pcm 14:00 pcm 14:10 15:10 15:35 16:20 17:00 17:30 18:25 18:40 19:50 19:50 21:00 21:15 22:10 22:40 23:20 Slide 47

APPENDIX Slide 48

Simple Lag Persistence Model • Name Convention: A (actual), F (forecast), E (Error) = F – A • FH = Forecast Horizon (RTD) • Lag Model – F(t) = A(t-FH) (Forecast for time t = Actuals from time t-FH) Slide 49

Recommendation for Solar Resources Persistence Counter Market Model • Let F(t) be forecast, A(t) be actual, and FPI(t) be estimate of full power output taking into consideration sun angle. • The persistent forecast is then: – F(t) = A(t-lag) / FPI(t-lag)* FPI(t) – Where A(t-lag) / FPI (t- lag) is the estimate “cloud” factor to A(t)/FPI(T) The premise is the lag forecast A(t-lag) should adjust according the track of performance under different cloudiness condition at lag time point Slide 50

Example • Sunny Day: – A(t-lag) / FPI(t-lag) = 1 • Cloudy Day: – A(t-lag) / FPI(t-lag) = .3 Slide 51

Market Update

Good price convergence in April based. Note: Metric Based on System Marginal Energy Component (SMEC) Slide 53

RT prices higher than DA prices for both NP15 and SP15 in April. Slide 54

Insufficient upward ramping capacity in ISO continued to be at low levels since last November. Slide 55

Insufficient downward ramping capacity declined since February. Slide 56

Congestion revenue rights market revenue inadequacy without auction revenues. Slide 57

Congestion revenue rights market revenue sufficiency including auction revenues. Slide 58

Exceptional dispatch volume in the ISO area decreased since February. Slide 59

Real-time Bid cost recovery dropped in April Slide 60

Bid cost recovery (BCR) by Local Capacity Requirement area Slide 61

Minimum online commitment (MOC) MOC San Onofre Bus Slide 62

Pmax of MOC Cleared Units Slide 63

Enforcement of minimum online commitments in March and April Number (frequency) of hours in MOC Name 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 64

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 65

Hourly distribution of maximum RTD renewable (VERS) curtailment in April Slide 66

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 67

CAISO Price correction events increased in March and April 10 9 8 7 6 Count of Events 5 4 3 2 1 0 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 Process Events Software Events Data Error Events Tariff Inconsistency Slide 68

EIM-Related Price correction events decreased in March and April 14 12 10 Count of Events 8 6 4 2 0 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr 2016 2017 Process Events Software Events Data Error Events Tariff Inconsistency Slide 69

EIM Price trends Slide 70

Robust Energy transfers observed in in 1st quarter, 2017 Average – 80MW Maximum – 300MW PSEI Average – 108MW Maximum – 300MW Average – 118MW PACW PACE Maximum – 300MW Average – 0MW Maximum – 0MW Average – 165MW Average – 141MW Maximum – 909MW Maximum – 330MW Average – 136MW Maximum – 360MW Average – 144MW Maximum – 857MW Average – 173MW Average – 184MW Maximum – 506MW Maximum – 945MW Average – 222MW NEVP Maximum – 791MW Average – 0MW Maximum – 0MW Average – 231MW Average – 84MW Maximum – 871MW Maximum – 150MW Average – 186MW Maximum – 739MW AZPS CAISO Average – 259MW Maximum – 1196MW Slide 71

EIM BCR observed a modest increased in April Slide 72

EIM Manual Dispatch increased in April and is mostly concentrated in APS area Slide 73

Day-ahead load forecast 3.0% 2.5% 2.0% 1.5% MAPE 1.0% 0.5% 0.0% Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 2015 2016 2017 Slide 74

Day-ahead peak to peak forecast accuracy 3.5% 3.0% 2.5% 2.0% 1.5% MAPE 1.0% 0.5% 0.0% Mar Apr May Aug Sep Nov Dec Jan Feb Jun Jul Oct 2015 2016 2017 Slide 75

Day-ahead wind forecast 10.0% 9.0% 8.0% 7.0% 6.0% 5.0% 4.0% MAE 3.0% 2.0% 1.0% 0.0% Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 2015 2016 2017 **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 10.0% 9.0% 8.0% 7.0% 6.0% 5.0% 4.0% MAE 3.0% 2.0% 1.0% 0.0% Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 2015 2016 2017 **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 4.0% 3.5% 3.0% 2.5% 2.0% MAE 1.5% 1.0% 0.5% 0.0% Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 2015 2016 2017 **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 6% 5% 4% 3% MAE 2% 1% 0% Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 2015 2016 2017 **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 or 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 obligation – phase 2 – Second revised straw proposal in July – Q2 2018 ISO Board meeting • Congestion revenue right auction efficiency – Stakeholder working group on analysis in April – Analysis phase in progress – Policy development phase starting after analysis complete in 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. $70 $7 Average cost (nominal) Average cost normalized to gas price, including greenhouse gas adjustment $60 $6 Average annual gas price ($/MMBtu) Average daily gas price, including greenhouse gas adjustments ($/MMBtu) Average annual cost ($/MWh) $50 $5 $40 $4 $30 $3 $20 $2 $10 $1 $0 $0 2012 2013 2014 2015 2016 Slide 89

Estimated average wholesale energy costs per MWh (2012 – 2016) Change '15-'16 2012 2013 2014 2015 2016 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) Slide 90

Markets continued to perform close to competitive benchmarks. $50 Competitive baseline ($/MWh) Average load-weighted day-ahead price Average load-weighted 15-minute price Average load-weighted 5-minute price $40 Average price ($/MWh) $30 $20 $10 $0 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Slide 91

Estimated net revenue of a hypothetical new unit 2012 - 2015 Combined Cycle Combustion Turbine $220 $220 $200 $200 $180 $180 $160 $160 Net revenues (NP15) Net revenues (NP15) $140 $140 $/kW-year $/kW-year Net revenues (SP15) Net revenues (SP15) $120 $120 Levelized fixed cost target $100 $100 Levelized fixed cost target $80 $80 $60 $60 $40 $40 $20 $20 $0 $0 2012 2013 2014 2015 2012 2013 2014 2015 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) Significantly below California Energy Commission’s estimate of annualized fixed costs for a hypothetical combined cycle is $166/kW-yr Total energy Operating costs Net revenue Zone Scenario Capacity factor revenues ($/kW-yr) ($/kW-yr) ($/kW-yr) Day-ahead prices and default energy bids 21% $75.88 $64.65 $11.23 NP15 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 22% $79.73 $66.82 $12.91 5-minute prices using default energy bids Day-ahead prices and default energy bids 29% $104.92 $84.40 $20.52 SP15 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 30% $108.51 $86.38 $22.13 5-minute prices using default energy bids Slide 94

Financial analysis of new combustion turbine (2016) Significantly below California Energy Commission’s estimate of annualized fixed costs for a hypothetical combustion turbine is $177/kW-yr Real-time energy Operating costs Net revenue Zone Scenario Capacity factor revenues ($/kW-yr) ($/kW-yr) ($/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 NP15 5.6% $27.85 $22.17 $5.68 adder 15-minute commitment with dispatch to 15-minute 5% $31.41 $21.03 $10.38 and 5-minute prices using default energy bids 15-minute prices and default energy bids 7% $41.37 $28.87 $12.50 15-minute prices and default energy bids without SP15 9% $48.20 $34.33 $13.87 adder 15-minute commitment with dispatch to 15-minute 8% $50.07 $32.79 $17.29 and 5-minute prices using default energy bids Slide 95

Flexible ramping payments $2.5 $0.10 California ISO PacifiCorp East Payments per MWh load ($/MWh) PacifiCorp West NV Energy Total payments ($ million) Puget Sound Energy Arizona Public Service $2.0 $0.08 Payments per MWh of load Flexible ramping product implementation $1.5 $0.06 $1.0 $0.04 $0.5 $0.02 $0.0 $0.00 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 Slide 96

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

Release Plan 2017 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 Slide 98

Release Plan – 2018 and subject to further planning 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 Slide 99

2017 - MRI-S ACL Groups+ CPG Enhancements Project Info Details/Date 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. Application Software Changes 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 2 nd re-opening of the MRI-S Metering: September 1, 2017. BPM Changes None Potential Level-II business process changes under – • Business Process Changes Manage Market & Reliability Data & Modeling • Manage Operations Support & Settlements 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 Mar 13, 2017 – June 9, 2017 Market Simulation Phase 2 - MRI-S Metering Enhancements  Production Activation Phase 1 - ACL Groups Mar 10, 2017 Phase 2 - MRI-S Metering CPG Enhancements Jun 13, 2017 Slide 100