Seasonal Trends are Present with New Method (Regulation Up) 500 Regulation Up Minimum Capacity 450 400 350 300 (MW) 250 200 150 100 50 0 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 Hour Ending Jan Feb Mar Apr May Jun Jul Aug SEP OCT NOV DEC Values above are based on historical information and are subject to change. Slide 21
Seasonal Trends (Regulation Down) 800 Regulation Down Minimum Capacity 700 600 500 (MW) 400 300 200 100 0 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 Hour Ending Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Values above are based on historical information and are subject to change. Slide 22
May 2016 Regulation Procurement Versus October 2016 Procurement 800 Spring 2016 Regulation Capacity 600 Regulation Requirement (MW) 400 200 Oct 2016 Regulation Capacity 0 -200 -400 -600 -800 -1000 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 Hour of the Day (Hour Ending) Slide 23
October 2016 Results Percentage of time with insufficient capacity: 1% Slide 24
Flexible Ramp Product Update Slide 25
Flexible Ramp Product • Flexible Ramp product went live on November 1, 2016 • There is both upward and downward definitions for the product. • Each EIM area has its own requirement, and there is also a system-wide EIM area enforced in the real-time market. • There is also a flexible ramp sufficiency test done prior to the real-time market. • Requirements are based on historical data and calculated in the Balancing Area Ramp Requirement (BARR) application. Slide 26
What is the Balancing Area Ramp Requirement Tool? • The Balancing Area Ramp Requirement (BARR) tool calculates the uncertainty requirement and the demand curves for the Flex Ramp Product • The uncertainty requirements are hourly values calculated every day using the BARR tool • Uncertainty requirements are based on net load forecast error Net load = Load – Wind - Solar • The demand curves are the prices the system is willing to pay for a given quantity of flex ramp capacity Slide 27
Flexible Ramp Uncertainty Requirement: 5-minute Real-Time Dispatch (RTD) RTD Net Load Forecast Error is difference between the binding interval net load forecast and the prior market run first advisory net load forecast Slide 28
Flexible Ramp Uncertainty Requirement: 15-minute Real-Time Pre-Dispatch (RTPD) RTPD RTPD Net Load Forecast Error is maximum difference between the three RTD binding interval net load forecasts and the associated RTPD first advisory net load forecast Slide 29
Example of the Hourly Distribution of Data that Comprises the Histogram for Each EIM Entity Slide 30
Example of the Hourly Distribution of Data and the Calculated Uncertainty Requirements (Red Lines) Slide 31
An Example of the Flex Ramp Product Uncertainty Calculation • Flex Up and Down Uncertainty Requirement could be calculated as follows: – For each hour, gather the set of recent net load forecast errors for the appropriate market uncertainty – Group weekdays and weekends separately due to characteristic differences • Weekdays use last 40 days of net load forecast error • Weekends use last 20 days of net load forecast error – The flex up uncertainty requirement is the 97.5 percentile – The flex down uncertainty requirement is the 2.5 percentile • Daily thresholds are calculated using a similar process but with a larger set of data – Significant reduction in % of time thresholds are setting the requirement compared to the Flex Ramp Constraint Slide 32
Demand Curves • The demand curves are used to determine how much flexible ramp capacity the system will procure • One demand curve for each EIM entity and ISO plus the EIM Total Area (including ISO) for 7 total demand curves • The demand curves are the distribution of net load errors multiplied by the energy penalty price cap or floor – The penalty price cap is $1000 per MWh – The penalty price floor is $-150 per MWh • The maximum price is $247 per MW • The minimum price is $-155 per MW Slide 33
Constructing a Demand Curve • A demand curve starts with the probability distribution of net load forecast errors – This is the same set of data that is used for determining the uncertainty requirement • The flex ramp up demand curve is built by calculating the percent of data that is greater than a given MW value • The flex ramp down demand curve is built by calculating the percent of data that less than a given MW value • The percentage is converted a price by multiplying by either the energy penalty price cap or price floor • Finally, the curve is transformed from MW to Relaxation Capacity by subtracting the MW values from the uncertainty requirement Slide 34
Constructing a Demand Curve (Cont.) • The OASIS published demand curves are comprised of two components – The amount of capacity to relax the uncertainty requirement – The price associated for relaxing the uncertainty requirement • Example – With an uncertainty requirement of 100 MW, a relaxation capacity of 15 MW, and a price of $25 per MW – This means the market procured 85 MW of flexible capacity at a price of $25 per MW Slide 35
Example of Constructing a Flex Up Demand Curve: Start with Probability Distribution of Net Load Forecast Errors 45% Curves are limited to the flex up or down Percent of Data Greater than A Given Net Load Forecast 40% uncertainty requirement 35% 30% Error (%) 25% 20% 15% 10% 5% 0% 0 20 40 60 80 100 120 140 160 Net Load Forecast Error Between RTPD Advisory and RTD Binding (MW) Slide 36
Convert Percentage to Price by Multiplying the Curve by the Energy Penalty Price Cap ($1000 per MWh) 450 400 350 300 Price ($/MW) 250 200 150 100 50 0 0 20 40 60 80 100 120 140 160 Net Load Forecast Error Between RTPD Advisory and RTD Binding (MW) Slide 37
Convert x-axis to Relaxation MW by Subtracting the Net Load Forecast Errors From the Uncertainty Requirement 450 400 350 300 Price ($/MW) 250 200 150 100 50 0 160 140 120 100 80 60 40 20 0 Relaxaion Capacity (MW) Slide 38
The Curve is then Segmented for Use in the Market Optimization 450 400 350 300 Price ($/MW) 250 200 150 100 50 0 160 140 120 100 80 60 40 20 0 Relaxation Capacity (MW) Slide 39
Finally, the Curve is Capped (if Required) at the Minimum or Maximum Price ($-155/MW or $247/MW) 350 300 The segmented demand curve is then capped at a price of $247 per MW 250 Price ($/MW) 200 150 100 50 0 160 140 120 100 80 60 40 20 0 Relaxation Capacity (MW) Slide 40
FRP performance Slide 41
FRP requirements and prices driven by the hourly profile needs Slide 42
With FRP construct, the EIM area generally drives the overall procurement 2,000 1,500 1,000 500 Flex Ramp (MW) 0 -500 -1,000 -1,500 -2,000 -2,500 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 APS NV Energy PSE PACW PACE ISO Credit Upward/Downward requirement Slide 43
Flexible Ramp requirements adjusted with FRP activation Slide 44
Hourly profile of ISO FRP requirements Slide 45
Gas Price Update • FERC clarified use of daily ICE gas price index • Normal cycle calculates blended gas price indices the prior night which is used for both DAM and RTM markets. • With new provisions, the ICE index available in the morning is used for the DAM market run. • When no ICE price index is available, it defaults to use previous night blended index. Slide 46
Gas price difference of using morning ICE gas price update Slide 47
Gas price difference of using morning ICE gas price update 25% 100% 90% 20% 80% 15% % Price Difference ($/MMBTu) 70% % of Volume Traded 10% 60% 5% 50% 0% 40% -5% 30% -10% 20% -15% 10% -20% 0% 31-Oct 2-Nov 4-Nov 6-Nov 8-Nov 10-Nov 12-Nov 14-Nov 16-Nov 18-Nov 20-Nov 22-Nov 24-Nov 26-Nov 28-Nov 30-Nov 2-Dec 4-Dec 25-Oct 27-Oct 29-Oct Volume SCE CityGate Hub Slide 48
Gas price difference of using morning ICE gas price update 25% 100% 90% 20% 80% 15% % Price Difference ($/MMBTu) 70% % of Volume Traded 10% 60% 5% 50% 0% 40% -5% 30% -10% 20% -15% 10% -20% 0% 31-Oct 2-Nov 4-Nov 6-Nov 8-Nov 10-Nov 12-Nov 14-Nov 16-Nov 18-Nov 20-Nov 22-Nov 24-Nov 26-Nov 28-Nov 30-Nov 2-Dec 4-Dec 25-Oct 27-Oct 29-Oct Volume KRN Del Pool Hub Slide 49
EIM Update • Arizona Public Service (APS) and Puget Sound (PSE) joined the EIM market on October 1, 2016. • In the first hours after the activation, market observed minor transitional issues. • Both entities are under the six-month transitional period, under which price discovery provisions apply. Slide 50
90% of the time APS and PSE have passed the balancing test in over 100% 10% 20% 30% 40% 50% 60% 70% 80% 90% 0% 100% 10% 20% 30% 40% 50% 60% 70% 80% 90% 0% 1-Oct 2-Oct 1-Oct 3-Oct 2-Oct 4-Oct 3-Oct 5-Oct 4-Oct 6-Oct 5-Oct 7-Oct 6-Oct 7-Oct 8-Oct Passed Test Passed Test 8-Oct 9-Oct 9-Oct 10-Oct 10-Oct 11-Oct 11-Oct 12-Oct 12-Oct 13-Oct 13-Oct 14-Oct AZPS Area PSEI Area 14-Oct Underscheduling Underscheduling 15-Oct 15-Oct 16-Oct 16-Oct 17-Oct 17-Oct 18-Oct 18-Oct 19-Oct 19-Oct 20-Oct 20-Oct 21-Oct 21-Oct 22-Oct Overscheduling Overscheduling 22-Oct 23-Oct 23-Oct 24-Oct 24-Oct 25-Oct 25-Oct 26-Oct 26-Oct 27-Oct 27-Oct 28-Oct 28-Oct 29-Oct 29-Oct 30-Oct 30-Oct 31-Oct 31-Oct Slide 51
October and PSE have been less than 0.3% of the time in Power balance constraint infeasibilities in both APS 10% 20% 30% 40% 50% 0% 10% 20% 30% 40% 50% 0% 1-Oct 1-Oct 2-Oct 2-Oct 3-Oct 3-Oct Valid RTD Under-supply Infeasibility 4-Oct 4-Oct 5-Oct 5-Oct Valid FMM Under-supply Infeasibility 6-Oct 6-Oct 7-Oct 7-Oct 8-Oct 8-Oct 9-Oct 9-Oct 10-Oct 10-Oct 11-Oct 11-Oct 12-Oct 12-Oct 13-Oct 13-Oct 14-Oct 14-Oct 15-Oct 15-Oct Load Bias Limiter 16-Oct 16-Oct 17-Oct 17-Oct 18-Oct 18-Oct 19-Oct 19-Oct 20-Oct Correctable Infeasibilities 20-Oct 21-Oct 21-Oct 22-Oct Correctable Infeasibilities 22-Oct 23-Oct 23-Oct 24-Oct 24-Oct 25-Oct 25-Oct 26-Oct 26-Oct 27-Oct 27-Oct 28-Oct 28-Oct 29-Oct 29-Oct 30-Oct 30-Oct 31-Oct 31-Oct Slide 52
been less than 0.3% of the time in October Power balance constraint infeasibilities in PSE have 10% 20% 30% 40% 50% 10% 20% 30% 40% 50% 0% 0% 1-Oct 1-Oct 2-Oct 2-Oct 3-Oct 3-Oct Valid RTD Under-supply Infeasibility 4-Oct 4-Oct 5-Oct 5-Oct Valid FMM Under-supply Infeasibility 6-Oct 6-Oct 7-Oct 7-Oct 8-Oct 8-Oct 9-Oct 9-Oct 10-Oct 10-Oct 11-Oct 11-Oct 12-Oct 12-Oct 13-Oct 13-Oct 14-Oct 14-Oct 15-Oct 15-Oct Load Conformance 16-Oct 16-Oct 17-Oct 17-Oct 18-Oct 18-Oct 19-Oct 19-Oct Correctable Infeasibilities 20-Oct 20-Oct 21-Oct 21-Oct 22-Oct 22-Oct Correctable Infeasibilities 23-Oct 23-Oct 24-Oct 24-Oct 25-Oct 25-Oct 26-Oct 26-Oct 27-Oct 27-Oct 28-Oct 28-Oct 29-Oct 29-Oct 30-Oct 30-Oct 31-Oct 31-Oct Slide 53
EIM Price trends Slide 54
Transfer capabilities in EIM areas Slide 55
Market Update Slide 56
Good price convergence between IFM and RTD in September and October. Slide 57
RT prices higher than DA prices for both NP 15 and SP 15 in September but lower than DA in SP15 in October. Slide 58
Insufficient upward ramping capacity in ISO increased in October. Slide 59
Insufficient downward ramping capacity remained low in 2016. Slide 60
Congestion revenue rights market revenue inadequacy without including auction revenues. Slide 61
Congestion revenue rights market revenue sufficiency including auction revenues. Slide 62
Exceptional dispatch volume in the ISO area continued at low levels. Slide 63
Daily exceptional dispatches by reason Slide 64
Real-time Bid cost recovery dropped in October Slide 65
Bid cost recovery (BCR) by Local Capacity Requirement area Slide 66
Minimum online commitment (MOC) Slide 67
Pmax of MOC Cleared Units Slide 68
Enforcement of minimum online commitments in September and October Number (frequency) of hours in MOC Name September and October Humboldt 7110 1436 MOC TABLE MTN 504 HNTBH 7820 187 Orange County 7630 134 MOC East Nicolaus 4385234 125 SCIT MOC 67 MOC NP15 11 MOC SAN ONOFRE BUS 10 SDGE 7820 3 Slide 69
IFM under-scheduling of solar generation Slide 70
IFM under-scheduling of wind generation declined in September and October Slide 71
Renewable (VERS) schedules including net virtual supply and aligns with VER forecast in September and October http://www.caiso.com/Pages/documentsbygroup.aspx?GroupID=EFF75C 2E-F28E-4087-B88B-8DFFAED828F8 Slide 72
RTD renewable (VERS) curtailment rose since August Slide 73
RTD renewable (VERS) curtailment versus avoided curtailment Slide 74
Hourly distribution of maximum RTD renewable (VERS) curtailment in October Slide 75
Wind, solar and hydro production Slide 76
Monthly wind (VERS) downward flexibility in FMM Slide 77
Monthly solar (VERS) downward flexibility in FMM Slide 78
Monthly solar (VERS) downward flexibility in FMM from 11 AM to 5 PM Slide 79
ISO area RTCO and RTIEO remains at relatively low levels in September and October. 2015 2016 (YTD) RTCO $55,489,221 $49,049,744 RTIEO $13,817,548 $380,581 Total Offset $69,306,769 $49,430,324 Slide 80
Price correction events increased in September and October 10 9 8 7 6 Count of Events 5 4 3 2 1 0 Jan-15 Feb-15 Mar-15 Apr-15 May-15 Jun-15 Jul-15 Aug-15 Sep-15 Oct-15 Nov-15 Dec-15 Jan-16 Feb-16 Mar-16 Apr-16 May-16 Jun-16 Jul-16 Aug-16 Sep-16 Oct-16 Process Events Software Events Data Error Events Tariff Inconsistency Slide 81
EIM BCR in September and October Page 82
EIM Exceptional Dispatch in September and October Slide 83
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 2014 2015 2016 Slide 84
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 2014 2015 2016 Slide 85
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 2014 2015 2016 Slide 86
Day-ahead solar forecast 14.0% 12.0% 10.0% 8.0% 6.0% MAE 4.0% 2.0% 0.0% Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 2014 2015 2016 Slide 87
Real-time wind forecast 4.5% 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 2014 2015 2016 Slide 88
Real-time solar forecast 6% 5% 4% 3% MAE 2% 1% 0% Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 2014 2015 2016 Slide 89
Real-time solar forecast 6% 2016’s October MAE becomes more comparable 5% to previous years when the Curtailed Solar MW are 4% added back into Actuals. 3% MAE 2% 1% 0% Oct 2014 2015 2016 2016_withCurtailedMW Slide 90
Load Forecast Adjustments Gabe Murtaugh Sr. Market Monitoring Analyst, Department of Market Monitoring Slide 91
Growth in EIM transfer capacity significantly increases market competiveness. Total average transfer capacity (May-Oct 2016) Puget 300 MW 300 MW 293 MW PacifiCorp West 0 MW PacifiCorp 85 MW East 126 MW 468 MW NV 872 MW Energy 710 MW CAISO 899 MW 321 MW 216 MW 1,874 MW APS 924 MW Slide 92
Congestion into EIM areas is very infrequent. Frequency of congestion in 15-minute market (May-Oct 2016)* Puget 1% (205 MW) 1% (187 MW) PacifiCorp 4% (105 MW) West 23% (0 MW) PacifiCorp 2% 20% 7% (221 MW) East (27 MW ) (463 MW) .2% NV (611 MW) Energy .3% (156 MW) 1% CAISO 7% 2% MW (119 MW) (150 MW) (790 MW) * Average transfer MW during 0% congested intervals APS in parentheses. .3% (143 MW) Slide 7
EIM areas separated by congestion from the ISO only 1-3 percent of intervals. Slide 94
Settlement prices in Arizona largely reflected prices in the ISO during October. $100 Arizona Public Service settlement price $90 Southern California Edison settlement price Average hourly price ($/MWh) $80 Bilateral price benchmark $70 $60 $50 $40 $30 $20 $10 $0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 Slide 95
Settlements prices in Puget Sound were lower than the ISO and reflected PacifiCorp West prices. $100 Pacific Gas and Electric settlement price $90 Puget Sound Energy settlement price $80 PacifiCorp West settlement price Average hourly price ($/MWh) $70 Bilateral price benchmark $60 $50 $40 $30 $20 $10 $0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 Slide 96
Positive load adjustments were more frequent in NV Energy and the ISO, while negative load adjustments were more frequent in the PacifiCorp areas. Positive load adjustments Negative load adjustments Average Percent of Average Percent of Percent of Average Percent of hourly bias intervals MW total load intervals MW total load MW California ISO 15-minute market 44% 471 1.4% 14% -274 1.1% 169 5-minute market 56% 438 1.4% 27% -300 1.1% 162 PacifiCorp East 15-minute market 5% 91 1.6% 42% -101 1.9% -38 5-minute market 9% 88 1.5% 63% -125 2.4% -71 PacifiCorp West 15-minute market 3% 38 1.5% 43% -49 2.2% -20 5-minute market 4% 42 1.7% 49% -58 2.6% -27 NV Energy 15-minute market 48% 132 2.3% 1% -171 3.6% 62 5-minute market 44% 95 1.7% 11% -83 1.7% 32 Slide 97
Load adjustments in NV Energy tended to be greatest in the late afternoon, while PacifiCorp East adjusted by the greatest quantity in the morning. 250 15-minute market (PacifiCorp East) 5-minute market (PacifiCorp East) 15-minute market (PacifiCorp West) 5-minute market (PacifiCorp West) 200 15-minute market (NV Energy) 5-minute market (NV Energy) 150 100 MW 50 0 -50 -100 -150 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 Slide 98
Policy Update Brad Cooper Manager, Market Design and Regulatory Policy Slide 99
Ongoing policy stakeholder initiatives • Contingency modeling enhancements – Technical analysis results targeted Dec – Stakeholder call on technical analysis targeted Dec – May 2017 Board Meeting • Generator contingency and remedial action scheme modeling – Revised straw proposal targeted Jan 2017 – Jul 2017 Board Meeting • Stepped transmission constraints – New schedule being developed – Board Meeting TBD Slide 100
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