Very short term forecast of potential oversupply Using daily average numbers Cloud Cover Forecast VER Forecast > 5,500 MW Wind Speed Net Load Forecast < 16,000 MW Oversupply Risk Load Forecast < Temperature Hydro Self 21,500 MW Forecast Schedule > 4,000 MW Current solar capacity is capable of increasing the risk of oversupply without factoring in wind or hydro schedule Page 33 Last updated: March 15, 2017
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 Forecasted Ramp … Binding Advisory A A RTD Upward example 9:25 9:30 9:20 9:15 … Run time Binding Advisory A 9:07.5 for 9:15 110 MW 90 MW 100 MW Forecasted Movement = 100 – 90 = 10 MW (upward) Settlement = -1*10 MW * ($20 (FRU) - $10 (FRD)) = -$100 (Payment) RTD downward example 9:25 9:30 9:20 9:15 … Run time Binding Advisory A 9:07.5 for 9:15 75 MW 90 MW 85 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 9:25 9:30 9:20 9:15 … RTD Run 1 Run time Binding Advisory A 9:07.5 for 9:15 110 MW 90 MW 100 MW … RTD Run 2 Run time B A 9:12.5 for 9:20 107 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 Last updated: March 15, 2017
Good price convergence between FMM and RTD in February. Page 60
RT prices lower than DA prices for both NP15 and SP 15 in January and February. Page 61
Insufficient upward ramping capacity in ISO stayed at low levels since last November. Page 62
Insufficient downward ramping capacity increased in January and February. Page 63
Congestion revenue rights market revenue inadequacy without auction revenues. Page 64
Congestion revenue rights market revenue sufficiency including auction revenues. Page 65
Exceptional dispatch volume in the ISO area remained low in January and February. Page 66
Daily exceptional dispatches by reason Page 67
Real-time Bid cost recovery increased slightly in January and February Page 68
Bid cost recovery (BCR) by Local Capacity Requirement area Page 69
Minimum online commitment (MOC) Page 70
Pmax of MOC Cleared Units Page 71
Enforcement of minimum online commitments in November and December Number (frequency) of hours in MOC Name 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 72
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 Page 73
Hourly distribution of maximum RTD renewable (VERS) curtailment in February Page 74
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 75
CAISO Price correction events increased in February 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 Process Events Software Events Data Error Events Tariff Inconsistency Page 76
EIM-Related Price correction events increased in February 16 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 2016 2017 Process Events Software Events Data Error Events Tariff Inconsistency Page 77
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* PSE I PAC (88MW, 300MW) PAC E W (0MW, 0MW) (244MW, 963MW) (93MW, 766MW) NEV P AZP (123MW, 917MW) S (304MW, 1230MW) Page 80 *Notation: (average, maximum)
EIM BCR declined in February Page 81
EIM Manual Dispatch increased in February Page 82
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
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
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.
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.
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.
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.
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
Ongoing policy stakeholder initiatives (continued) • 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
Ongoing policy stakeholder initiatives (continued) • 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. 25,000 2013 2014 2015 2016 20,000 Generatioin (GWh) 15,000 10,000 5,000 0 Solar Wind Geothermal Biogas/Biomass Page 96
Prices mirrored net load patterns in 2016. $70 35,000 Day-ahead 15-minute Average net load $60 30,000 $50 25,000 Average net system load (MW) Price ($/MWh) $40 20,000 $30 15,000 $20 10,000 $10 5,000 $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 24 Page 97
As the ISO integrated more renewables, prices have been negative more frequently. 6% Below -$145 -$145 to -$50 -$50 to $0 5% Percent of 5-minute intervals 4% 3% 2% 1% 0% 2012 2013 2014 2015 2016 Page 98
As more solar has been added, negative price patterns have shifted. 18% 2012 2014 2016 16% Percent of negative 5-minute intervals 14% 12% 10% 8% 6% 4% 2% 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 Page 99
Participants typically bid solar into the market between -$25/MWh and $0/MWh. 3,000 Natural Gas Hydro Geothermal Wind Solar Other 2,500 2,000 Average hourly MW 1,500 1,000 500 0 -500 -1,000 -1,500 below -$50 -$50 to -$25 -$25 to $0 $0 to $25 $25 to $50 above $50 Page 100
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