California Market Designs for Grid Services to Integrate Renewable Energy Portfolios

Transcription

1 1 California Market Designs for Grid Services to Integrate Renewable Energy Portfolios Jim Price, Senior Advisor, Market Development & Analysis, California ISO IEEE PES Panel Session: Incentive Compatible Pricing, Payment, and Cost Allocation of Market-Based Grid Services 16PESGM0309

2 CAISO markets provide a responsive foundation for matching changes in supply & demand 60 Hz Day Ahead Market Hourly market for 24 hours of next day Establish energy and ancillary service schedules Manage congestion (transmission access) using Full Network Model (FNM) Determine residual unit commitment requirements Hourly & 15-minute Scheduling Prior to real-time (RT) market, schedule energy and ancillary services for static interchange for 24 individual hours Manage congestion using FNM As one of 4 RT pre-dispatch processes, establish unit commitment & advisory schedules for internal & dynamic resources Load Generation Real Time Market Manage energy flows on transmission grid with telemetry and 1-minute state estimator solutions Update FNM for RT conditions Dispatch balancing energy/ ancillary service Slide 2

3 Changing California resource mix presents new operational challenges Over 20,000 MW of wind and solar capacity to be interconnected by 2020 (33% renewable energy by 2020, 50% by 2030) Increased supply volatility Changes to load patterns as a result distributed generation and electric vehicles Changing, less predictable load patterns Approximately 18,000 MW of thermal generation will be repowered or retired Uncertainty surrounding thermal resources Slide 3 o Phase out 12,000 MW of coastal plants with once-through cooling o Greenhouse gas reductions limit replacement generation o Water flow management affects hydro availability

4 Load & Net Load (MW) Wind & Solar (MW) Changing resource mix changes the net load pattern for dispatch, with new needs for market products 34,000 32,000 30,000 28,000 26,000 24,000 22,000 20,000 18,000 16,000 6,700 MW in 3-hours Load, Wind & Solar Profiles -- Base Scenario January ,000 MW in 3-hours 12,700 MW in 3-hours 9,000 8,000 7,000 6,000 5,000 4,000 3,000 2,000 1,000 14,000 0 Net_Load Load Wind Total Solar Net Load = Load - Wind - Solar Slide 4

5 Changes can already be seen in CAISO s net demand (Source: ISO Today iphone App, 3/24/2016) 5

6 ISO's Net Load (MW) 5-Minute Energy Prices ($) New events (like negative energy prices indicating risk of over-generation) introduce new opportunities 22,000 ISO's Net Load vs. Average 5-Minute Energy Prices April 12, , ,000 19, , ,000 16,000 15, , Net Load MCP_RTD 5-Min_Prices<=Zero 5-Min_Prices>$100 Example, April 12, 2014: Coincident MW of wind & solar was 35% of total 23,450 system load, dropping net load to 15,000 MW. With limited decremental bids, energy prices were zero or negative (blue dots) for 43% of 5-minute RTD intervals. -40 Slide 6

7 Demand response and storage can provide flexibility to shift load to periods of excess supply Resources Traditional Use Future grid Value Conventional generation Renewable generation Demand response Baseload Peaking Ability to start and stop frequently Low minimum operating levels Must take Ability to modify output Emergency Frequent, short duration events Automated response Supports ramping needs Mitigates overgeneration Decreases ramping needs Provides voltage support Defers or offsets generation or transmission investment Mitigates overgeneration Energy storage Electric vehicles Slide 7 Peak-shifting Ability to start and stop frequently Frequent, short duration events Not applicable Frequent, short duration events Automated response Supports ramping needs Mitigates overgeneration Provides frequency response Mitigates overgeneration Provides frequency response

8 Real-Time Economic Dispatch (RTD) meets energy balance within each resource s capability 8

9 Uncertainty: net demand in prior advisory interval differs from financially binding dispatch Short deviations in net demand can cause price volatility, to be addressed by procuring additional ramping capacity if benefit exceeds cost 9

10 Flexible ramping requirement reflects uncertainty in resource need to meet expected net demand Flexible Ramping Up: Uncertainty Forecast Flexible Ramping Down: Uncertainty 10

11 Across multi-interval look-ahead horizon, ramping capacity ensures sufficient flexibility in RTD Flexible ramping product: Secures ramping capability in 15-minute market & RT dispatch Meets forward-looking needs, considering future uncertainty Compensates resources whose dispatch is held back in financially binding interval to meet future ramping needs Energy Allocates costs to movement that requires others to be dispatched Ensures consistent compensation with energy bids by settling both energy and forecasted ramp in the binding interval Energy 11

12 Costs allocated to uncertainty (& benefit from ramping capability): load, supply and interties 12

13 Operational experience will determine if further enhancements are needed Product enhancements turn current flexi-ramp constraint into market product (Fall 2016): Add bidding & flexible downward ramping Refine flexible ramping compensation & cost allocation Open areas for possible future enhancements include: Procurement in day-ahead market Explicit ramping bid Regional procurement within a balancing authority area Example of market structure questions: Do flexi-ramp and operating reserve interact as market concepts? (procurement for contingency vs. for dispatch) 13