Quick Response Demand-Side Resources to Balance Variable Renewables National Town Meeting on Demand Response and Smart Grid June 28, 2012 © EnerNOC Inc. What do these have in common? 2.5 kW! 2400 MW 2600 MW 2800 MW (April 29, 2011) (January 22, 1984) (July 4, 1990) 2 One more picture… 1500 MW (February 26, 2008) 3 It’s a big deal! “According to NERC’s 2008 Long-Term Reliability Assessment, over 145,000 MW of new variable resources are projected to be added to the North American bulk power system in the next decade . . . represent[ing] one of the largest new resource integration efforts in the history of the electric industry.” NERC Special Report: “Accommodating High Levels of Variable Generation,” April 2009 4 Wind output isn’t exactly predictable MW Hour of Day 5 Solar isn’t much better Solar PV Output (Partly Cloudy Day) 6 Exponential growth of wind capacity continues ERCOT 10,000 Cumulative Planned (Signed Interconnection Agreement) 7,912 997 7,912 7,912 1,357 8,909 2008 2009 2010 8,000 7,000 6,000 (MW) Wind Capacity Installed by Year BPA 9,269 Cumulative MW Installed 9,000 4,785 5,000 4,000 2,875 3,000 1,854 2,000 1,000 116 116 1999 2000 816 977 2001 2002 1,173 1,385 0 2003 2004 2005 2006 2007 Year (as of November 30, 2008) 7 Operating Reserves Examples of Ancillary Services Service Response Time Detail Regulation Service and Frequency Response Nearly instantaneous (~4 seconds) Automatically balances supply and demand in real time to maintain system voltage and frequency Spinning (or Synchronized) Reserves <10 minutes Capacity that is already online and can be ramped up quickly ~10 minutes Capacity that can be brought online quickly (typically fast-starting generators) 30-60 minutes Slower-responding capacity used to relieve the resources supplying spinning or non-spinning reserves Non-spinning (or Supplemental) Reserves Supplemental (or Replacement) Reserves 8 Why use DR for ancillary services? 1. Lower cost / postpone need for new capital investment 2. Improve utilization of existing resources 3. Enhance reliability Case Study: Hawai’i Marginal costa of responsive load typically Deploying DR resource forisjust 18 lower than cost of supply-side generation; days per year: resources can be put into place more quickly Reduced system operational cost 10+% ancillary If DR can be used by to provide services, generation capacity can avoid being “held back” and can operate at optimal level Increased overall potential for wind byportfolio 4% An aggregated, energy distributed of DR capacity providers leads to a decreased risk of performance failure Decreased the “reliability reserve deficit” from 31 days/year to 0 days/year Source: Power Systems Balancing with High Penetration Renewables: The Potential of Demand Response in Hawai’i Joint Institute for Strategic Energy Analysis, 2012 9 Aggregation provides reliability Utility Operator Utility Dispatch Reliable, Firm Resource Load Aggregator Specialized Specialized Software Software Platform Platform for for Addressing Managing Renewable Aggregated Resources Portfolio End Users Dispatch Load Response Grocery Store Dispatch Load Response Algorithm selects which customers to dispatch, based on: Hospital Dispatch • Account portfolio diversification by vertical Load Response Industrial Company • Load availability • Connectivity • Risk factor • Customer fatigue Customer not selected for participation Agriculture 10 However, it’s a more limited customer market than traditional DR Key Requirements • Need to be able to curtail load quickly through automated control • Need to be able to respond to frequent dispatch events, perhaps on a 24/7 basis • May need to be able to provide bi-directional response, depending on resource requirements Best Loads • Pumping • Hot water heating • Variable frequency drives • Refrigeration • Air conditioning • Battery charging • Dimmable lighting Prototypical Customers • Refrigerated warehouses • Wastewater treatment plants • Food processors • Heavy industrial • Water / gas pumping manufacturers stations 11 A single DR customer portfolio can provide multiple resources Emergency DR Resource (100 MW) - Typical dispatch: 6 hours duration; 1-2x/year; 60-minute notice - Load reduction only Peak-shaving DR Resource (50 MW) - Typical dispatch: 4 hours duration; 10-15x/year; 30-minute notice - Load reduction only Non-Spinning Reserves DR (20 MW) - Typical dispatch: 30-minute to 2 hours duration; 10-50x per year; 10-minute notice - Load reduction only Load-following DR Resource (5 MW) - Typical dispatch: 1-2x/day; 30-minute duration; 5-minute notice - Load reduction or increase (bi-directional dispatch) 12 DR for A/S: Current Examples Service DR Suitability Examples Regulation Requires continuous bidirectional control of loads PJM, MISO, NYISO Frequency Response Requires specialized technology (e.g. UFRs) ERCOT, Genesis (NZ), Alberta ESO,HECO Spinning and Nonspinning Reserves DR very well positioned, response time typically requires automated control PJM, ERCOT, NYISO, numerous interruptible and direct load control programs Load Following Dispatch frequency and need for bi-directional response are key considerations BPA 13 13 Key Market Drivers for Ancillary Services DR Balancing authority size / load profile Eligibility of DR to provide ancillary services Transmission network / degree of interconnection Wind forecast accuracy Scheduling granularity Generation base Wind spatial diversity Source: “Balancing Wind Down Ramps with Demand Response,” Duke Master’s Project http://dukespace.lib.duke.edu/dspace/handle/10161/5306 14 Anatomy of a Wind Balancing Resource BPA Load-following Pilot Response Types Fully automated load decreases (INCs) and increases (DECs) C/I Portfolio Currently focused on refrigerated warehouses Response Time Capacity dispatched upon 10 minutes notice. Availability 24 hours per day, year round Event Duration / Limitations Maximum event duration of 30 minutes Maximum of 2 events per day, 10 events per week Minimum of 3 hours between events Technology 1-minute DemandSMART interval metering Baseline Average of ten 1-minute readings prior to event start Performance For each interval, difference between baseline and facility usage Signal Transmitted Utility Control Room Near Real-Time Feedback DR Network Operations Center Signal Transmitted EMS/BMS Near Real-Time Feedback DR Gateway Meter End Use Loads 15 Conclusions Demand response can go beyond traditional peak-shaving and emergency roles to provide cost-effective ancillary services to grid operators. Advances in telemetry and automated control equipment will help DR cost-effectively meet a growing fraction of ancillary service requirements. Pilots are important to understand the extent to which both residential and C/I DR can provide true “load-following” services to help integrate intermittent renewables, and to inform effective program design. 16 Brad Davids Vice President, Utility Solutions bdavids@enernoc.com 17