Demand Management from an Aggregator's Perspective David Brewster, President May 21, 2009
Today s Energy Challenges
Unprecedented Challenges Higher Demand Increased Costs Renewable Energy
10% of Costs for 1% of the Time Annual Energy Demand 100% 90% 75% 50% 25% Winter Spring Summer Fall
Demand Response is the Solution Dispatchable Reliable Demand Response Clean Cost Effective
Why Demand Response? 100 MW Demand Response 100 MW Combustion Turbine Transmission Losses None 8-10% Annual Carbon Emissions None 6,500 tons Siting Anywhere Limited Time to Build 3-6 months Years
Aggregator Model
Connecting a Broken System Management Grid Operators Commercial Institutional Network Utilities Industrial
Aggregator Model Originated in U.S. restructured markets (ISO-NE, PJM, NYISO) Grid Operator/Utility contracts with aggregator for capacity Contract is similar to a power purchase agreement (PPA) Capacity payments ($/kw) and energy payments ($/kwh) Penalties apply for under-performance Aggregator builds a portfolio to deliver contracted capacity Responsible for all aspects of program delivery All costs (e.g., marketing, enablement) included in capacity/energy payments Contract is signed between Aggregator and end user (no tariff/rate required) Revenue is shared between aggregator and end user
Revenue Share Arrangement GRID OPERATOR/ UTILITY DEMAND RESPONSE AGGREGATOR
Why Aggregation? 50 MW More reliable resource performance Smaller customers can participate Idiosyncratic / variable loads can be matched with others in the portfolio vs. Risk-free participation 250 kw 1 MW 300 kw 1 MW 1 MW 300 kw 5 MW 300 kw 1 MW 300 kw 200 kw 300 kw 1 MW 1 MW 300 kw 300 kw 300 kw 1 MW 1 MW 400 kw
Managing Risk: DR Portfolio Management Customer 1 Customer 2 Customer 3 Customer 4 By aggregating resources into a single portfolio, the aggregator manages 100% of the risk associated with delivering a contracted amount of capacity. In this manner, both the grid operator/utility and end users are protected from under-performance. Customer 5 Customer 6 Customer 7 Customer 8 Customer 9 Customer 10 Customer 11 Customer 12 Customer 13 Customer 14 Customer 15 Customer 16 0% 50% 100% 150% Aggregator 0% 50% 100% 150% Avg Events 2006 103 % 34 2007 106 % 120 2008 102 % 101 Grid Operator/Utility 0% 50% 100% 150% 0% RISK 100% RISK 0% RISK 13
Value Proposition to Grid Operator/Utility Cost-effective alternative to building/maintaining a combustion turbine Resource/fuel diversity No NIMBY or BANANA Reduced carbon exposure Flexible (sizing, contract length) Tampa Electric Company 35 MW EnerNOC DR Customer Customer satisfaction Fully outsourced
Alignment of Incentives Under a $ per kw arrangement, incentives align with the utility s interests (more so than under a $ per site approach) It is in the Aggregator s financial interest to: Minimize customer churn Maximize demand response capacity at a site Maintain a dynamic, reliable resource
Aggregators Skill Set Demand response aggregators have a very different set of core competencies than grid operators and/or utilities providing outsourced demand response and energy efficiency solutions is our only business! Aggregators already have made investments in: Infrastructure (software, NOC) Sales and Marketing (inside and outside sales) Curtailment expertise (certified energy managers, vertical-specific knowledge) R&D (next-generation technologies, e.g. PowerTalk)
Investments in Technology Platform
Event Management Tools (1) EnerNOC tracks customer notifications, monitors event performance, and records all customers interactions through the Action Call Center (3) Utilities can monitor real-time, aggregate portfolio performance using EnerNOC s Demand Response Dashboard (4) Within 48 hours, Utilities receive detailed Post-Event Performance Report (2) Customers and Utilities can view facility-specific, real-time energy reduction efforts through web-based PowerTrak software 18
High-Growth, Scalable Network As of May 2009, more than 5000 3,000 MW Under Management 2,000 Demand Response Customers 3000 5,000 C&I Sites Under Management Customer Sites 4000 3000 2000 MW Under Management Sites Under Management 2500 2000 1500 1000 MW Under Management 1000 500 0 0 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 5/6 2005 2006 2007 2008 2009
The End User
C&I Customers of all types
Diversity of Customer Types
Value Proposition to End Users New revenue stream Reduced energy costs No cost or risk PR benefits Financially, DR makes a lot of sense. As energy costs go up, we need to maintain control and reduce our reliance on increasing amounts of electricity. - Jake Nixon, Mission Produce, Oxnard, CA
Perhaps most important
Site Enablement
Demand Response actions Curtailment Self-Generation
Demand Response actions Automatic Manual
Next-Generation Services
Monitoring-Based Commissioning (MBCx) Technology-based Commissioning process to solve key problems Deployment: Remote capture of BMS and Meter data (no boots or additional sensors) Persistent: Algorithms run every night Deliverables: monthly scorecards to integrate EE into workflow processes $ savings, energy savings, and GHG reductions for each recommendation Cost: Priced on a shared-savings models with good ROI (for large buildings) Customer Energy Scorecard & Recommendations Your Facilities Your Recommendations 29
MBCx is like Retro-Commissioning Every Night Impact of Monitoring-Based Commissioning on Building Consumption: 125% 120% Recomissioning (without MBCx) Normalized Energy Usage 115% 110% 105% 100% 95% Traditional, periodic recomissioning Monitoring-Based Comissioning (MBCx) Lost Opportunity 90% Time
Presence Enabled Smart Grid
David Brewster 617.692.2002 dbrewster@enernoc.com