Demand Management from an Aggregator's Perspective David Brewster, - PowerPoint PPT Presentation

Demand Management from an Aggregator's Perspective David Brewster, President May 21, 2009

Today’s Energy Challenges

Unprecedented Challenges Higher Increased Renewable Demand Costs Energy

Fall Summer 10% of Costs for 1% of the Time Spring Annual Energy Demand Winter 100% 90% 75% 50% 25%

Demand Response is the Solution Reliable Dispatchable 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

DEMAND RESPONSE AGGREGATOR Revenue Share Arrangement GRID OPERATOR/ UTILITY

Why Aggregation? 50 MW • More reliable resource performance • Smaller customers can participate vs. • Idiosyncratic / variable loads can be matched with others in the portfolio 300 75 kW kW 75 kW 75 kW • Risk-free participation 75 kW 1 MW 75 kW 75 kW 1 MW 250 kW 75 kW 75 kW 75 kW 5 MW 300 1 MW 300 kW 75 kW kW 1 MW 300 75 kW 75 kW 300 1 MW kW 75 kW kW 75 kW 200 75 kW 75 kW 300 kW kW 75 kW 300 300 kW 400 kW 1 MW 1 MW 1 MW 75 kW kW 75 kW 75 kW

Managing Risk: DR Portfolio Management By aggregating resources into a single portfolio, the Customer 1 aggregator manages 100% of the risk associated Customer 2 with delivering a contracted amount of capacity. In Customer 3 this manner, both the grid operator/utility and end users are protected from under-performance. Customer 4 Customer 5 Aggregator Grid Operator/Utility Customer 6 Customer 7 Customer 8 Customer 9 Customer 10 Customer 11 Customer 12 Customer 13 0% 50% 100% 150% 0% 50% 100% 150% Customer 14 Avg Events Customer 15 2006 103 % 34 2007 106 % 120 Customer 16 2008 102 % 101 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 (3) Utilities can monitor real-time, aggregate portfolio performance (1) EnerNOC tracks customer notifications, monitors event performance, and using EnerNOC’s Demand Response Dashboard records all customers interactions through the Action Call Center (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 18

High-Growth, Scalable Network As of May 2009, more than 3,000 MW Under Management 5000 2,000 Demand Response Customers 3000 5,000 C&I Sites Under Management 4000 MW Under Management 2500 MW Under Management Customer Sites Sites Under Management 2000 3000 1500 2000 1000 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

Manual Demand Response actions Automatic

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 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% Traditional, periodic Lost recomissioning Opportunity 110% 105% 100% Monitoring-Based Comissioning (MBCx) 95% 90% Time

Presence Enabled Smart Grid

David Brewster 617.692.2002 dbrewster@enernoc.com