Demand Response and Transmission Planning

1. Demand Response and Transmission Planning February 16th, 2009Prepared for the Southwest Area Transmission (SWAT) Planning Group

2. Proposed Agenda EnerNOC Background DR Drivers Relevant Experience DR as a Transmission Planning Resource Discussion and Questions

3. Who is EnerNOC?

4. EnerNOC’s Demand Response Footprint Founded in 2001, EnerNOC is the largest demand response provider focused exclusively on the commercial and industrial sector. PROGRAMS IN RESTRUCTURED MARKETS ISO-New England (ISO-NE) PJM Interconnection (PJM) New York ISO (NYISO) Ontario Power Authority (OPA) Electric Reliability Council of Texas (ERCOT)

5. Energy Network Operations Centers Our Network Operations Centers (NOCs) feature automated DR capabilities to ensure that curtailment happens quickly, efficiently, and consistently for our utility customers.

6. 0% 50% 100% 150% EnerNOC Utility/ISO Performance through Portfolio Management Customer 1 Customer 2 Customer 3 Customer 4 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% RISK 100% RISK 0% RISK

7. Consistent Delivery of Capacity • Key Drivers • Our technology platform enables automated dispatch of multiple events simultaneously, with real-time visibility into performance. • We monitor end-use loads continuously to ensure capacity availability. • We thoroughly test each site prior to event dispatch, including acceptance tests and notification tests. • We are experts at building a “portfolio” that ensures reliable delivery.

8. DR Drivers

9. Drivers for Demand-Side Resource in Planning • FERC Order 719 • Demand resources treated comparably to generation for the provision of energy, capacity and ancillary services • Smart Grid/Technology • Integrating information and communications from transmission operator, generator to consumer. • Integrating technologies (EPRI) • Economic Concerns • Environmental Concerns

10. Types of Demand Response • Emergency-Triggered • Maintain Operating Reserve Minimums • Local or System Transmission Outages • High Peak Demand • Capacity Resource (Counts for PRM) • Economically-Triggered • Wholesale Market Prices • Heat-Rate Averages • Energy & Ancillary Service • Hybrid • Either emergency or economically triggered

11. Relevant Experience

12. EnerNOC Experience with Quick-Start DR EnerNOC has extensive experience managing quick-start programs, including regions where demand response can qualify as reserves. 11

13. 2. Regions where DR Provides Reserves = Full program, robust participation = Full program, limited participation Demand response acts as a reserves resource in both regulated and deregulated markets. Focus on Restructured Markets

14. Interruptible tariffs throughout U.S., including utility in Midwest, Southeast, etc. • Thermostat, pump, and heating cycling programs (residential) throughout the U.S. Source: NERC DR Report: Assessments & Trends DR Ancillary Services in Electrical Regions

15. PJM’s Synchronized Reserves Market PJM allows DR to provide ancillary services, including both synchronized reserves and regulation.

16. 3. PNM’s Peak Saver Program An innovative demand response program wherein commercial and industrial customer’s usage is automatically reduced.

17. PNM’s Peak Saver Program A wide-variety of customer types participate in Peak Saver, spanning PNM’s service territory and various industries. Geographical Distribution of Sites • Portfolio nomination is updated at least monthly; September 2009 nomination was16.0 MW • 50 sites are fully automated remote-control response customers; 15 are manual response • Majority of customers participate via curtailment; small percentage utilize back up generation • Industries with the most sites participating include light industrial, commercial, government, and education

18. Salt River Project In Salt River Project’s PowerPartner demand response program for commercial and industrial customers, 50% of the capacity is available within 10 minutes and the rest is available within 30 minutes “We selected EnerNOC as our commercial/industrial demand response provider for a variety of reasons, including its extensive experience working with utilities, its strong track record in ensuring customer satisfaction, and the technology it has created to make demand response easy for participating customers and reliable for us.” Debbie Kimberly, Manager Energy Efficiency and Policy Analysis Program PeriodYear - round Program Hours5 AM – 9 PM on weekdays 7 AM – 7 PM on weekends & holidays Event Notification10 minutes; 30 minutes Event Duration1 - 4 hours Demand Response StrategiesCurtailment and permitted generation Response MethodAutomatic and manual

19. Auto DR Case Study – Packaged Ice Producer • Event Start • EnerNOC remotely curtails ice-making equipment and blast freezer compressors • 10 minute lead safely clears product from equipment Curtailment: Remote curtailment of blast freezer compressors and ice-making equipment • Event Notification • EnerNOC flashes strobe lights and sends phone and email notification to facility managers at 2 locations • Facility managers confirm participation • Event End • EnerNOC remotely restores power to all equipment • Strobe lights stop and courtesy phone call confirms end of event Nomination 1,500 kW Event Window 18

20. PNM Peak Saver Performance The Peak Saver program provides reliable load reductions to PNM’s system. Peak Saver Portfolio Event Performance 2009 Performance • 7 events in 2009, for a total of 26 hours • 6 events in 2008, for a total of 21 hours • Average event length is 3.6 hours • Average event performance is 102%

21. 4. Peak Saver as a Reserves Resource The characteristics of the Peak Saver Program are comparable to other markets where DR qualifies as a reserves resource. These include: • Metering • EnerNOC maintains 1-minute meters at all participating Peak Saver facilities; average reading latency is <5 minutes, <<5 minutes with EnerNOC’s new PowerTalk technology • Network specialists monitor meter connectivity, and immediately address issue remotely (if possible) or dispatch a local site technician (as needed) • Operators monitor near real time data to manage DR events; if customer underperforming, a “coaching” call is made • Resource Reliability • Since 2007, the PNM Peak Saver program has been dispatched 13 times for a total of 47 hours • Average performance is 102% with a standard deviation of 11% • Performance at 10-minute mark has been similarly consistent • Resource is not “all or nothing”, like a quick-start supply-side resource • Measurement and verification: several M&V approaches are reasonable; EnerNOC is open to working with the SRSG

22. DR as a Transmission Planning Resource

23. 4. DR as a Transmission Planning Resource • DR as part of utility resource portfolio may: • Reduce transmission constraints in local areas • May affect sizing or upgrading of transmission corridors • Reduce need for new peaking resources, and, therefore: • Must be included in an IRP process • ACC is including EE targets, which include DR, significant reductions in consumption by 2020 • Timing concerns • Need some kind of historical basis; include trend analysis

24. DR Participation Considerations • Metering • Requirement Based Upon Service Provided • Measurement • Baseline Methodology • Data Submission • Payment for Performance • Failure to Perform • Depends on type of service provided

25. Thank you! 5. Discussion and Questions

26. EnerNOC Contact Information EnerNOC thanks the SWAT for the opportunity to present at today’s meeting. Please feel free to contact us at any time! Dan KozikowskiManager of DR Program Operationsdkozikowski@enernoc.como: 312.955.5044 | m: 917.647.5849 Stina BrockProgram Operations Manager, DRkbrock@enernoc.como: 415.343.9505 | m: 206.310.6254 David Meyers Director of Western US Business Developmentdmeyers@enernoc.com m: 415.722.2261 Mona Tierney-Lloyd Sr. Manager, Western Regulatory Affairs, mtierney-lloyd@enernoc.com m: 415.238.3788