Smart Grid & Demand Response Creating a shared resource

1. Smart Grid & Demand ResponseCreating a shared resource PNDRP Feb.23, 2012 Lee Hall, BPA Smart Grid Program Manager

2. Building DR knowledge, experience and scale > $10 M Current Concept Planning still in progress BPA DR Portfolio MW Scale Annual Cost 250+ MW potential 50-100 MW <10 MW potential <1 MW < $1M 2008-2009 1984-2008 2010-2012 2013-2015 2016 + • Individual projects designed to address a specific research or operational objective • Not continuous • Two residential and one commercial proof-of-concept pilot project projects • Developed marketing materials and evaluation approach • Additional residential pilots • Added commercial and industrial pilots • Largely focused on utility peak • Introduced wind integration and load increase testing • Larger scale (10s of MWs) • Shared/multiple use projects • Multiple acquisition methods • Initial cost allocation methodology • Joint utility/BPA dispatchability • Continue to scale larger based on evolving business needs • Refined funding and cost allocation Overview • Based on specific need or utility interest • Example: OPALCO submarine cable deferral in late ‘90s • Seattle City Light and LBNL • Kootenai Electric • Central Electric • 12 additional utilities • Joint project with TI (Ecofys) • Many additional partners – commercial, academic, etc. • 5-6 additional projects • Blend of customer types • Utility as aggregator and commercial providers • Portfolio of varied DR resources • Multiple utility and commercial partners Utilities / Partners • Manual event dispatch/notification • Focused on peak load reduction • Commercial building management systems • Residential water heater and HVAC • Curtailment only • Added thermal storage, in-home displays, irrigation, cold storage and industrial processes • Curtailment, load increase, HLH to LLH load shift • Portfolio of projects rather than specific sectors or technologies • Some focus on commercial and industrial loads • Testing routine dispatchability • More sophisticated technologies • Likely to span all sectors • Ongoing testing of emerging technologies Sectors / Technology • Successful projects ensured reliability during deferral • Technical feasibility • Programmatic lessons • Marketing refinement • Open Auto DR success • Technical feasibility and data • Programmatic lessons • Scalability assessment • Testing dispatch based on wind and balancing needs • Multiple/shared use feasibility • Delivery of MWs for BPA needs • Significant regional DR learning • Test commercial arrangements • Program scaled to address multiple regional needs • Ongoing evolution Benefits / Outcome Emerging Drivers Transmission / distribution deferral 6th Power Plan encourages pilots Overgeneration TRM price signals – utility peak demand Balancing reserve constraints Economic opportunities

3. Brief history of DR in the PNW From 1992-1994, both Seattle City Light and Snohomish PUD operated residential direct load control pilot programs. The Seattle City Light program involved 410 residential participants, each of which received a one-time payment of $75 for allowing the utility to control the water heater up to 20 times per winter. In 1995, OPALCO formed a partnership with BPA called Energy Partners to control demand to help meek their peak. They had exceeded demand on an existing 34.5 kV submarine cable. In 2004, the Olympic Peninsula Project tested whether it was possible to decrease the stress on the electric grid by at times of peak demand by more actively engaging typically passive resources, in particular end-use loads and idle distributed generation. Seattle City Light partnered with BPA in a year-long demand response pilot which concluded with a report in March 2010. It tested automated demand response with pre-programmed control strategies in a local energy management control system.

4. Now evaluating multiple technologies for both reducing and increasing load • Electric Water Heaters (residential and commercial) • Cold Storage • HVAC (thermostats) • Industrial processes (and electric boilers) • Irrigation • Municipal water pumps • Battery storage • Building energy management systems • Space heating (thermal storage) • In home displays

5. Operational reserve and capacity constraints (1000s of MW) Wind integration: BPA faces significant balancing reserve demands due to Balancing Authority obligations to integrate over 3,500 MW of wind now, and likely over 6,000 MW in the next 2-3 years River management: BPA is at the limits of balancing reserves but must ensure sufficient margin to meet multiple use requirements of the FCRPS, including managing high wind/high water events Additional reserves are needed to ease supply constraints and operational demands on FCRPS assets during summer and winter peaks and large unit outages Opportunity to market FCRPS capacity freed up by DR Transmission expansion challenges Further renewable development is expected in the BPA BA, further affecting borrowing authority, over-supply, siting and reserve capacity challenges Opportunity to avoid or defer potentially contested and costly transmission infrastructure investments where non-wire DR solutions are a viable least-cost alternative and could help mitigate reserve capacity, debt, and stranded cost risks DR may be the only solution available if new lines cannot be built or face lengthy delays Economic impacts on utilities TRM creates incentives for customers to invest Additional potential benefits enhance value Utilities will invest in approaches that address their needs, but may not benefit the region and preference customers DR can help address major BPA and utility challenges Integration of renewables Potential utility economic benefit from DR Load shaping charge avoidance Deferred distribution system investments TRM demand charge avoidance 5

6. BPA has an evolving portfolio of DR pilots to assess BPA and regional needs

7. DR pilots – Update • Recently completed pilots with Central Electric Co-op and Kootenai – evaluation for Kootenai now available. • Seven active pilots and Ecofys thermal storage pilot, with 15 utilities. 1250 installed controllable water heaters. • Ecofys pilot successfully demonstrated ability to move load in response to BPA balancing signal without inconvenience to customers. Council is part of pilot team. • Preparing to support an 18-40 MW test in Port Angeles.

8. The City of Port Angeles :http://www.youtube.com/watch?v=vgyIM0_F2w4&feature=share

10. Energy Storage Pilot City of Port Angeles Cowlitz PUD City of Richland Forest Grove Consumers Power EPUD EWEB Lower Valley Energy Residential: ceramic heaters and water heaters Commercial & industrial: cold storage • Objectives: • Use controllable loads to help integrate variable renewables such as wind and solar • Implement commercial / industrial end- use storage projects. • Develop a demand response business case and marketing materials to support utilities Participants: Spirae, Steffes Corporation, EnerNOC, PNNL, Montana State, Renewable Northwest Project, Horizon Wind, Energy Northwest, Power and Conservation Council 10

11. Energy Storage Pilot

12. Energy Storage Pilot

13. Evolving DR Business Plan • Team presented the DR Business Plan proposal for BPA to the Agency Strategy Forum on October 27th. Work has included: • Cost effectiveness: completed assessment of demand response products and a representative 100 MW DR portfolio relative to alternative resources. • Infrastructure: With Strategy, Power and Transmission, continued assessment of potential systems /business process impact of demand response products both in the near-term (fy12-fy13) and longer term.

14. Evolving DR Business Plan • DR Executive Steering Committee: Launched an Executive Steering Committee composed of executives from Power, Transmission, Corporate Strategy and EE • Project identification: Working with utilities and utility groups who have expressed interest in near-term DR projects. • Outreach: Created preliminary plan and materials for outreach to utilities and utility groups to evaluate interest in DR, to be presented to DR Executive Steering Committee for refinement/approval during the coming month. AE advisory committee established.

15. We incorporated key lessons learned and advice we heard from established programs during the September 29th summit 15

16. We created a matrix of potential DR products to evaluate Explanation: • Created matrix of discrete products to facilitate internal and aggregator discussions • Proved valuable in explaining potential utility and BPA business needs • Does not represent opportunity to stack uses across multiple needs (e.g., utility peak avoidance and balancing) • No intent to purchase nine separate products • This matrix originated with the Agency needs assessment, revised over time 16

17. How funded? • Rates – avoided costs • Incentive payment • Capacity purchase • Asset purchase • Capital investment avoidance • Who benefits? • Utility • Aggregator • End use customer • BPA • Who purchases asset? • Utility • End use customer • Aggregator • BPA • Use? • Load shift • INC • DEC • Peak avoidance • Capacity • Reliability • Congestion • Load type? • Residential • Commercial • Irrigation • Industrial • Who manages program? • Utility • Aggregator • BPA • Who pays? • Utility • End use customer • Aggregator • BPA • Who dispatches? • Utility • Aggregator • End use customer • BPA • Notification Period? • Instant • <10 minutes • <30 minutes • <60 minutes • Forward market • Day-ahead Numerous questions to address the “shared use” issue

18. Outreach accomplishments Benchmarking trip to TVA Hosted an executive briefing with PJM, TVA and NE ISO Presented to Oregon Citizen Utility Board Presented to Pacific Center of Excellence for Clean Energy Work Taskforce Active participation with Smart Grid Consumer collaborative Collaborated on an AESP presentation with Milton-Freewater Responded to inquiries from Southern California Edison, New Brunswick Power, Hawaii Electric, California Governor’s office Presented to Clean Energy class at Evergreen State College What’s next: Next Generation Dynamic Load Management Industry Panel, March 8, San Diego Utility customer “Common Ground” presentation, March 28, Spokane 3rd DR Utility Cross-share, May 7, Portland

19. Moving forward Seeking utility, regional involvement and perspective Address multiple requirements – meet utility, regional and end-user needs Shared use of resources Test dispatchability Determine commercial arrangements – who pays for what? Increase size and scope of pilots, but not full scale yet – lesson from TVA

20. Resources available to you – BPA has active membership with: Advanced Load Control Alliance: http://www.alca.info/Contact/ Peak Load Management Alliance: http://www.peaklma.com/home.aspx Smart Grid Consumer Collaborative: http://smartgridcc.org/ Association of Energy Service Professionals: http://www.aesp.org/ BPA has a membership with E Source, which opens the doors for our utility customers to log on for research and answers to questions. http://www.esource.com/ How can we help you?

21. Contact information Lee Hall, BPA Smart Grid Program Manager, 503-230-5189, ljhall@bpa.gov Katie Pruder-Scruggs, SG Outreach Coordinator, 503-230-3111, kpruder@bpa.gov For more information: BPA SG and DR website: http://www.bpa.gov/Energy/N/Smart_Grid-Demand_Response/index.cfm PNNL: www.pnl.gov DOE OE: www.oe.energy.gov DOE Smart Grid: www.smartgrid.gov BPA wind site: www.bpa.gov/corporate.WindPower