REGULATORY MECHANISMS TO ENCOURAGE DR/AMI Dr. Eric Woychik Executive Consultant, Strategy Integration, LLC APSC Workshop on DR and AMI

Overview DR/EE offerings Some limitations due to regulatory process Cost recovery and rate base Loading order and preference policies Conditions precedent How DR/EE May Be Considered

DR/EE Options Technology (equipment) for utility implementation of DR  Digital Control Devices (e.g. for AC cycling)  Smart Thermostats (e.g., White-Rogers, simple to complex)  Two-way communications, e.g. Gulf Power TOU Pricing  Energy Management System (EMS) applications  TOU-based WattSpot web-based gateway services TOU pricing – like Gulf Power Dispatchable DR –direct load control “Rate-guard” service (price-triggered response from SPP) Environmental dispatch (“soft dispatchable DR) “Turn-Key” DR handing of off management & control Fully-outsourced DR program

Limitations Due to Regulatory Process Bifurcated proceedings => separation of goals and responsibilities Short-term funding (e.g., for GRC funding of DR/EE) Lack of resource integration and full consideration of long- term contracts RTO/ISO responsibilities vs. state responsibilities  RTOs/ISOs and utilities are about reliability, balancing needs, and ramping – more focused on capacity needs  State planning proceedings focus more on long-term supply- demand balance, so may ignore ramping & capacity needs

Cost Recovery and Rate Base Traditional cost recovery of expense and capital costs  In what proceeding, covering what time frame, for DR/EE  Longer-term treatment recognizes long-term benefits Rate-base treatment  DR/EE installation & capital costs are traditionally rate-based  With 3 rd party contracting DR/EE assets can still be owned by the utility  Incentive Rate-or-Return (ROR) may be appropriate Financial implications for utilities  Rate-base reductions for long-term DR/EE contracts lower investment levels for G + T + D + environmental mitigation

Loading Order or Resource Preference Policies Benefits of changing the presumed preference for traditional supply–side resources  Recognizes G + T + D + environmental + market mitigation  Recognizes DR/EE are environmentally beneficial  CA policy recognizes these benefits & difficulty of detailed cost-effectiveness given multiple benefits Has relaxed need for formal cost-effectiveness if competitive RFP procurement process is used  NC approach requires a specific amount of DR/EE… Environmental adders – create preference for DR/EE Cost-effectiveness with all benefits defined – similar result

North Carolina Utilities Commission Orders Re. Proposed Coal Plants & Green Power One 800 MW state-of-the art coal plant approved Duke commitment to invest 1% of annual electricity sales revenue in energy efficiency and demand-side programs  EE/DR to back out MW-for-MW retired coal plants Must account for actual load reductions realized  EE/DR need is contingent on system reliability need  Collaborative workshops to commence Green Power authorized if $25,000 or more of Renewagle Energy Credits (RECs) are purchased and applied to renewable generation

Conditions Precedent to New Resources Conditions imposed on ComEd’s AMI rollout – WattSpot  Make DR/EE cost effective by offering a menu (scope) Ensure cost effectiveness and ratepayer benefits  Require specific results (e.g., with Standard Practice Tests) Locational Resource Adequacy Requirement Risk allocation using 3 rd party contracts  Pay-for-Performance  Rigorous Measurement & Performance

3 rd Party Risk with Fully Outsourced DR DR program risks include the following:  Marketing, customer acquisition, and customer churn  Hardware and equipment (warranty)  Software upgrades and customer call center  Operations and maintenance  Measurement & verification  Performance – dispatchable MWs when called upon  Stranded investment (if not used) Customers and Utilities Can Be Free of These Risks  Utah, ISONE, SDG&E, and PNM examples

How DR/EE May be Considered N. Carolina If at least one half of the 1% of annual electricity sales revenue was allocated to DR  At $.05/kWh this may amount to about $1.3 B annually.  To ensure performance we recommend performance-based DR with rigorous Measurement & Verification (M&V) to account for actual load reductions realized  This may depend on system reliability need and on use of a reference costs for capacity ($/kW-year) DR may qualify for Green Power RECs if M&V shows savings to reduce emissions, comparable to renewables?

How DR/EE May be Considered in Arkansas Use competitive RFP procurement process Ask for specific DR or DR/EE services to enable apples- to-apples comparisons Consider not just new baseload resources but retirement of old, inefficient, polluting facilities held for reserves Integrate benefits/costs of G + T + D + environmental + market price/mitigation + hedging/insurance/portfolio Design a menu to provide more DR/EE services, for more benefits, customer acceptance, and customer choice Place risks for customer acquisition, hardware, installation, performance, & financing on DR/EE providers

Fully Examine Plant Expansion and Deferral Define the menu of DR/EE needed to meet needs at least cost, taking account the shifts in uses of generation Compare reliability, ensure outage rates are comparable, and define both T&D deferral and environmental benefits Define lowest life-cycle cost peaking capacity, including flexibility, market price impact, & market power mitigation Consider the flexibility benefits with DR/EE during the power plant planning and construction cycles  Plant is lumpy, may be partially stranded, requires T&D  DR/EE is not lumpy, can be increased/decreased based on locational needs, does not require T&D Compare the hedging/insurance benefits & costs of both

Discussion… Follow-Up Suggested…