APSC Workshop on DR and AMI

REGULATORY MECHANISMS TO ENCOURAGE DR/AMIDr. Eric WoychikExecutive 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 3rd 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 3rd party contracts • Pay-for-Performance • Rigorous Measurement & Performance

3rd 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…

APSC Workshop on DR and AMI