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 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…