APSC Workshop on DR and AMI

OVERVIEW OF ISSUESDR AND AMI HELP SOLVEDr. Eric WoychikExecutive Consultant, Strategy Integration, LLC APSC Workshop on DR and AMI

Overview Aim: To define the needs and opportunities Demand Response and Automated Metering Infrastructure are best applied to • Demand Response vs. Energy Efficiency • Super-peak needs and Summer Heat Waves • Define the resource types • Displace Combustion Turbines & Ramping Capacity • Selected Resources: G + T + D + env. mitigation

Demand Response (DR) vs. Energy Efficiency (EE) • DR is generally more available during the peak and super peak periods; provides capacity deferral for select hours • May be automatic, or dispatchable on short notice • EE is generally provided over a longer duration, to provide energy reduction • Is not generally flexible, but is fixed in its application • Permanent DR is something in between, providing capacity reductions on a constant basis • Managed, such as to optimize facility demand reduction • May be relatively fixed, such as “ice storage” • DR over a duration can also help save energy • DR and EE can be great compliments when integrated

What is Demand Response? • Interruptible load (e.g., by industrial customers) • Dispatchable, direct load control (e.g., AC or irrigation) • Automatic demand response; smart thermostat or control • Price response, on-call, manually activated and/or preset • Thermostat operation (e.g., temperature set-back) • Permanent demand response; managed with controls • Manually or automatically triggered load reductions (e.g., lighting controls)

Electricity peak may be 1 PM until 8 PM, summer months (June and September) – so just 87 days or 610 hours Super-peak is likely 2 PM to 8 PM, during the 16 hottest days of the year, about 100 hours or less (about 1%) Electricity generation capacity is maximum Transmission and power flows are maximum Air conditioning (AC) is used to the maximum AC loads increase system peak & reduce load factor Summer heat waves are a major driver of super-peak NOAA, NASA, NERC, and IGCC, suggest climate change Average and peak temperatures appear to be increasing Super-Peak Needs and Summer Heat Waves

Basic Electricity Resource Types Purchases -- on the market …at a cost Reserves -- available for contingencies and peaks Peaking – ramping or load following High capacity factor load following (CF LF) Intermediate (load factor) Baseload – e.g., coal and nuclear Transmission (may be ignored in some least cost plans) Demand Response (DR) and Energy Efficiency (EE)

Purchases Reserves Peaking Intermediate High CF LF Base Entergy Arkansas Electricity Peak & Resources Entergy System Strategic Supply Resource Plan, Plan Description, 2006

Peak Demand, Load Factor, and Retirements • SWEPCO peak demand (August 16) record 4,910 MW • Entergy Arkansas peak demand is about 5,600 MW • Load factor in AR is declining with increased use of AC • Decision to retire an existing plant • Compare the forward cost of the existing unit with the forward cost of alternatives – this is oversimplified • Many older gas and oil-fired units run at low capacity factors to serve the peaking and reserve roles • Decision to add a new coal plant, is related to older units that will shift roles to serve peaking and reserves • Add new coal as baseload then use existing old plants?

Displace Combustion Turbine & Ramping Capacity • Recent AEP-SWEPCO CT proposal for 332 MW was $102.8 million (for used units at 50% of new). • Each 80 MW CT must operate at 75% of capacity for NOx • Can operate from 52MW to 83MW and 104MW to 332MW • Ramping capacity is to meet loads rapidly, typically between hours to avoid voltage lags & grid requirements • Baseload and intermediate plants ramp slowly • Peaking units ramp quickly (but many older units are used) • More renewables (must-take power); more ramping needs • Criteria for peaking/ramping capacity are lowest life-cycle cost, reliable, flexible, and environmentally responsible

Ramping and Load Following Resources • System faces large daily load swings that require ramping and load following resources • Combined Cycle Gas Turbines (CCGTs) are typically desired for operational flexibility and to limit exposure to high purchase power prices • Replace current 35+ year old conventional gas plants? • Utilities need resources in transmission critical regions • Reduce production costs at minimum run levels • Where Reliability Must Run (RMR) units are needed • For ramping and load following

Selected Resources: G + T + D + env. mitigation • DR and AMI can reduce or fully defer the capital and operating costs for system expansion: • Generation • Transmission • Distribution • Environmental mitigation • Transmission deferral – Rocky Mountain Power & NEISO • Distribution deferral – Commonwealth Edison & PG&E • Environmental mitigation – preferred loading order (CA)

Basic Ways DR/AMI Resolves System Needs • Reduce overall system loads -- the EE effect • Reduce system peak and locational loads – the DR effect • Reduce existing and new generation needs • Reduce existing and new transmission needs • Reduce existing and new distribution costs… • Reduce environmental mitigation costs • DR/AMI can be installed when supply-side are more difficult • AMI provides automated meter reading, remote connect/disconnect, communications to the home, and may enable building automation

APSC Workshop on DR and AMI