March 30, 2004 CONFIDENTIAL AMR Benefits and Costs – Benchmarks and Examples Presentation at CB Associates Seminar Sanjoy Chatterjee [email protected]

March 30, 2004

CONFIDENTIAL

AMR Benefits and Costs – Benchmarks and ExamplesPresentation at CB Associates Seminar

Sanjoy [email protected](646) 732-2493

2Confidential –- March 30th, 2004

Today’s Discussion

• Types of business cases•Operational•Demand Response (e.g., CA)

• Benefits – Industry Experience and Benchmarks

• Cost Categories


Operational Business Case

Utility Operational

Savings

$ per meter per month

AMI Capital Investment

AMI Operations & Maintenance

NET SHAREHOLDER

BENEFITS

CostsBenefits


Demand Response Business Case

Utility Operational

Savings

$ per customer per month

Demand Response Savings

AMI Capital Investment

AMI Operations & Maintenance

NET RATEPAYER BENEFITS

CostsBenefits


Operational Benefits Beyond On-Cycle Meter Reading


Daily Usage Screen: Off-Cycle Reads and Customer Service


Revenue Mgmt: Unauthorized Usage Screens


Revenue Mgmt: Diversion Detection at KCPL


Other Revenue Management and Meter Operations

Discovery of electrical problems in field:•UI found significant increased revenue during the installation phase

Improved meter accuracy leads to revenue recovery•UE estimated meter accuracy improvement of 0.7% - older meter population than average

•KC Retrofit center tested 5000 random meters before and after retrofit process and found an average improvement in accuracy of 0.25%

•3-digit demand registration improvement

Identification of dead meters earlier leads to revenue recovery•KCPL has ~0.1% of its meters die in field every year & it takes 4 months to identify and replace

Reduce number of meters in inventory•Reduction in inventory costs•Less training•Reduction in meter repairs, manpower, and parts


T&D Operations: Real Time Read Screen


1 - Lights Out Call

2 - Query Meter

3 - Meter re

ports ON

4 - Assisted to check breakers

Customer CSR

Meter

Outage Management: Instrumenting the Distribution Network


Outage Restoration

Outage FlagOutage

Information System

WMS Dispatch

Trouble Crew

MeterRestoration Flag

NO

YESAuto-dialer

OutageEvent


Transformer Load Monitoring

Transformer LoadDuration Curve

+

+


Industry Benchmarks

Meter Reading• Labor• Supervision• Vehicles• Injuries• Equip and• new meters

UtilityOperational

Savings

Billing & Customer Service

• Call center• Re-reads• Cash flow

Revenue Protection

$0.70$0.26

$0.29

$2.87

Source: North American Advanced Metering AMR, Frost & Sullivan

Off-Cycle Reads

• Move-in/move-out

• Re-reads

Meter Operations

• Avoided testing

• Avoided replacement

• Accuracy

$0.56

$0.60

Outage Mgmt• Singe No-

Lights Trips• Restoration

$0.36

Gross savings in $ per meter per month


Demand Response Benefits


The Goal of Dynamic Pricing

Avoid the need to construct additional peaking power plants or to make expensive wholesale power purchases during price spikes

Top 1% of the hours in PJM

• Top 10% of demand

• Top 90% of prices


California Statewide Pricing Pilot – Background

•California joint agencies demand response proceeding–PUC, Energy Commission, and Power Authority –Rulemaking 02-06-001, begun June 2002–Establishing state policies for advanced metering and demand response

•Goal: avoid a repeat of the 2001 Energy Crisis

-4.0%

-2.0%

0.0%

2.0%

4.0%

6.0%

8.0%

10.0%

12.0%

14.0%

16.0%

2004 2005 2006 2007 2008 2009 2010

Year

Ope

ratin

g R

eser

ve

Projected Operating Reserve (1-in-2)

Projected Operating Reserve (1-in-10)

Target Operating Reserve

Stage 2 Emergency- Called whenreserves fall below 5%

Stage 3 Emergency- Called whenreserves fall below 1.5%

Source: Mike Messenger, California Energy Commission

Projected Reserve Margins

Rolling Blackouts


California Rulemaking Progress

• Three subgroups– WG1: Policy– WG2: Large customer programs (>200 kW)– WG3: Small commercial and residential programs

• Decisions to date – Mar 2003: Adopted statewide goal of meeting 5% of peak

demand via dynamic pricing by 2007– Jun 2003: Established regular dynamic pricing tariffs for

large customers– Jun 2003: Ordered implementation of Statewide Pricing

Pilot– Nov 2003: Ordered development of business case

methodology, including utility filings due March 31 regarding 2004 activities to meet 2007 goal


Statewide Pricing Pilot Overview

• Statewide– Pacific Gas & Electric, San Diego Gas & Electric, and Southern California

Edison– Sample of 2,500 customers statistically representative of the entire state– Residential and small commercial customers

• Goals– Measure peak demand reductions– Measure total consumption reductions– Assess customer preferences via participant experiences and market

surveys• Customers put in three primary treatment groups

– Time-of-Use (TOU)• Peak (2-7 pm weekdays) and off-peak• Peak to off-peak price ratio about 2:1

– Critical Peak Pricing-Fixed (CPP-F)• Peak (2-7 pm weekdays) and off-peak• Much higher price – about 5x higher – during critical peak period (2-7

pm) on up to 15 days a year, with day-ahead notification– Critical Peak Pricing-Variable (CPP-V)

• Three differences from CPP-F– Critical peak period varies from 1 to 5 hours from 2-7 pm– Notification varies from day ahead to 4 hours ahead– All customers have smart thermostat programmed for automated

response


Residential Dynamic Pricing Results: Price Elasticity

–Fifty-six analyses and projects in the past 25 years–Average of -0.30 own-price elasticity

• Equals 30% usage reduction for 100% price increase (off-peak to peak)–California’s pilot providing one more data point

Residential Own-Price Elasticities Recorded in Experiments/Programs

More

peak d

em

an

d

red

uctio

n

-0.9

-0.8

-0.7

-0.6

-0.5

-0.4

-0.3

-0.2

-0.1

0

1975 1980 1985 1990 1995 2000 2005

Average result =-0.30

California data

U.S./international data

Source: King and Chatterjee, Public Utilities Fortnightly, July 1, 2003


Residential Dynamic Pricing Results: Peak Demand Reduction

–Results of 30 residential time-of-use and critical peak pricing programs–Results expressed as a percentage of customer’s total demand under non-time-based pricing

0%

10%

20%

30%

40%

50%

60%

70%

1975 1980 1985 1990 1995 2000 2005

Average reduction 24%

More

peak d

em

an

d

red

ucti

on


Statewide Pricing Pilot Results - Residential•Rates went into effect July 1, 2003•12 events called during summer 2003•Analysis by Charles River Associates (contractor to joint utilities) completed January 16, 2004 (draft report; final data may differ)

Performance Measure Average from the Literature

California SPP Result

Price elasticity (mean own price) -0.30 CPP-F: -0.27CPP-V: -0.53TOU: -0.24

Peak demand reduction – TOU 20% 24%

Peak demand reduction – CPP without automated response

24% 20%

Peak demand reduction – CPP with automated response

44% 49%

Total usage reduction (conservation effect) 4% CPP-F: 6%CPP-V: 28%TOU: 9%


Meters/Modules

Field Logistics

Network Equipment

Network Installation

IT Interface Design

Total Upfront Capital

System Operations

3rd Party Comm

Network Ops

Network Maintenance

Endpoint Replacement

Other Utility Costs

TCO

Meters and modules based on retrofit capabilities

Installation, retrofit, cross-dock

Network equipment and field installation, including site preparation (where needed)

Utility IT team to build interfaces to different deployment systems

Operating data collection systems, data management, process management, manual reads (where needed)Leased lines, wireless, telco, other backhaul

Engineers, Technicians, Site leases, energy costs

Maintenance, repairs and upgrades

Replacement of failed meters and modules in the field

Utility in-house project team, overhead, facilities, vehicles, G&A

*Sales taxes and property and use taxes ignored

Total Cost of Ownership (TCO) Categories*

Documents

March 30, 2004 CONFIDENTIAL AMR Benefits and Costs – Benchmarks and Examples Presentation at CB Associates Seminar Sanjoy Chatterjee [email protected]