Advanced Metering Infrastructure (AMI) Project Update

Mark Heintzelman

June 2010

AMI System RequirementsDemonstrated Ability @ Scale

• Retrieve hourly energy consumption from all (480,000) endpoints• Two-way communications to reset displayed Peak Demand or kW,

on command• Two-way communications to support direct load control

– Meet NIST – Critical Infrastructure Protection requirements• Provide outage management process enhancements• Reduce operational costs related to meter reading and customer

movement processes

AMI Phased Approach

• Phase I – Test the AMI technology – 2004 -2008– Test hourly data retrieval– Pilot Data Management & time variant pricing– Develop a business case

• Phase II – AMI Infrastructure Installation 2009- 2011– Strategic Sourcing– Regulatory Filing– Infrastructure deployment– O&M cost reduction

• Phase III – AMI Full Implementation 2012– Full data and system integration– System optimization– Additional Systems

Deployment Shcedule

Two-Way Automated Communications System (TWACS) Overview

Substation Control Equipment

TWACS Modules

• Meter applications– New Solid-state Meters with factory installed TWACS modules

– Residential - Landis & Gyr

– Commercial – General Electric

• Transponder Switch (outdoor)– AC Cycling/Irrigation Load Control

• Control circuit

– 30 Amp Direct • water heater/pool pump

TWACS PLC Communications

OutboundOutboundCommunication From Communication From

Distribution SubstationDistribution Substation

InboundInboundCommunication From Communication From TWACS ModuleTWACS Module

11 33 55 77

4422 66 88

Inbound BitInbound Bit

Outbound BitOutbound Bit

TTAA TTBB

VV11

VV22

Communications Schedule/Shift

text

2400

0600

1200

0200

0400

0800

10001400

1600

2000

2200

0330

0830

1130

1930

0010

0300

Start Daily/Billing Read

Billing Demand Reset

1st Hourly Block

3rd Hourly Block

Begin AC Cycling

AC Cycling Conformation

Retry/Problem Resolution

10:00 PM

2:00 PM

4:00 PM

6:00 PM1800

7:30 PM

2nd Hourly Block

Midnight Read

(7:00 PM -3:00 AM)

(11:00 AM 7:00 PM)

(3:00 AM -11:00 AM)

5:00 PM Start EW Peak

1:00 PM Start TOD Peak

7:00 AM Start TOD Mid Peak

9:00 PM Stop EW & TOD Peak

Typical TWACS Daily Operations 6,000 Customer Buss Section @ IPCO

Daily and 1st hourly do overlap if

issues occur, when this

happens 1st hourly is delayed.

System Voltage Read Desired

System Voltage Read

System Voltage Read

Actual Voltage Read (7:00 PM – 9:00 PM Peak)

(1:00 PM – 7:00 PM Peak)

Setup prior to determining Peak time periods

Residential Meter Display

• Scrolling (3) – Display Check - Peak Demand - kWh

• “PD” Peak-Demand OO . OO (08.12 or 20.11 or 00.95)

• Power Indicator/disc emulator (forward > Reverse <)

• Com Indicator (not used)

• Nominal Voltage (on)

AMI Data Flow

Data Display

Deployment Status

• 60+ Sub Stations Complete

• 260,000 meters exchanged – 750-1,000 per day

• MDMS IEE 5.3 in production

• On Schedule

• On Budget

• PUC Actions

– Certificate of Necessity & Convenience (Dec 2008)

– Recovery on investment (June 2009 – June 2012)

• DOE Stimulus Grant $47 M for Phase III

TWACS Outage Management - Trace

Ping

Response Displayed

Added Value

• Billing Error & High Bill complaint reductions• Customer Satisfaction

• Access issues, Digital meters, Data availability - Web• Enhance DSM (Green)• Enable Time Variant Rates (Green)• Enhanced C2T/GIS/OMS data• Reduction In Vehicle Use (Green)• Distribution Control? – Capacitors?• System Monitoring & Reporting/Data Acquisition

• Voltage, Load, PQ, Energy use, Outage, Electrical location

Data Volume

• Monthly reading of 500,000 meters X 12 months = 6,000,000 meter reads annually

• 250,000 AMI meters X 26 reads daily = 6,500,000 meter reads daily (24 hourly reads + daily kWh & kW reads = 26 reads daily)

• 500,000 AMI meters X 26 reads daily = 13,000,000 meter reads daily

• 13,000,000 daily reads X 365 = 4,745,000,000 meter reads annually

• Additional reads (future)– Voltage

– Power Quality

– Transponder cycle counts

• Meter Data Management System (MDMS) – Bleeding edge

Hard AMI Cost Reductions(the business case)

• 99% of Meter Reading Costs ($5.5M annually)

• 90% of Customer Movement Costs ($1.5M annually)

• Reduction in outage scoping & restoration conformation costs ($363k annually)

Approximate Cost

• 3 Years• $74,000,000

– $1.2M - IT – Systems & Interfaces

– $13.3M - 142 Station + growth & Communications Equipment Installed

– $55.5M – 500,000 Meters Exchanged or installed

– 10% contingency and loading

• $126 to $140 per endpoint

AMI Phase III (2012)

• Implementation of “Mass” Time-Variant-Rates, this will require additional investment (CIS) (stimulus)

• DSM Implementation (stimulus)– Direct load control – Indirect load reduction – price signals - TOU– Data analysis

• Other Value Added Services (stimulus)– Monitoring– Reporting– Control

Frequency Spectrum Exposure Hazard

1 Hz - 3 MHz 3 MHz - 2000 MHz 2000 MHz - 750 THz 750 THz - 3000 EHz

No recognized exposure hazardPotential hazard - prolonged exposure at extremely high

power levelsHazards related to prolonged

exposure at high power levels Extreme exposure hazards

Health risks generally increase with the signal frequency, strength of the signal and exposure duration.

Questions