advanced metering infrastructure (ami) project update mark heintzelman june 2010
TRANSCRIPT
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