Request for Information
SCE’s Advanced Metering Infrastructure Program
Next Generation Metering System
December 2, 2005
Table of Contents
Background………………………………………………………………….. 3
RFI Objectives………………………………………………………………. 4
Vendor Engagement Approach……………………………………………… 4
RFI Responses……………………………………………………………….. 5
Contact Information………………………………………………….. 5
Response Schedule…………………………………………………… 5
RFI Questions & Response…………………………………….……. 6
Future Communications……………………………………………………. 6
Proprietary Information…………………………………………………….. 6
Product Endorsements……………………………………………………… 6
Disclaimer…………………………………………………………………… 6
APPENDIX………………………………………………………………… 8
B: Conceptual AMI System Functionality…………………………… 9
C: Specification E-100 SSM (Meter Requirements)…………………. 10
Page 2 of 32
Copyright © 2005 Southern California Edison
All rights reserved.
BACKGROUND
SCE, the utility, is separate from the other Edison International (EIX) Companies, which are not
regulated by the California Public Utilities Commission (“CPUC”). SCE is the largest subsidiary of Edison
International and has over 110 years of experience in the transmission and distribution of electricity. SCE is
California’s second largest investor-owned electric utility company supplying power to a population of over 11
million people, with over 4.3 million residential and business customers. Please visit the company web site at
www.sce.com for more detailed information. On the company home page under the “About SCE” tab, visitors
will also find a service area map depicting SCE’s service coverage area.
In 2004, the California Public Utilities Commission (CPUC) required that SCE and the other California
Investor Owned Utilities analyze and develop business cases surrounding “Advanced Metering Systems”
capable of supporting dynamic tariffs, facilitating operational and other cost reductions, and ultimately reducing
peak-energy demand through enhanced load control and demand response capabilities1. SCE evaluated the
available commercial solutions at the time, performed the required analysis, and found that the “best” full meter
deployment business case yielded a significantly negative net present value (NPV). SCE’s evaluation of the
available commercial technology solutions identified the need for more cost justified integrated system features
and capabilities that could deliver significantly more operational, cost, and customer benefits.
As a result, SCE submitted an application to the CPUC on March 30, 2005 to pursue development of a
next generation AMI technology that will meet SCE’s business objectives and system requirements for SCE’s
five million customers spread across its 50,000 square mile territory. SCE proposed a multi-phase approach,
with Phase I and II over the next three years encompassing the development effort. System-wide deployment is
anticipated in Phase III contingent upon success in Phases I and II. The goal of this technology development is
to develop, acquire and deploy a durable, reliable, and extensible AMI solution. The following table outlines
the key activities and duration for the various phases in SCE’s overall development and deployment effort
spanning seven and one-half (7 ½ ) years.
The following table outlines all phases of the technology and deployment effort.
Table 1
Key Activity
Functional & Non-Functional Requirements Development
System Architecture
Cost/Benefit Analysis
Small Scale Technology Trials (e.g. integrated disconnect, Home Area Network)
Product Bench Testing (Controlled Lab Environment)
Phase
1
Duration
18 months
2
18 months
Business Process and Back-Office Systems Analysis
Conduct Field Trials – Limited Deployments of compliant technologies
Business Case –in-Chief Development
3a
12 months
CPUC Approval Process
Pre-Deployment Activities
3b
42 months
Full-scale system and meter deployment
Addition information regarding SCE’s business case analysis and approach to developing an Advanced Metering Infrastructure can
be found at www.sce.com/ami. Locate “Regulatory Filings” on the left margin selection tool.
Page 3 of 32
Copyright © 2005 Southern California Edison
All rights reserved.
1
RFI OBJECTIVES
On December 1, 2005, the CPUC approved SCE’s application for Phase I scope and funding. In
anticipation of approval, SCE began the process to define business requirements and AMI system architecture
in November 2005. SCE engaged IBM, EnerNex and KEMA Consulting to work with internal technical and
functional experts through a systems engineering approach. SCE also seeks to begin formally engaging
potential AMI vendors to identify a candidate pool of vendors that have developed or are well underway in the
process of developing a commercial AMI solution that aligns with SCE’s business objectives, system
requirements and development timeline.
As such, SCE intends to use this RFI as a first step in the next generation metering system procurement
process. SCE plans to employ a staged development approach that will lead to identifying, testing and
deploying next generation candidate technologies. SCE expects to work closely with candidate AMI solutions
providers to further develop their next generation technology.
The following table outlines the Phase 1 technology procurement activities and timeline.
Milestones
Time
Table 2
Objective
RFI Part A
Q4 2005
Identify qualified AMI technology vendors
Release
Functional Requirements
Q1 2006
Publish SCE’s AMI business and functional requirements
RFI Part B
Q2 2006
Identify candidate AMI technology solutions based on SCE’s
functional & non-functional requirements for bench testing
RFP
Q1 2007
Field test selection from bench tested AMI technology solutions
VENDOR ENGAGEMENT APPROACH
SCE envisions collaboration with candidate AMI solution providers throughout all phases of this
program. The following table outlines key Phase I development activities.
Table 3
Key Activity
Objectives
Vendor Engagement &
Capability Assessment
Work closely with candidate solution providers regarding their product development
roadmaps and to confirm their capability in meeting SCE’s objectives. Includes
collaboration and due diligence on product development
Pre-commercial
Technology Assessment
Vendor site visits as needed for witness testing and/or review of 3 rd party testing to
confirm pre-commercial technology works in a controlled environment and supports
SCE requirements.
Commercial
Technology Testing
SCE anticipates that qualified solution providers will submit commercial product for SCE
bench testing to verify performance and functionality.
Page 4 of 32
Copyright © 2005 Southern California Edison
All rights reserved.
SCE is attempting to gain a better understanding of those companies serious about providing a “next
generation” AMI solution, to better understand where your company might be in the development process, and
to better determine which companies SCE might work with as it moves forward with its development effort.
SCE is also interested in obtaining more information about your company’s alignment with SCE’s vision (see
“APPENDIX B” included in this solicitation) and the status of your company’s current and near term
development efforts as they relate to this vision.
There will be many vendors and products involved with any comprehensive AMI solution. Broad
categorization of these entities might include: 1) meter vendors, 2) AMI communication solution providers, 3)
meter data management systems and 4) in-premise device vendors (e.g. smart communicating thermostats,
wired or wireless in-home display devices, remotely activated load switches, etc.). The intended audience of
this first RFI only includes those companies that will be engaged in the first two product categories (meter
manufacturers and communication solution providers).
SCE is not currently evaluating meter data management systems, but anticipates beginning evaluations
of these systems after the system architecture design is complete. SCE also anticipates engaging in-premise
device manufacturers at a later date, primarily from the standpoint of understanding interface requirements,
encouraging necessary product development, and working to ensure communications compatible device product
availability.
If (1) your company is working on development of a next generation advanced metering system, (2)
would classify your company as falling within the first two specified product categories, and (3) are interested
in working with SCE on this development effort, please continue to read the terms of this request and then
complete and return the Response Template included as an attachment and titled “APPENDIX
A_SCE_AMI_RFI_Response Template”.
CONTACT INFORMATION
The following e-mail address has been developed and designated by SCE as the primary means of contact (the
“SCE RFI Contact”) for the purposes of this RFI: AMItechnology@sce.com All RFI related questions should
be directed to this address.
RESPONSE SCHEDULE
The schedule for the RFI process is as follows, however, vendors are advised that this schedule is subject to
change at SCE’s discretion:
Friday, December 2nd, 2005. RFI documents will be sent to selected vendors via e-mail.
Friday, December 16th, 2005. By 2:00 PM pacific standard time, vendors must provide three (3) hard
copies (unbound and sent to the address below) and one (1) electronic copy (sent via e-mail to
AMItechnology@sce.com) of their complete response package.
Hard Copies should be mailed to: Southern California Edison
2244 Walnut Grove Ave,
Rosemead, CA 91770
To the Attention of: Judee Apodaca, G.O.1, Quad 1A
Page 5 of 32
Copyright © 2005 Southern California Edison
All rights reserved.
Vendor responses to the RFI (including those delivered in person or by mail courier service) should be clearly
marked on the outside of each package with "CONFIDENTIAL – REQUEST FOR INFORMATION AMI
PROGRAM" and "RESPONSE DUE DATE: 12/16/05.”
RFI QUESTIONS
Vendors should submit via email any questions to the SCE RFI Contact. All questions will be
responded to via email and all answers will be distributed to the entire RFI recipient list.
RFI RESPONSE FORMAT
SCE requests that vendor’s responses conform to the format provided in the attached AMI RFI Response
Template document which was included with this solicitation and to specifically address the content of the
requested information. The inclusion of general marketing materials or technical manuals is discouraged. SCE
reserves the exclusive right to determine if a response is incomplete or non-responsive. SCE will distribute the
responses to an internal review team for evaluation. SCE also requests that response submissions adhere to the
submission deadline as specified above.
FUTURE COMMUNICATIONS
As stated in Table 2, SCE intends to identify qualified AMI technology vendors through this RFI Part A
process. As such, a refined list of AMI technology vendors will be identified to participate in RFI Part B, also
identified in Table 2. It should be noted, however, that SCE understands the potential for changes in
circumstances over the 42-month period appropriated for the 3 phases of the AMI Program. For vendors not
selected to participate in RFI Part B, SCE will provide periodic opportunities to update information included in
the Response Template of RFI Part A. Formal communications will be distributed at a future date to be
determined.
PROPRIETARY INFORMATION
This RFI and the material contained herein is copyrighted by Southern California Edison Company. The
information contained herein is SCE’s proprietary information and is not to be copied or otherwise distributed
in any manner without the express written consent of SCE.
Vendor agrees that responses shall place no obligation on Edison, its subsidiaries or any of its
employees, to maintain these responses in confidence or to otherwise take any steps to protect these responses.
Further, vendor agrees that Edison may use and publicly disclose as required for regulatory purposes any
responses submitted.
PRODUCT ENDORSEMENTS
Unless vendor has SCE’s prior written permission, it will not (1) associate vendor’s products or services with
SCE or SCE’s operations or (2) represent to anyone that SCE has employed or endorsed vendor’s products or
services. Breach of this section entitles SCE to immediately eliminate the vendor from any further
consideration.
DISCLAIMER
This RFI shall not be construed in any manner to create an obligation on the part of SCE to enter into
any contract, or serve as a basis for any claim whatsoever for reimbursement of costs for efforts expended.
Page 6 of 32
Copyright © 2005 Southern California Edison
All rights reserved.
Furthermore, the scope of this RFI may be revised at the option of SCE at any time, or this RFI may be
withdrawn or canceled by SCE at any time. SCE reserves the right to waive formalities and to add, modify, or
delete items, requirements, and terms or conditions prior to the conclusion of this RFI whenever it is deemed to
be in SCE’s best interest. Notwithstanding any other provision of this RFI, vendor is hereby specifically
advised that this RFI is an informal solicitation of information only, and is not intended to be (nor is it to be
construed as) engaging in formal competitive bidding pursuant to any statute, code, ordinance, rule, or
regulation. Therefore, SCE shall not be obligated by any responses received by SCE or by any statements or
representations, whether oral or written, that may be made by SCE, and SCE reserves the unqualified right to
reject any or all responses submitted hereunder for any reason whatsoever. SCE shall be held free from any
liability resulting from the use or implied use of the information submitted in any response to this RFI.
Submission of a response shall constitute the vendor's acknowledgment of this notice and the vendor's
acceptance of this disclaimer.
SCE reserves the right to verify all information provided by vendor via direct contact with the vendor's
prior clients and prior personnel, and the vendor must agree to provide and release necessary authorizations, if
required, for SCE to verify any of the vendor's previous work and the vendor’s qualifications to perform this
work. Misstatements of experience, qualifications and scope of prior work may be grounds for disqualification
of the vendor. SCE reserves the right to amend the schedule of RFI activities, as it deems necessary.
Page 7 of 32
Copyright © 2005 Southern California Edison
All rights reserved.
Appendix
Attachment B – Conceptual AMI System Functionality
Attachment C – Specification E-100 SSM (Meter Requirements)
Page 8 of 32
Copyright © 2005 Southern California Edison
All rights reserved.
APPENDIX B: CONCEPTUAL AMI SYSTEM FUNCTIONALITY
SCE conducted an extensive AMI solution technology search over the past year, and found that a more
feature rich, durable and reliable solution would create a positive business case. This analysis was based on a
conceptual feature set that might be integrated with next generation meters and remote communication devices.
We found that expected end-point pricing decreased dramatically as compared with the increase in overall
integrated features and system functionality. The following graphic provides a conceptual framework of
capabilities.
High Level Conceptual
Meter & Communication Device Functionality
Open Design and Standards
•Internal / External expansion
•Input / Output interoperability
•Software enabled functions
•Data structure & security standards
•Messaging / control protocol standards
Communications
Metrology & Intelligence
•ANSI C12.19 compliant
•Distributed generation detection
•Power quality monitoring & reporting
•Net metering capabilities
•Meter data captured in non-volatile memory
•Remotely programmable / configurable
•Self diagnostics and remote reporting
•Remote disconnect / current limiting capabilities
•15+ year MTTF
Page 9 of 32
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•2-way communications to meter
•High reliability
•Multiple WAN options
•Meter self registering at install
•Home Area Network communications
•2-way communications & control
(e.g. load switches, communicating
thermostats, misc. sensors)
•Ancillary device self registry
•Gas / water meter readability
•Emergency event notification / confirm
APPENDIX C: SPECIFICATION E-100 SSM
Page 10 of 32
Copyright © 2005 Southern California Edison
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Watthour Meters
Table of Contents
1.0
1.1
1.2
1.3
1.4
1.5
1.6
1.7
1.8
1.9
GENERAL REQUIREMENTS
Terms and Definitions
Applicability
Compliance
Verification
Changes and Deviations
Exceptions
Responsibility
Conflicts
Inquiries
4
4
4
4
4
4
4
4
4
4
2.0
2.1
2.2
2.3
2.4
2.5
2.6
SCOPE
General
Compliance with Standards
Purchasing Contract
Applicability
Minimum Requirements
Previous Approvals
4
4
4
5
5
5
5
3.0
3.1
3.2
PERFORMANCE
Longevity and Reliability
Failure Definition
5
5
5
4.0
4.1
4.2
4.3
4.4
4.5
4.6
4.7
4.8
4.9
4.10
4.11
4.12
4.13
4.14
QUALITY COMPLIANCE
100% Testing
Sample Testing
Acceptable Quality Level (AQL)
Sample Size
Acceptance Criteria
Single Phase Meters
Three-Phase Meters
Demand Run-up Test
Accuracy Distribution (Bar-X)
Defective Meters
Shipment Rejection
Inspection
Visual Inspection
Reporting
5
5
6
6
6
6
7
7
7
8
8
8
8
9
9
5.0
5.1
PRODUCT CHANGES
Notification
9
9
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6.0
6.1
6.2
6.3
6.4
6.5
6.6
6.7
6.8
6.9
6.10
6.11
6.12
FUNCTIONAL REQUIREMENTS
Measured Quantities
Additional Measured Quantities
Forward and Reverse Measurements
Loss Compensation Measurements
Basic Default Metering Function
Demand Metering Function
Time-Of-Use (TOU) Metering Function
Self-Read TOU Metering Function
Load Profile Function
Function During Power Disturbances
Meter Test Mode Function
Meter Clock
10
10
10
10
10
10
10
11
11
11
12
12
13
7.0
7.1
7.2
7.3
7.4
7.5
7.6
7.7
7.8
7.9
7.10
7.11
DISPLAY REQUIREMENTS
LCD Display
Viewing Characteristics
Display Components
Digits
Time Format
Date Format
Operating Modes
Normal Mode
Alternate Mode
Display Items
Constants
13
13
13
13
13
14
14
14
14
14
14
14
8.0
8.1
8.2
8.3
8.4
8.5
8.6
METER DIAGNOSTICS
Self Test
Diagnostic Checks
Pulse Overflow
Error and Warning Displays
Error Reset
Metering Installation Diagnosis
14
14
14
15
15
15
15
9.0
9.1
9.2
9.3
PROGRAMMING AND SOFTWARE
Interface Requirement
Meter Programmers
Supplier Software
15
15
15
15
10.0
10.1
10.2
10.3
10.4
COMMUNICATION
Baud Rate
Optical Port Location
Optical Cable
ANSI Protocols
16
16
16
16
16
11.0
11.1
OPTIONAL METER FUNCTIONS
Pulse Outputs
16
16
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11.2
Additional Contact Output
16
12.0
12.1
12.2
12.3
12.4
12.5
12.6
12.7
12.8
ACCURACY
ANSI C12.20
Factory Calibration
Test Equipment
Creep
Starting Current
Start-Up Delay
Pulse Outputs
Disk Emulation
16
16
17
17
17
17
17
17
17
13.0
13.1
13.2
13.3
13.4
13.5
13.6
13.7
13.8
13.9
13.10
13.11
13.12
13.13
ELECTRICAL REQUIREMENTS
Meter Forms, Voltages and Classes
Single-Phase and Three-Phase Meters
Expanded Voltage
Circuit Boards
LCD Display Connectors
Metering Application
Connections
Meter Register Power Supply
Clock
Batteries
Battery Identifiers
Battery Safety
Electromagnetic Compatibility
17
17
17
18
18
18
18
18
18
18
18
19
19
19
14.0
14.1
14.2
14.3
14.4
14.5
14.6
14.7
MECHANICAL REQUIREMENTS
General
Solar Radiation
Corrosive Atmospheres
Meter Package
Cover Requirements
Nameplate
Demand Reset
19
19
19
19
20
20
20
20
15.0
15.1
15.2
15.3
15.4
15.5
SECURITY
Billing Period Reset
Meter Password
Test Mode
Program Security
Revenue Protection
21
21
21
21
21
21
Page 13 of 32
Copyright © 2005 Southern California Edison
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1.0
GENERAL REQUIREMENTS
1.1
Terms and Definitions
1.1.1
Specification
This document consisting of 15 sections
1.1.2
Meter
For the purposes of this specification, an electricity meter is referred to as “meter” or “meters.”
Bidder/Manufacturer/Supplier
These terms apply to meter providers and are synonymous as used in this specification
1.1.3
1.2
Applicability
This Specification applies to any single and multi-stator electricity meter purchased by Edison for the
purpose of collecting revenue information.
1.3
Compliance
Meters obtained from this Specification shall comply with requirements identified herein.
1.4
Verification
Edison reserves the right, at its sole discretion, to test meters to verify compliance with the Specification.
1.5
Changes And Deviations
Edison reserves the right to make partial or complete changes to this Specification and to approve
deviations from the Specification.
1.6
Exceptions
Any product exceptions must be approved in writing by Edison.
1.7
Responsibility
Suppliers shall provide a complete functioning system and shall assume full responsibility for
integrating all hardware, firmware and software they furnish, regardless of origin.
1.8
Conflicts
If conflicts arise, requirements of the Specification will supersede all other requirements
1.9
Inquiries
Inquires about the specification shall be addressed to:
Southern California Edison Company
Procurement Agent -Meters Procurement Division
14660 Chestnut Street, Westminster, CA 92683
2.0
SCOPE
2.1
General
The Specification provides the minimum functional and performance requirements for the meter. All
requirements in the Specification are intended to assure expected life cycles, accuracy, reliability and
minimum maintenance of the meter. It is not intended to inhibit design, construction and creativity of
the Supplier. Some requirements, however, are specified to maintain the compatibility and
interchangeability of the Meter.
2.2
Compliance with Standards
Page 14 of 32
Copyright © 2005 Southern California Edison
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In terms of safety, performance, and susceptibility to natural or induced phenomena, the meter's design,
construction, and operation shall conform to requirements established in the following standards or the
latest revision:
2.2.1
ANSI C12.1 -1995, Code for Electricity metering
2.2.2
ANSI C12.7 -1993, Requirements for Watthour meter Sockets
2.2.3
ANSI C12.10 -1997, Code for Electromechanical Watt-hour meters
2.2.4
ANSI C12.20 -1998, Code for Solid State Demand Registers
2.2.5
ANSI MH10.8M -1983, Specification for Bar Code Symbols
2.2.6
ANSI/ASTM-8117-73 (Z118.1-1974}, Method of Salt-fog Spray
2.2.7
IEEE C37.90.1-2002, SWC Surge Testing
2.2.8
IEC 61000-4-2- 2001, Electrostatic Discharge Requirements
2.2.9
IEC 61000-4 -4- 2001, Electrical Fast Transient/Burst Requirements
2.3
Purchasing Contract
The Specification will be used in conjunction with Edison’s procurement process and if not included in
Edison's contract, it is implied by reference.
2.4
Applicability
The Specification covers Edison’s current and near future requirements for electricity meters used in
revenue applications. The Specification does not cover the requirements for substation or inter-tie
metering. Meters that Edison purchases under this specification will have a limited number of specific
features. Edison will identify the required features with each order.
2.5
Minimum Requirements
As a minimum each Meter supplied shall meet the minimum requirements of this specification and the
requirements of “Direct Access Standard for Metering and Meter Data In California (March 1999),
Meter Approval Testing.”
2.6
Previous Approvals
Meter designs specified and approved by Edison prior to January 1, 2001 remain approved.
3.0
PERFORMANCE
3.1
Longevity and Reliability
The meter shall be designed and constructed, excluding its replaceable battery, to have a life expectancy
of at least 15 years and a failure rate of less than 0.75 % per year. The failure rate is the ratio of the
number of failed meters of a specific type to the number of installed meters of the same type.
3.2
Failure Definition
For the purposes of this specification, a failure is defined as anything that goes wrong with the meter
which prevents its intended operation as outlined herein or if the meter's safe operation is impaired in
any way.
3.2.1
If the failure rate exceeds 0.75%, this will be taken into account during Edison's vendor evaluation as
part of the procurement process.
4.0
QUALITY COMPLIANCE
Page 15 of 32
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4.1
100% Testing
One purpose of this procedure is to obtain data on meters (models) introduced into the Edison system.
Generally, Edison will perform 100% testing of the first (1000) meter (models) to determine the
performance and quality of the meters. Transition to sample testing will occur once Edison is confident
of the meter model quality and performance.
4.2
Sample Testing
Each shipment of Meter models that have been transitioned from 100% testing will be received at
Edison to be sample tested for various physical and electronic attributes and for metering accuracy.
4.3
Acceptable Quality Level (AQL)
The minimum Acceptable Quality Level (AQL) of each Meter shipment received at Edison's shipping
dock shall be 1% as defined by Edison's Sampling Plan. (Table 1).
Lot Size
(1)
First
Sample
size
(2)
< 18
19-150
151-500
501-200
12013200
>3200
All
9
18
42
50
50
Table 1
Edison's Sampling Plan for 1% AQL
Max.
Number Number
Defect
defect
defect
Second
Units
units
Units
Sample
Accept
Reject
ReSize
(3)
(4)
sample
(6)
(5)
0
1
N/A
*
1
N/A
9
0
2
1
24
1
3
2
26
1
3
2
50
1
3
2
100
Max.
Defect
Units
Accept
(7)
0
1
2
2
3
*Indicates that a lot cannot be accepted until the second sample is examined
N/A Indicates not applicable
(1)
Size of shipment
(2)
Size of first sample
(3)
Max. Number of defective units in first sample to allow acceptance of shipment
(4)
Number of defective units in first sample to cause rejection of shipment
(5)
Number of defective units in first sample to necessitate a second sample
(6)
Size of second sample
(7)
Max. number of defective units in second sample to allow acceptance of shipment
(8)
Number of defective units in second sample to cause rejection of shipment
4.4
Sample Size
Table I will determine the size of the sample of each Meter shipment.
4.5
Acceptance Criteria
The Meter shipment will be accepted by Edison when the following criteria is met:
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Numbe
r
Defect
Units
Reject
(8)
1
2
3
3
4
4.5.1
The sample lot passes a combined inspection for physical and electronic attributes and metering
accuracy as defined in Section 4.3.
4.5.2
The sample lot passes the meter accuracy distribution criteria defined in Section 4.5.
4.5.3
Physical and Electronic Attributes and Metering Accuracy
4.5.4
The sample lot will be inspected for physical and electronic attributes as shown in Attachment 1.
4.5.5
As-received accuracy tests will be performed on the sample lot.
4.5.6
The tests will be performed as shown in Table 2
Table 2
4.6
Meter Class
Full Load @
Unity
20
200
320
2.5
30
30
Test Point Loads
Full Load @
50% PF
2.5
30
30
Light Load
@ Unity
0.25
3
3
Single Phase Meters
For acceptance of Single Phase Transformer Rated meters, the metering accuracy at the test points shall
be within:
4.6.1
0.5% at light load at power factor of 100%.
4.6.2
0.5% at full load at power factor of 100%.
4.6.3
0.5% at full load at power factor of 50% lag for polyphase meters.
For acceptance of Single Phase Self-contained meters, the metering accuracy at the test points shall be
within:
4.6.4
0.5% + or – at full load at power factor of 100%
4.6.5
1.0% + or – at full load at power factor of 50%
4.6.6
1.0% + or – at light load at power factor of 100%
4.7
Three-Phase Meters
For acceptance of Polyphase self-contained meters, the metering accuracy at the test points shall be
within;
4.7.1
0.5%+ or – at full load at power factor of 100%
4.7.2
0.5%+ or - at full load at power factor of 50%
4.7.3
1.0 + or – at light load at power factor of 100%
4.7.4
For acceptance of polyphase transformer rated meters, the metering accuracy at the test points shall be
within;
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Copyright © 2005 Southern California Edison
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4.7.5
0.5% + or – at full load at power factor of 100%
4.7.6
0.5% + or – at full load at power factor of 50%
4.7.7
0.5% + or – at light load at power factor of 100%
4.7.8
The Meter shipment will pass the combined inspection if the total number of defective meters plus the
number of inaccurate meters in the sample lot does not exceed the number specified in Column (3) of
Table 1 on the first sample or in Column (7) of Table 1 on the second sample.
4.8
Demand Run-up Test
4.8.1
Apply voltage only to the meter and put the meter into the test mode. Verify that the meter is in the
test mode by observing the word “TEST” is displayed on the LCD screen.
4.8.2
Perform a demand reset to zero all test registers.
4.8.3
Apply current and count 25 complete revolutions exactly.
current.
4.8.4
Verify the kW run-up demand is equal to :
At the end of 25 revs stop the applied
Kh  Re vs  4
Dk  1000
Kh = Kh of the particular meter.
Dk =1
Revs =25
4.8.5
To pass this test, the meter demand displayed value should be exactly the same as the calculated demand
value.
4.8.6
Return the meter to its normal (operating) position by reversing whatever method was used to enter the
test mode. Verify that the test indicator is not displayed.
4.8.7
Replace the meter cover if necessary.
4.8.8
NOTE: The meter under test shall remain energized throughout this test.
4.9
Accuracy Distribution (Bar-X)
The mean and the standard deviation of the as-received metering accuracy of the sample lot will be
calculated for each test point. The Bar-x procedures outline the functional test to be performed on single
phase (240v form 2S) meters that are typically received in a lot of 5760. The material code for this meter
type is 500-03300. The meter shipment will pass the metering accuracy distribution criteria if the mean
and standard deviation of the sample lot meter accuracy are within the limits listed in Table 3.
Table 3
Metering Accuracy Distribution Criteria
Load
Power Factor
Mean
Std. Deviation
Full (HL)
Unity
+ 0.25
+ 0.18
Full (PF)
0.5
+ 0.35
+ 0.35
Light Load (LL)
Unity
+ 0.35
+ 0.35
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4.10
Defective Meters
4.10.1 A Meter that fails any inspection or accuracy test will be returned to the Supplier for replacement or full
credit.
4.10.2 Warranties. The Supplier shall pay for all shipping and handling costs for returning the Meter.
4.11
Shipment Rejection
4.11.1 If the sample lot fails to pass all of the acceptance criteria in Section 4.3, the entire Meter shipment fill
be rejected and returned to the Supplier for full credit. The Supplier shall pay for all shipping and
handling costs for returning the Meter shipment.
4.12
Inspection
4.12.1 Edison, at its option, may specify 100% inspection in addition to its Sampling Plan.
4.13
Visual Inspection
4.13.1 Verify all meter nameplate values are correct such as: the disk constant (Kh), dial constant (DK),
voltage, test amps, prefix/suffix, bar code, etc.
4.13.2 Check the base of each meter for cracked, broken, bent or missing parts.
4.13.3 Check condition of meter stabs for gouges or poor plating.
4.13.4 Check that pot link is intact, screws are tight and not stripped.
4.13.5 Check each meter cover for cracks, chips, reset device is aligned and secured correctly, and for other
obvious defects. Check optical port for damage and alignment. Check for damage to the Reset and Alt
display switch.
4.13.6 Remove the cover and check for the following items:
4.13.6.1 Proper routing of all wires, if visible, to prevent phase to phase or phase to ground contact
4.13.6.2 Insulation intact on all conductors, if visible cracks or damage to the meter chassis proper operation
and no damage to the Reset, Alternate, and Lock/Test buttons
4.13.6.3 Cover and demand reset sealing holes intact to allow proper sealing
4.13.6.4 Cover gasket is intact and cover fits properly
4.13.6.5 Debris inside cover
4.14
Reporting Requirements
Bar-x, Sample Test and 100% test tabulated (accuracy) result forms shall be provided to Edison for
review prior to the release of each meter shipment.
5.0
PRODUCT CHANGES
5.1
Notification
5.1.1
The Supplier shall submit to Edison, for Edison’s evaluation and approval, a written request for any
functional or design revision made to the Meter.
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5.1.2
Design revisions to increase process efficiency are exempt from this notification requirement.
5.1.3
Design changes that could potentially affect the reliability or performance of the Meter, are not exempt
from this notification requirement.
5.1.4
Supplier shall submit to Edison a written request for any substitutions of the Meter for approval.
5.1.5
Requests shall be made with sufficient lead time to guarantee scheduled meter deliveries.
5.1.6
Edison reserves the right to reject any such substitutions or revisions at Edison's sole discretion.
5.1.7
A certified test report shall be required for all substitutions and revisions.
5.1.8
Written requests shall be addressed to:
Southern California Edison
Manager
Effective Date
5.1.9
Edison reserves the right to reject a shipment of the Meter if a change is made on any part or component
of the Meter without Edison's prior written approval.
5.1.10 Edison's approval of any revision shall become effective on the date of the letter notifying the Supplier
of the approval.
6.0
FUNCTIONAL REQUIREMENTS
6.1
Measured Quantities
As a minimum the Meter shall be capable of measuring delivered kilowatt- hour consumption and
delivered kilowatt demand. Edison may specify the following consumption quantities in addition to
delivered kilowatt-hours:
6.1.1
Kilowatt-hours-received.
6.1.2
Kilovar-hours-total delivered, total received, on any quadrant.
6.1.3
Kilovoltamp-hours-total delivered, total received, or any quadrant.
6.1.4
Ampere-squared-hours.
6.1.5
Volt-squared-hours.
6.2
Additional Measured Quantities
Edison may specify the following demand quantities in addition to delivered kilowatts:
6.2.1
Kilowatts-received.
6.2.2
Kilovars-total delivered. total received, or any quadrant.
6.2.3
Kilovoltamps-total delivered. total received, or any quadrant.
6.3
Forward and Reverse Measurements
Edison may specify average power factor for the previous demand subinterval in any quadrant or
combination of two quadrants. The Meter shall be programmable to take one of the following actions
for reverse consumption and demand quantities:
6.3.1
Ignore the reverse quantities.
6.3.2
Add the reverse quantities to the appropriate consumption and demand quantities.
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6.4
Loss Compensation Measurements
Edison may specify transformer loss compensation calculations for consumption or demand quantity
that Edison specifies.
6.5
Basic Default Metering Function
When power is applied to the Meter, it shall immediately begin recording total kilowatt-hours delivered.
This function shall be performed regardless whether the Meter is programmed or not and shall not
require a battery. An unprogrammed meter shall indicate that it is unprogrammed.
6.5.1
Edison may request the Supplier to program Meters with a specific program.
6.6
Demand Metering Function
6.6.1
As a minimum, the Meter shall be programmable for 15 minute block interval demand calculations on
delivered kilowatts.
6.6.2
A battery shall not be required to perform demand calculations, to save the results, or to communicate
the results to a handheld meter reader connected to the optical port.
6.6.3
Demand intervals shall be programmable for a duration of 5,10, 15, 30 or 60 minutes.
6.6.4
Demand functions shall be capable of temporary suspension for a programmable time interval after
power is restored following a power outage.
6.6.5
The length of time shall be programmable from zero to 60 minutes in one minute intervals.
6.6.6
After a demand reset, further manual demand resets shall be prevented with a programmable lockout
time.
6.6.7
A demand reset from a Meter Programmer connected to the optical port is not subject to this delay and
can be initiate as frequently as desired.
6.6.8
If the Meter has been programmed for TOU functions, the time at which maximum demand occurred
shall be recorded at the end of that demand interval.
6.7
Time-of-Use (TOU) Metering Function
As a minimum, the Meter shall be programmable for TOU calculations for delivered kilowatt-hours and
delivered kilowatt demand.
6.7.1
The Meter shall be programmable for TOU calculations for any optional consumption or demand
quantity specified.
6.7.2
The calendar shall be programmable into one to four mutually exclusive seasons.
6.7.3
Each season shall be further programmable into one to four mutually exclusive daily TOU schedules.
6.7.4
The Meter shall be capable of distinguishing weekdays, weekend, day of the week and holidays.
6.7.5
Each consumption and demand quantity shall be metered independently for each TOU schedule.
6.7.6
Only one season and one TOU schedule shall be active at a given time.
6.7.7
There shall always be one active season and one active TOU schedule.
6.7.8
Each daily TOU schedule shall be capable of a minimum of eight switch points with a minimum
resolution of a quarter hour .
6.7.9
The calendar shall be capable of accommodating leap years, daylight saving time changes, and
recurring holidays.
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Copyright © 2005 Southern California Edison
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6.7.10 The Meter shall have capacity for a minimum calendar of 20 years taking into account 16 holidays/year,
8 seasons/year, and 2 daylight savings time adjustments/year with 4 daily TOU schedules/season and
eight switch points/day TOU schedules.
6.7.11 Edison will give preference to Meters that are capable of automatically replacing one TOU program
with another on a specified date.
6.8
Self-read TOU Metering Function
6.8.1
As a minimum the Meter shall perform a self-read of all consumption and demand quantities on season
changes.
6.8.2
A self-read shall consist of reading the quantities, resetting the demand, and storing the data.
6.8.3
The change of season self-reads shall occur at midnight of the day before the season change.
6.8.4
Edison may specify that the Meter be programmable for up to three consecutive self-reads.
6.8.5
The self-reads shall be programmable for the following options:
6.8.5.1 Self-read on a specific day of each month at midnight.
6.8.5.2 Self-read on a specific number of days from the last demand reset (read) at midnight.
6.8.5.3 Self-read data., other than previous season data, need not be displayed but shall be retrievable with a
Meter Programmer connected to the optical port.
6.9
Load Profile Function
6.9.1
As a minimum the Meter shall be capable of providing load profile recording of kilowatt-hours
delivered and the ki1ovar-hours associated with kilowatt- hours delivered.
6.9.2
Edison may optionally specify that the Meter provide load profile recording of interval data for l to 4
additional channels of consumption quantities.
6.9.3
Load profile recording shall operate independently of the TOU functions.
6.9.4
Date and time shall be stored with the load profile interval data.
6.9.5
Load profile data shall use a "wraparound" memory that stores new interval data by writing over the
oldest interval data.
6.9.6
The load profile function shall be capable of storing and communicating a minimum of 35 days of 2
channel, 15 minute data (32 Kbytes memory), in addition to allowances for event recording (power
outages, resets, time sets, etc.).
6.9.7
The load profile function shall have the capacity to count and store at least 16,000 counts in a l5 minute
period of time.
6.9.8
Load profile data recording shall continue while the Meter is communicating with a Meter Programmer
connected to the optical port.
6.9.9
The load profile data interval shall be a programmable, at a minimum to a value of 5, l5, 30 or 60
minutes, or 24 hours.
6.9.10 The Meter shall have an option to increase the capability of the load profile function so that it can store
and communicate a maximum of 60 days of 4 channel, 5 minute data (128 Kbytes).
6.9.11 For each channel of load profile interval data, the Meter shall provide a corresponding register reading
for data validation purposes when the Meter is read by a data retrieval system.
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6.10
Function During Power Disturbances
6.10.1 During power line disturbances such as brownout or outage conditions. and during transportation to the
installation site. the Meter shall maintain all meter data as well as timekeeping functions. Display and
communication functions are not required during these conditions.
6.10.2 The Meter shall withstand all of the following outages during a continuous ten year or longer service
without the need to maintain its auxiliary power system, including replacing the battery:
6.10.2.1 20 short outages per year at less than 30 seconds per outage.
6.10.2.2 40 days of continuous/cumulative outage.
6.10.3 During a power outage critical program and billing data shall be written to nonvolatile memory. When
power is restored, data shall be returned to active memory and data collection resumed.
6.10.4 Following a power outage, register "catch-up" time shall be a maximum of 30 seconds.
6.10.5 During the "catch-up" time the Meter shall still calculate consumption and demand quantities. Optional
outputs shall also function during this time.
6.10.6 During power outages, time shall be maintained with a cumulative error of no more than 2 minutes per
week (0.02%).
6.10.7 The Meter shall record the date and time of any power outage.
6.11
Meter Test Mode Function
6.11.1 The Meter shall have the capability of a Test Mode that suspends normal metering operation during
testing so that additional consumption and demand from the tests are not added to the Meter's totals.
6.11.2 The Test Mode function shall be activated by a permanently mounted physical device that requires
removal of the meter cover to access or by a Meter Programmer connected to the optical port.
6.11.3 Activation of the Test Mode shall cause all present critical billing data to be stored in nonvolatile
memory and restored at the time of exit from the Test Mode.
6.11.4 Upon activation of the Test Mode, register displays shall accumulate beginning from zero.
6.11.5 Actuation of the billing period reset device during Test Mode shall reset the test mode registers.
6.11.6 After a programmable time-out period, the Meter will automatically exit from Test Mode and return to
normal metering.
6.11.7 The default Test Mode registers for an unprogrammed meter shall include as a minimum:
6.11.7.1 Time remaining in the test interval.
6.11.7.2 Maximum kilowatt block demand.
6.11.7.3 Total kilowatt-hours.
6.12
Meter Clock
The Meter Clock shall have a capability of using standard time or daylight savings time separately for
load profile memory and TOU registers. For example, standard time is used for load profile data, while
daylight savings time is used for TOU registers.
7.0
DISPLAY REQUIREMENTS
7.1
LCD Display
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7.1.1
The Meter shall have an electronic display for displaying the consumption and demand quantities.
7.1.2
A liquid crystal display (LCD) is preferred.
7.2
Viewing Characteristics
Digits for displaying the consumption and demand quantities shall be 7/16 inch minimum height, 1/64
inch minimum segment thickness, and be legible in normal daylight conditions from a distance of six
feet by an observer whose eye level ranges from five feet to six feet. The viewing angle shall be a
minimum of thirty degrees from the front Meter face line of sight.
7.3
Display Components
The display shall provide the following:
7.3.1
Five digits for display of the consumption and demand quantities and constants with decimal points for
the three least significant digits.
7.3.2
Three digits for numeric display identifiers (all numbers).
7.3.3
Alternate and Test Mode indication.
7.3.4
Potential indication for each phase.
7.3.5
Current TOU rate indicator.
7.3.6
End of interval indicator
7.3.7
Visual representation of the magnitude and direction of kilowatt loading. (Typically this is a blinking
cursor on the display or a separate LED).
7.3.8
Visual representation of the magnitude and direction of Kilovar loading if the meter is capable of
measuring Kilovars. This representation shall be simultaneous with the kilowatt visual representation.
(Typically this is a blinking cursor on the display or a separate LED).
7.3.9
Annunciators for most consumption and demand quantities.
7.4
Digits
Consumption and demand quantities shall be programmable for display with leading zeroes in four, five,
or six digits with a decimal point at any of the least significant three digits.
7.5
Time Format
Time shall be displayed in the 24 hour military format.
7.6
Date Format
Date shall be displayed programmable in Month/Day/Year format.
7.7
Operating Modes
The display shall have at least three operating modes:
7.7.1
Normal Mode -In this mode the display shall scroll automatically through the programmed displays for
normal meter reading.
7.7.2
Alternate Mode- In this mode the display shall scroll automatically, scroll manually, or freeze for up to
one minute for alternate programmed displays.
7.7.3
Test Mode-In this mode the display shall scroll automatically, scroll manually, or freeze for up to one
minute for test quantity displays.
7.7.4
Display ID numbers and display sequence shall be independently programmable for each of the three
modes.
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Copyright © 2005 Southern California Edison
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7.7.5
Display times shall be programmable.
7.8
Normal Mode
Upon power-up, the Meter display shall operate in the Normal Mode. The Meter display shall operate in
Normal Mode until power is disconnected, the Alternate Mode is activated, or the Test Mode is
activated.
7.9
Alternate Mode
The Alternate Mode shall be initiated with a display control device that does not require meter cover
removal or with a Meter Programmer connected to the optical port.
7.10
Display Items
As a minimum the Meter shall provide the display quantities and items for each of the three modes as
detailed in the Programming instruction
7.11
Constants
The Meter shall have a programmable constant.
8.0
METER DIAGNOSTICS
8.1
Self-Test
The Meter register shall be capable of performing a self-test of the register software. As a minimum, the
self-test shall be performed at the following times:
8.1.1
Whenever communications is established to the register.
8.1.2
After a power-up.
8.1.3
Once per day.
8.2
Diagnostic Checks
As a minimum, the following diagnostic checks shall be performed during a self-test:
8.2.1
Check the backup battery capacity.
8.2.2
Verify the program integrity.
8.2.3
Verify the memory integrity.
8.3
Pulse Overflow
The meter shall be capable of detecting and reporting that an excessive number of pulses accumulated
during a demand interval has caused the pulse accumulator to overflow.
8.4
Error and Warning Displays
8.4.1
Any detected error or warning shall be stored in memory and an error or warning code displayed on the
display.
8.4.2
Error code displays shall freeze the display.
8.4.3
Warning code displays shall be programmable to one of the following choices:
8.4.4
Freeze the warning code on the display.
8.4.5
Ignore the warning code (not displayed).
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8.4.6
Warning code display at the end of the Normal. Alternate or Test Modes display sequences.
8.5
Error Reset
Error or warning conditions shall only be reset upon an explicit command invoked via the Meter
Programmer or upon some other explicit action by Edison.
8.6
Metering Installation Diagnosis
The Meter shall self-diagnose the metering installation and provide warning codes. As a minimum, the
following diagnostics shall be performed:
8.6.1
Check phase voltage and current polarity.
8.6.2
Check for cross phasing.
8.6.3
Check energy flow direction.
8.6.4
Check for phase voltage deviation.
8.6.5
Check for phase voltage loss.
8.6.6
Check for inactive phase current.
8.6.7
Check for phase angle displacement deviation.
8.6.8
Check for current waveform distortion.
9.0
PROGRAMMING AND SOFTWARE
9.1
Interface Requirement
The Meter shall be capable of communicating with an Itron FS2 handheld reader through its optical port.
9.2
Meter Programmers
SCE will use Microsoft Windows XP based laptop computers with LCD displays and optional internal
modems as meter reader/programming devices (Meter Programmers). Communications with the Meter
shall be through the optical port or through the modem and a phone line.
9.3
Supplier Software
The Supplier shall provide all software for maintenance, programming, and operation of the Meter. The
software shall include the following:
9.3.1
Rate Development Program
9.3.2
The Supplier shall provide a Rate Development Program software package which allows Edison to
customize the Meter's rate schedules and the Meter's operating parameters.
9.3.3
The Rate Development Program shall be capable of utilizing all programmable functions of the Meter
Field Program
9.3.4
Field Disk Security Program
10.0
COMMUNICATION
The primary communication port for programming and maintaining the Meter shall be an optically
isolated communication port per ANSI C12.18, Type 2. Retrieval of load interval data from the Meter
shall also be possible through this port.
Meters with additional remote communication options, could be given preference by Edison.
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Copyright © 2005 Southern California Edison
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10.1
Baud Rate
The Optical Port shall communicate at a minimum of 9600 baud.
10.2
Optical Port Location
The Optical Port shall be located in the front of the Meter and be accessible without removing the
Meter's cover. The Optical Port shall also be functional with the Meter cover removed.
10.3
Optical Cable
There shall be no cable connecting the optical port on the Meter cover to the meter electronics.
10.4
ANSI Protocols
The Meter shall support the following ANSI standards as soon as possible:
10.4.1 ANSI C 12.18-1996, Protocol Specification for ANSI Type 2 Optical Port.
10.4.2 ANSI C12.19-1996, Utility Industry End Device Data Tables. Standard Tables
10.4.3 ANSI C12.21-2000. Protocol Specification for Telephone Modem Communication.
10.4.4 ANSI CI2.22-200X. Protocol Specification for Networks (when approved).
11.0 OPTIONAL METER FUNCTIONS
11.1
Pulse Outputs
SCE may specify one to four channels of pulse outputs that are proportional to the consumption
quantities. In addition, pulse input channels could also be given as a preference. The pulse output
values shall be programmable with pulse duration of a least 100 milliseconds. The outputs may be either
2-wire, Form A or 3- wire, Form C configuration.
11.2
Additional Contact Output
Edison may specify a contact output in addition to the pulse outputs. This output shall be programmable
as any one of the following:
11.2.1 A Load Control switch
11.2.2 An end-of-interval indicator
11.2.3 A demand threshold alarm
12.0 ACCURACY
12.1
ANSI C12.20
The Meter shall meet or exceed the accuracy specifications contained in ANSI C12.10 over its entire
service life without the need for adjustment.
12.2
Factory Calibration
The Meter shall be calibrated by the Supplier to provide an accuracy of plus or minus 0.3% at:
12.2.1 Full load, unity power factor
12.2.2 Full load, 0.5 lagging power factor
12.2.3 Light load, unity power factor
12.3
Test Equipment
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The Meter shall not require any special equipment for shop or field testing procedures. All standard test
equipment currently used at Edison may be used for testing the Meter in both the field and the shop.
12.4
Creep
The Meter shall not creep. No pulse generation or registration shall occur for any consumption or
demand quantity which depends on current while the current circuit is open.
12.5
Starting Current
The Meter shall start to calculate consumption and demand quantities when the per phase current
reaches the following limits:
12.5.1 Class 20- 5 milliamps.
12.5.2 Class 200- 50 milliamps.
12.6
Start-up Delay
The Meter shall start to calculate consumption and demand quantities less than 3 seconds after power
application.
12.7
Pulse Outputs
Pulse outputs shall have the same accuracy as the Meter displays.
12.8
Disk Emulation
Disk emulator shall have the same accuracy as the Meter test LED.
13.0 ELECTRICAL REQUIREMENTS
13.1
Meter Forms, Voltages, and Classes
SCE may specify the Meter forms, voltages, and current classes as shown below.
13.2
Single Phase and Three-Phase Meters
13.2.1 Single Phase Meters
Form
1S
1S
2S
2S
2S
2S
2S
3S
Voltage
120 (Induction)
120-480
240 (Induction)
120-480
240 (Induction)
120-480
480 (Induction)
120-480
Class
100
200
200
200
320
320
200
20
Voltage
120-480
120-480
120-480
Class
20
20
200
13.2.2 Polyphase Meters
Form
5S
9S
12S
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16S
13.3
120-480
200
Expanded Voltage
The Meter shall incorporate Expanded Voltage ranging potential coils that operate between 110 volts
and 600 volts continuously.
13.4
Circuit Boards
All circuit boards in the Meter shall be assembled per ANSI/IPC-61 OA, Class 2 Standards. They shall
be designed to meet Edison's environmental and electrical testing requirements and the service life and
performance expectations detailed in this Specification.
13.5
LCD Display Connectors
Gold pins or carbonized contacts shall be used to connect the LCD display to the register circuit board.
13.6
Metering Application
The Meter shall be used to meter electrical service on a continuous duty.
13.7
Connections
13.8
Meter Register Power Supply
The Meter's internal electrical connections shall be in accordance with ANSI C12.10
The Meter register shall be powered from the line side of the Meter. The power supply shall not be fused.
13.9
Clock
13.9.1 The Meter’s internal time-base shall be have a minimum accuracy of plus or minus 0.02%.
13.9.2 The internal clock shall have two modes of operation as follows:
13.9.3 The clock shall synchronize with its own time-base during outages.
13.9.4 The clock shall synchronize with line frequency, except during outages.
13.9.5 The clock’s mode of operation, internal time-base or line frequency, shall be programmable
13.10
Batteries
13.10.1When the Meter design requires a battery as auxiliary power supply, the requirements of the following
battery sections shall apply.
13.10.2The battery shall be secured with a holder securely attached to the Meter. The battery holder and
electrical connections shall be designed to prevent the battery from being installed with reversed
polarity.
13.10.3Replaceable batteries shall be easily replaced when the outer Meter cover is removed. and shall not be
disconnected if the inner casing or cover is removed for maintenance or repair of the Meter. Battery
replacement while the Meter is in service shall not interfere with any of the specified functions.
13.10.4No fuse external to the battery shall be installed in the battery circuit.
13.10.5The meter battery shall provide 5 years of carryover capability at 23° C for the functions listed in
Section 6.7 with a 15 year shelf life.
13.11
Battery Identifiers
The following information shall be clearly identified on the battery:
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13.11.1 Manufacturer.
13.11.2 Date of Manufacture, including year and month (i.e. 9301) or year and week (i.e. 9344).
13.11.3 Polarity markings.
13.11.4 Voltage Rating.
13.11.5 Type.
13.12 Battery Safety
13.12.1 The Supplier shall provide battery handling instructions, safety precautions, and disposal instructions
upon Edison’s request.
13.12.2 The Supplier shall provide Material Safety Data Sheets upon Edison’s request.
13.13
Electromagnetic Compatibility
The Meter shall be designed in such a way that conducted or radiated electromagnetic disturbances as
well as electrostatic discharges do not damage nor substantially influence the Meter .
13.13.1
Radio Interference Suppression
13.13.2 The Meter shall not generate conducted or radiated radio frequency noise which could interfere with
other equipment.
13.13.3 The Meter shall meet FCC Pan 15 Class B computing device Radio Frequency Interference standards.
14.0 MECHANICAL REQUIREMENTS
14.1
General
The Meter shall not pose any danger when operating under rated conditions in its normal working
position. Particular attention shall be paid to the following:
14.1.1 Personnel protection against electric shock.
14.1.2 Personnel protection against effects of excessive temperature.
14.1.3 Protection against the spread of fire.
14.1.4 Protection against penetration of solid objects, dust or water .
14.1.5 Protection against corrosion
14.1.6 All pans shall be effectively protected against corrosion under normal working conditions.
14.1.7 Protective coatings shall not be damaged by ordinary handling nor damaged due to exposure to air
14.2
Solar Radiation
The functions of the Meter shall not be impaired, the appearance of the Meter shall not be altered, and
the legibility of the Meter nameplate and other labels shall not be reduced due to exposure to solar
radiation throughout the service life of the Meter .
14.3
Corrosive Atmospheres
SCE may specify additional requirements for Meters used in corrosive atmospheres.
14.4
Meter Package
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14.4.1 The Meter's dimensions shall be in accordance with ANSI CI2.10.
14.4.2 The Meter shall be designed for mounting outdoors in a standard meter socket.
14.4.3 A twist-on self-1ocking cover shall be provided in accordance with ANSI C 12.10 requirements.
14.5
Cover Requirements
The cover shall have the following attributes:
14.5.1 It shall not contain a metal or conducting locking ring.
14.5.2 It shall be resistant to ultraviolet radiation.
14.5.3 It can be sealed in such a way that the internal parts of the meter are accessible only after breaking the
seal.
14.5.4 Non-permanent cover deformation shall not prevent the satisfactory operation of the meter.
14.5.5 The “sprue” hole (mold fill hole) shall not affect the ability to read the meter.
14.5.6 It shall have an optical port per ANSI C12.18, Type 2.
14.5.7 The method of securing the Meter to the meter socket shall be with either a sealing ring or a high
security sealing device.
14.5.8 The billing period demand reset device shall accommodate a standard utility seal and shall remain in
place with friction if not sealed.
14.5.9 Filtered ventilation shall be provided in the base of the Meter to prevent condensation inside the Meter.
14.5.10 Non demand, induction watthour meters with Form 1S or 2S shall be fitted with glass covers
14.6
Nameplate
14.6.1 The nameplate information shall comply with the minimum requirements of ANSI C12.10.
14.6.2 The nameplate of the Meter shall include Edison’s meter number and manufacturing date.
14.6.3 SCE will provide the meter number to the Supplier.
14.6.4 The manufacturing date shall include the year and month (i.e. 9301) or the year and week (i.e. 9344).
14.6.5 The nameplate shall have the following attributes:
14.6.6 It shall be mounted on the front of the Meter.
14.6.7 It shall not be attached to the removable meter cover.
14.6.8 It shall be readable when the Meter is installed in the meter socket.
14.6.9 It shall not impair access for accuracy adjustment or field replacement of components (such as the
battery).
14.6.10 The nameplate shall include bar coding per Edison Standard for Bar-coding of E1ectricity Meters.
14.6.11 The nameplate shall include an easily erasable strip with minimum dimensions of 0.75 inch by 0.75
inches for penciling in items such as meter multiplier.
14.7
Demand Reset
The Meter shall have a hardware reset mounted on the Meter cover.
15.0
SECURITY
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15.1
Billing Period Reset
Operation of the billing period demand reset mechanism shall require breaking of a mechanical sealing
device. Use of common utility sealing devices shall be accommodated.
15.2
Meter Password
The Meter shall be programmable with up to three unique passwords to prevent unauthorized use of the
optical port or the optional modem. Access rights and capabilities shall be individually programmable
for each password.
15.3
Test Mode
Removal of the Meter cover shall be required to activate the Test Mode.
15.4
Program Security
At least three levels of security shall be available for the Rate Development Program and the Field
Program. These levels include:
15.4.1 Meter-Inquiry-Reset can access billing and load profile data, and perform a demand reset.
15.4.2 Meter-Modify-Reset can perform functions listed in 15.4.1 plus download meter configuration files and
operate other features of the Field Program.
15.4.3 Meter-Modify-Program can perform functions listed in 15.4.2 plus develop meter configuration files and
operate all features of the Rate Development Program.
15.5
Revenue Protection
Meters that help prevent energy diversion will be given preference by Edison.
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