Smart Metering Program in India - A Critical Assessment

ISGF White Paper
Smart Metering Program in India – A Critical

Assessment – Revision 1 (October 2023)
(FOR PRIVATE CIRCULATION ONLY)
Abstract
Electric utilities in Western Europe and North America embarked on Smart Metering or Advanced Metering
Infrastructure (AMI) implementation at the beginning of the 21st century and today there are over 1.15 billion smart
meters in operation around the globe. The early AMI projects had limited functionalities. As large volumes of smart
meter data accumulated, forward looking utilities deployed advanced digital tools for analyzing the energy
consumption data and realized that the time-stamped meter-reads offer a goldmine of information to fine-grain the
distribution grid including accurate demand forecasting, power purchase cost reduction and asset optimization. Some
of the early mover utilities in the AMI domain have also deployed Smart Meter Operations Center (SMOC) with
Artificial Intelligence (AI) and Machine Learning (ML) tools for advanced analytics; and this current level of smart
metering is referred as AMI 2.0 which offers several more benefits to utilities to transform as the next generation
digital utilities. This updated version of the White Paper highlights the threat of potential claims for IPR fees by cellular
technology patent holders for using their technologies in smart metering which could find attractive to these patent
holders when tens of millions of smart meters are connected on cellular networks.
India is presently rolling out 250 million smart meters on fast track and can leapfrog to AMI 2.0 by leveraging the
experiences of global utilities who have successfully ascended to AMI 2.0. This paper examines the ongoing AMI
rollout in India and suggests the measures for mid-course correction to protect the investments.
Disclaimer Authors
Anand Singh
The information and opinions of this document
Balasubramanyam K
belongs to India Smart Grid Forum (ISGF). ISGF has no
Disha Khosla
obligation to communicate with all or any reader of
this document when opinions or information in this Rajani A
document changes. We make every effort to use Reena Suri
reliable and comprehensive information, however we Reji Kumar Pillai
do not claim that it is accurate or complete. In no Vivek Gupta
event shall ISGF or its members shall be liable for any Shashi Bala
damages, expenses, loss of data, opportunity, or
profit caused using the contents of this document. October 2023
About India Smart Grid Forum

The India Smart Grid Forum (ISGF) is a Think-Tank of global repute on Smart Energy, Electric Mobility, Grid
Modernization and Energy Transition. ISGF, established as a Public Private Partnership (PPP) initiative of Government
of India in 2011, is spearheading the mission to accelerate electric grid modernization and energy transition in India.
ISGF is registered as a Not-for-Profit Society under Indian Societies Act and has its head office at CBIP Building, Malcha
Marg, Chanakyapuri, New Delhi 110021.
1 INTRODUCTION 1 INTRODUCTION
In 2021, Government of India (GOI) launched the world’s largest smart metering or Advanced Metering
Infrastructure (AMI) program to replace 250 million electricity meters with smart prepayment meters
under the Revamped Distribution Sector Scheme (RDSS) applicable to all the state government owned
electricity distribution companies (Discoms) in India. The smart meter rollout proposed under this scheme
envisages the appointment of an AMI Services Provider (AMISP) who will implement the AMI system and
maintain it for ten years against a monthly fee per meter based on specified service level agreements
(SLAs). Under RDSS, GOI will provide 15% of the cost of the project as grant to the Discoms which will be
passed on to the AMISPs. Power Finance Corporation Ltd (PFC) and Rural Electrification Corporation Ltd
(REC) are the nodal agencies for RDSS – half the Discoms are with PFC and rest with REC. A standard bidding
document (SBD)1 has been issued by REC for appointment of AMISPs which all the Discoms are mandated
to follow for availing the grant under RDSS. Also, several AMISPs has been empaneled for this program2
who are only eligible to bid for the AMI projects in Discoms. As of September 2023, 51 AMISPs have been
empaneled; but majority of them have no prior experience with smart metering and many of them have
never undertaken any kinds of projects with Discoms. This is a cause of concern as their understanding of
what it takes to implement a large AMI project involving millions of meters is doubtful. The AMI system
must be maintained by the AMISP for about 93 months after commissioning including replacement of faulty
meters, maintaining the last mile connectivity, IT systems upgrades as and when required; and complying
with the cyber security norms. As per the SBD, there are steep penalties for not meeting the SLAs. AMISPs
need to factor all these risks in their project budget – not to speak of minimum two changes of the elected
state governments who control the Discoms during the ten year project life that brings its own challenges.
As of 15 August 2023, AMI projects totaling about 230 million meters have been approved by the nodal
agencies (PFC and REC) and contracts for 56 million meters have been awarded; tenders for the rest are
under various stages of finalization. During the RDSS finalization and program rollout in the past 2 years,
the SBD has gone through several rounds of amendments. Additionally, certain conditions imposed on the
project implementation methodology do not align with successful practices from smart metering
experiences worldwide over the past two decades. This paper provides insights gained from experts with
decades of hands-on experience in implementing and maintaining large AMI systems in different utilities
around the globe. It also offers a practical implementation roadmap for smart metering in Discoms in India.
2 KEY CONSIDERATIONS IN SMART METERING IMPLEMENTATION
Some of the key components of the AMI systems and the considerations for their selection and
implementation are discussed here.
1 Latest version of the SBD can be accessed here: https://recindia.nic.in/SBD-AMISP

2 List of empaneled AMISPs can be accessed here: https://recindia.nic.in/ami-test-demonstration
ISGF White Paper on Smart Metering Program in India – A Critical Assessment

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2.1 Smart Meters
Smart meters are a significant improvement over traditional meters in many ways. They offer several unique
characteristics that can greatly benefit both consumers and utilities. One key feature of smart meters is their
ability to transmit detailed and accurate energy usage data in real-time. This enables consumers to monitor
and adjust their energy consumption patterns, leading to greater energy-efficiency and cost-saving benefits
over time. Additionally, smart meters have the potential to support a more reliable and efficient power grid
owing to their ability to remotely detect and report power outages and other issues. Smart meters eliminate
the need for manual meter readings which saves time, reduces costs and labor, and improves accuracy. With
benefits ranging from improved energy-efficiency, reduced costs, to better monitoring and reporting
capabilities, smart meters are a valuable upgrade for any utility looking to improve their services.
India is one of the few countries that have a national-standard for smart meters. IS:16444 standard for smart
meters was issued by Bureau of Indian Standards (BIS) in 2015 and the associated data communication
standard IS:15959 Part-2 was issued in 2016. Presently there are 87 BIS certified meter manufacturing units
with cumulative annual capacity of over 100 million meters in India3. While new domestic companies are
setting up manufacturing facilities, some of the existing players are augmenting their manufacturing
capacities as well. Foreign players are not expected to jump in due to very competitive pricing by domestic
players and ban of import of smart meters from countries sharing land border with India (which precludes
Chinese firms from participating in the smart metering projects in India). Overall, availability of smart meters
is not expected to be a constraint for the 250 million smart meter rollout program. Smart meters record
meter readings every 15 mins and have the memory to keep the data for 45 days in the meter.
2.2 Communication System
AMI requires two-way communications between the smart meter and the Discom’s computers in the control
room (or on the cloud). Various communication technologies, either individually or in combination, have
been used by utilities worldwide for AMI. Major utilities in North America, Australia, Japan, Nordic Europe,
South America, and South Korea have opted for the radio frequency mesh (RF Mesh) solution for their last
mile connectivity. Chinese4 and some European utilities have chosen power line communication (PLC)
technology, along with RF Mesh, for their last mile communication. Meanwhile, utilities in the UK5 and a few
other Scandinavian countries have adopted cellular technologies. Detailed features, architecture and
comparison of these different communication solutions are described in the next section 3.
Claim for IPR fees for using cellular technology for smart metering by cellular technology patent holders is a
new development that started in Europe. As the number of smart meters deployed on cellular technologies
scale up massively, such claims can arise in India as well. This issue is explained in APPENDIX-A
3 List of BIS approved smart meter manufacturing units in India is given in this link:
https://www.services.bis.gov.in/php/BIS_2.0/bisconnect/manufacturers/RGlyZWN0IENvbm5lY3RlZA==
4
Initially, smart metering with limited functionalities was rolled-out in China on PLC connectivity; later they experimented with RF
Mesh, Cellular and NBIoT technologies. The second-generation AMI which is about to begin in China is expected to deploy RF Mesh
for last mile connectivity
5
The UK launched the AMI rollout on cellular communications; but soon realized that cellular communication cannot reach meters
installed in the basement of buildings; hence they had to install RF based range extension systems. Out of 35 million smart meters
installed so far in the UK, about 40% of them are connected through RF communication

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2.3 Software Solutions for AMI
Head-End System (HES) and Meter Data Management (MDM) System are the most important software
solutions in an AMI system.
HES is a software that is responsible for fetching the meter data from the smart meters to the Discom’s
computers. Another important software for AMI system is the MDM which is installed in the Discom’s
computers where all meter data is collected and stored. In India, utilities record the meter readings every 15
minutes – 96 reads per day and this will be brought from millions of meters to the MDM by the HES. The
meter data organized in specified formats in the MDM helps to integrate it with the Discom’s billing system,
customer care system, geographical information system (GIS); and other IT applications. While there can be
several makes of meters, different communication technologies in different regions and several HES in a
smart metering solution of one utility, it is recommended to have only ONE MDM in a Discom which will
integrate all meter data with the billing systems and other Discom applications.
Having a single MDM for a Discom has several advantages over the use of multiple MDM systems. First, a
single MDM reduces integration costs by streamlining the process of data collection, analysis, and storage.
This eliminates the need for extensive customization and specialized staff training, resulting in significant
savings to the Discom. Another benefit of using a single MDM is the ability to standardize data reporting,
ensuring consistency and accuracy across the entire utility system. This not only simplifies data analysis, but
also improves system reliability and reduces the risk of errors, leading to an improved customer experience.
Additionally, the use of a single MDM system can alleviate the challenge of managing multiple competing
data systems. With a common data environment, Discoms can better coordinate their operational functions,
optimize resource management, and improve decision-making processes. In summary, the adoption of a
single MDM will help Discoms to streamline operations, reduce costs, and improve system reliability. By
consolidating data collection and analysis into one standardized platform, Discoms can successfully manage
the energy landscape and customer demands with greater efficiency and effectiveness.
2.4 Smart Meter Operations Centre (SMOC)
Smart Meter Operations Centre (SMOC) is the control center with network monitoring system and advanced
analytical software solutions. The first-generation AMI projects did not have SMOC and as AMI data started
piling up, the utilities created SMOC with advanced analytical tools to handle the smart meter data. The time-
stamped meter-reads offer a goldmine of information about the power flows in the low voltage network
which helps to fine-grain the distribution grid including accurate demand forecasting that will reduce power
purchase cost and improve asset optimization. SMOC has proven to be beneficial in monitoring and
management of smart meter rollout as well. The standard bidding document (SBD) for the AMI program of
RDSS covers the functions of SMOC under Network Management Systems (NMS) and Network Operation &
Monitoring Centre (NOMC)6. Several functionalities and technical requirements of NMS and NOMC are
mentioned in these sections of the SBD. Detailed architecture for SMOC is not included in the SBD which is
left to the bidders to propose. For large scale AMI rollout, it is essential to have a well-designed SMOC that
can manage meter roll outs, data collection, data integration, data provisioning and data analytics. SMOC
typically provide/responsible for:
6
Section 6; Clause 2.2.2; and Clause 2.6 of the Model Standard Bidding Document for AMI

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▪ Centralized Project Management
▪ Platform for Business Intelligence
▪ AMI Events Management
▪ Enterprise Asset Management and Monitoring
▪ Consumer and Consumption Analytics
▪ AMI ROI Matrix Tracking such as Revenue Protection, Load Planning etc
▪ Consumer Engagement Modelling
▪ SLA Management
▪ Service Ticket Management for Helpdesk
▪ Training Simulator
▪ Audit Trail
SMOC Analytics integrated with Customer Portal could provide real time visibility to customers on:
▪ Customer Billing and Energy Profile Information
▪ Prepayment Information
▪ Customer Centric Analytics
▪ Alerts on Account Information Updates
▪ Home Energy Profiles
▪ Customer Self Service
▪ Cost Saving Tips
▪ Customized Communication, Utility-branding, Customer Service and Feedback
Since most of the empaneled AMISPs are new to the AMI domain, it is recommended to include the detailed
architecture of state-of-the-art SMOC in the SBD.
2.5 AMI Architecture
In an ideal AMI system, there could be multiple makes of meters, different communication technologies,
different HES, but only ONE MDM. There are very few COTS7 MDMs in the world that are scalable to muti-
million meters. MDM software is expensive and its installation and integration with utility applications such
as billing system, customer care system, GIS; and outage management system is a very specialized job and it
takes minimum 6-9 months depending on the interfaces and the skill levels of the system integration team –
this is irrespective of the number of meters involved (whether 1 meter or 1 million meters).
There should be a standard middleware that should act as the integration platform through which different
Discom applications can call different data sets as and when required from the MDM. The selection and sizing
of the MDM and the middleware are very critical; and the hardware (on the cloud) sizing depends on the
software sizing. If the AMISP and their System Integrator (SI) get the sizing calculations (of software and
hardware) wrong initially, it will prove to be too expensive to correct them at a later stage. This is where prior
experience of handling humongous data generated by millions of meters and its integration with Discom
7 Commercially available Off the Shelf (COTS) refers to popular software products for which experts can be hired from the open
market. For proprietary software products one must always depend on the OEM for support. Most proprietary products may not
follow standard protocols and it may be difficult to integrate with other utility applications – all such integrations may be bespoke
developments which will be very difficult and expensive to maintain.

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applications should be valued. As mentioned already, majority of the empaneled AMISPs have no such
experience or exposure. The size of AMI contract packages being awarded by Discoms is in the range of 4-6
million meters which is too huge to be executed in a reasonable time frame even by experienced agencies;
and most of such large contracts have been awarded to AMISPs who have never undertaken any AMI projects
in the past. This is a serious cause of concern.
Typical AMI Architecture is presented below.
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Figure 1: Typical AMI Architecture
(SM1 – smart meters connected on RF mesh; SM2 – smart meters connected on cellular network; TSP NMS – network monitoring
system by telecom service providers for the meters connected on cellular communication; RF NMS – network monitoring system for
meters connected on RF mesh provided by the RF solution provider; DCU – data concentrator unit; GUI – graphical user interface;
WFM – workforce management system)
What is presented above is a Service Oriented Architecture (SOA) with micro-services which is the state-of-
the-art (SOTA) practice today. In the recent tenders from a few states, it is noticed that for each tender
package a separate MDM is provisioned which is not only expensive, but also prevents realization of several
benefits of smart metering. As mentioned already, with multiple MDMs (perhaps of different makes) in one
Discom, proper integration with billing system and energy accounting will be difficult. This approach is
erroneous and should be corrected immediately.

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3 COMMUNICATION SOLUTIONS FOR AMI
AMI requires two-way communication between the smart meters installed at the customer premises and the
Discom’s computers; and this two-way communication facilitates meter data transfer from the smart meters
to the Discom’s computers as well as sending commands from the Discom’s computers to the smart meters.
This is the most critical function for the reliable operations of the AMI system. Typical AMI communication
architecture is depicted below.
Figure 2: AMI Communication Architecture

(WAN: Wide Area Network; NAN: Neighborhood Area Network; FAN: Field Area Network;
HAN: Home Area Network; DCU: Data Concentrator Unit)
Public telecom networ or the utility’s fiber network (wherever available) is used for Wide Area Network
(WAN) solutions for AMI systems. The main challenge in a successful AMI system is the last mile connectivity
for which several solutions are available. The most successful AMI projects around the world have either
chosen RF Mesh technology or PLC technology for the last mile connectivity. In case of cellular technology,
the SIM card inside the meter is directly connected to the telecom network and there is no need for a
separate WAN network. The success of this depends on the data communication capabilities of the public
telecom network in a particular area. Different technologies available for last mile connectivity (NAN/FAN),
wide area network (WAN) and home area network (HAN8) are presented in the table below.
8Home Area Network (HAN) to connect the appliances inside home with smart meter was deployed during the first generation of
AMI. Now that smart apps are popular, the appliances can be connected to the broadband network at home and can be remotely
managed through apps on the smart phones; and their electricity consumption can be monitored through the customer portal of the
utility which has now become an integral part of the AMI system. Separate HAN is not being built these days.

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Table 1: Different Technologies Available for Last Mile Connectivity
Home Area Network
Technology Last Mile (NAN/FAN) Wide Area Network
(HAN)
▪ RF Mesh
▪ RF Mesh
▪ ZigBee ▪ Cellular
▪ 6LowPAN
▪ Wi-Fi ▪ Satellite
▪ ZigBee
▪ Millimeter Wave Bluetooth Low ▪ LPWAN
Wireless ▪ Wi-Fi
Energy (BLE) and BLE 5 ▪ Long Wave Radio
▪ Bluetooth
▪ Long Range Radio (LoRA) ▪ TV White Space
▪ Z-Wave
▪ Narrow Band IoT (NB IoT) -CAT ▪ Private Microwave Radio
▪ NFC
M1; LTE
▪ PLC (narrow band) ▪ Telecom Cables, Fiber Optic

▪ PLC ▪ Broadband over Power Line (BPL) Cables
Wired
▪ Ethernet ▪ Ethernet ▪ Power Line Carrier
▪ Control Area Network (CAN) Communication (PLCC)
3.1 Choice of Communication Technologies
Criteria for choice of different communication technologies is presented below.
Table 2: Choice of Different Communication Technologies

NarrowBand
Parameters RF Mesh Cellular PLC LoRA
IoT (NB IoT)
Deployed and Deployed and
Deployed and
Managed by Managed by
Managed by Managed by Managed by
Network Type Utility or their Utility or their
Utility or their the Telcos Telco
Service Service
Service Provider
Provider Provider
Topology Mesh Point-to-Point Star Point-to-Point Star
Spectrum Type Free Paid Free Paid Free
Dependency (Service
No Yes No Yes Yes
Provider)
Latency Medium Low High Low High
Depends on Depends on the Depends on
Depends on
Reliability/Availability >99% Service Condition of Service
Service Provider
Provider the Power Line Provider
Redundancy Self-Healing No No No No
Data Handling Large Large Packet Small Small
Appendix-B presents a list of utilities who have implemented AMI around the globe and their chosen
communication technologies for their AMI systems.
3.2 Telecom Operators Interest in AMI Projects
Cellular Operators Association of India (COAI) has appealed to the Telecom Ministry regarding security risk
in deploying license-free spectrum for smart metering; and subsequently, Telecom Ministry has invited

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comments from various stakeholders on this issue. ISGF has examined this issue and found no merit in the
argument of security risks in using license-free spectrum by deploying RF mesh solutions for last mile
connectivity for the AMI projects. As presented in the Appendix-B, 179 million smart meters are operating
with RF Mesh technology in different countries successfully for about a decade or more. Another 748 million
smart meters are operating on PLC technologies; and 156 million meters on combination of PLC and RF
technologies. Compared to these, the total number of smart meters operating on cellular networks is only
57 million. The key issues with cellular communication system for smart metering are briefed below:
a. Service Level Agreement (SLA): The AMI Service Providers (AMISPs) are bound to commit certain SLAs
(99%) for AMI system availability whereas none of the cellular service providers are ready to commit
guaranteed SLAs. Experiences with cellular communication for AMI in India indicate SLA below 95%
even in urban areas; which could be much lower in rural areas where data network is weak.
b. Technology Changes: Cellular operators upgrade their technologies frequently – 2G, 3G, 4G, 5G and
will move to 6G. Changing the network interface cards (NIC) and the SIMs in millions of meters is too
expensive and nearly impossible9. UK Government has recently sanctioned a £4 billion plan to replace
the 3G modems in smart meters with 4G, as the telecommunications companies will no longer provide
support for 3G. It is worth mentioning that, historically, the cellular telecom industry tends to undergo
upgrades every 5 years, leaving the previous infrastructure outdated which is closely aligned with the
handset replacement cycle.
c. Mis-match of Rollout Plans: Cellular operators primarily target urban areas for their new technology
rollout whereas electric utilities need to cover customers in urban and rural areas.
d. Cost: The initial installation cost of both RF Mesh (network interface cards + DCU/Gateway) and
Cellular (NIC + SIM) is nearly the same. But for cellular technology, there is a fee per meter per month
to be paid to the cellular operators which will be a huge burden that will eventually get passed on to
the common man (electricity consumer). Even at a modest fee of Rs 10 per meter per month, it works
out to about Rs 3000 crore per year to cellular operators for 250 million meters. The annual
maintenance fee for RF Mesh solution for AMI will be a small fraction (<10%) of that amount.
e. Reliability of Communication: Reliability of the cellular network in a given area depends on the user
density and when the utility wants to ping a particular meter, there is no guarantee that it will be
reachable at that moment as we often face with mobile calls not getting connected due to poor
bandwidth or network congestion. Last Gasps and First Breaths10 are to be logged by a smart meter
in case of power-off and power-on with in 20 seconds as per the SBD. When the Discom receives the
last gasp, they alert the maintenance teams on the power outage in a particular location and dispatch
the maintenance crew. This is one of the important benefits of AMI. With cellular connections, it is
9 In Uttar Pradesh, EESL deployed about 1.2 million smart meters with 3G during the period 2018 to 2020; and the telecom service
provider discontinued 3G service in UP. These meters are now operating on 2G as a fallback arrangement. New installations are on
4G; but future of 4G is uncertain as at some point, Telcos will stop 4G when 5G penetration achieve certain level of nation-wide
coverage
10 Last Gasp is the message of power outage communicated by a smart meter to the Discom; similarly, First Breath is the message
communicated to the Discom when power supply is resumed. Per SBD for RDSS, both Last Gasp and First Breath should be
communicated with in 20 seconds of the events. HES need to be programmed to act differently when one meter sends the last gasp
and when a large group of meters send the last gasp – if there is a power outage in a large community, thousands of meters will
send last gasp messages which the communication bandwidth may not be able to handle; and in such cases only select few meters
including the feeder/distribution transformer meters may be prioritized to transmit the last gasp. Such use cases should be
configured in the HES

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almost impossible for last gasps to be communicated to the Discoms within 20 seconds of a power
outage. There are steep penalties for not meeting these SLAs in the SBD.
f. AMI Benefits: There are 16 benefits11 to a Discom from smart metering and many of the high-impact
and high-value benefits may not be available if utility cannot reach a meter when required as is the
case often with cellular communication.
g. Standards for RF Mesh: The equipment deployed for RF Mesh for smart metering conforms to
standards such as ITU, IEC, IEEE, CEN/CENELEC/ETSI, NIST, ANSI, Wi-SUN etc. The security technologies
are same for equipment deployed in licensed and license-free spectrums. It is a frivolous argument to
suggest that conducting important banking, social, financial, and essential exchanges over Wi-Fi –
which is also local RF is unsafe. The security of these transactions relies on the built-in transmission
layer protocols, not the specific choice, ownership, or frequency of radio waves. It is important to
understand that the frequency of radio transmission impacts the propagation, but it does not impact
the security of data. Therefore, the public telecommunications infrastructure is vulnerable to a
greater number of threats and vulnerabilities.
h. Equipment Registrations: All equipment deployed in wireless networks whether in licensed spectrum
or license-free spectrum must be tested and registered with Wireless Planning Committee (WPC).
There is no technical reason for equipment deployed in license-free spectrum to be inferior than those
used in the licensed spectrum by the cellular operators. The experience with hundreds of millions of
wireless devices deployed in the license-free spectrum have been working satisfactorily around the
globe for a variety of IoT applications including smart metering. Hence, the argument by the COAI is
baseless and is driven purely by profit motive alone – not in the national interest.
RF Mesh solution providers should register with the Department of Telecommunications (DOT). The details
about the M2M Service Providers Guidelines published by DOT can be found on the website of DOT12. It is
recommended to include this in the SBD.
More recently, the telecom service providers have approached MOP (and REC which is the nodal agency for
the SBD) through Telecom Standards Development Society of India (TSDSI) to make changes in the SBD and
IS:16444 and IS:15959 so that cellular operators can meet the SLAs. This is another attempt of the telecom
operators to hijack the ongoing AMI rollout. They want to relax the standards so that their technologies (4G
and NBIoT) could meet the SLAs prescribed in the SBD. These attempts by the telecom operators must be
rejected.
4 BENEFITS OF AMI TO DIFFERENT STAKEHOLDERS 4 B
As indicated in the beginning, AMI is not just to improve the metering and billing processes in a Discom. The
impact of AMI on the overall utility operations is much more as described in the table below. Several of the
benefits from AMI system depends on the reliability of the communication system deployed.
11 The 16 benefits to the Discoms and benefits to other stakeholders are presented in the Section- 4 of this paper
12The details about the M2M communication equipment registration can be accessed here:
https://dot.gov.in/sites/default/files/M2MSP%20Guidelines%20.pdf?download=1

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Dependence on
Sl Financial
Benefits Communication
No Impact
Technology
A. Benefits to Discoms
Reduced metering reading and data entry cost
Without smart meters, Utilities must send personnel to customer
premises to manually read the meter. Implementation of AMI enables
1 remote meter reading both regularly and on-demand. Data entry and Medium Low
processing is performed automatically. Overall, AMI should deliver
greater convenience at reduced cost relative to traditional meter
reading.
Reduction in time taken for meter reading and bill generation as well
as reduction in errors
There are always chances of human errors when meters are read
2 manually or even via automatic hand-held devices. In addition, the Medium Medium
process is time consuming. By delivering meter data automatically over
communication networks, AMI eliminates human error from the meter
reading process as well as make the entire process faster.
Reduction in cost of disconnection and re-connection as it can be

3 Medium Medium
managed through remote operation of the AMI system
Faster detection of dead meters and hence enhanced revenue
4 protection High Medium
Enhanced Revenue per Month

Large share of meters existing in DISCOMs are old and hence the
readings are not very reliable. With new smart meters, the accurate
energy consumption can be captured which will enhance the monthly
revenue considerably. It is expected that the monthly payment to AMI
5 Service Provider (AMISP) can be met from the increased revenue. This High Low
has been the experience in DISCOMs where AMI has been implemented
(eg: Mysore, Indore, Gujarat, NDMC, Bihar). With 15% grant from GOI,
and the rest 85% paid monthly over 10 years from increased revenue on
a monthly basis is a very attractive option for Discoms
Reduction in Aggregate Technical & Commercial (AT&C) losses
AMI can remotely detect meter tampering and enable real time energy
accounting. This reduces theft through by-passing the meter, thereby
6 High Medium
substantially reducing aggregate technical and commercial (AT&C)
losses. AMI will also streamline the billing, or meter-to-cash process
considerably by reducing the human errors in meter reading and billing
Enabling faster outage detection and service restoration after faults
Traditionally utilities know about an outage only when they receive

7 complaints from affected customers. Service restoration requires utility High High
crews to identify the area and rectify the fault – a time consuming and
expensive process. The Bureau of Indian Standards requires all smart

Page No | 10
meters to be capable of sending ‘last gasp’ and ‘first breath’ messages,
which informs the utilities when power has failed or resumed. This will
reduce outage restoration times leading to financial savings and
improved customer satisfaction.
Better load research and demand forecasting from AMI data can
reduce power purchase cost
With meter data time stamped at 15-minute intervals, AMI enables near
real-time estimation of customer demand and understand customer’s
power consumption in granular detail. This improves DISCOM’s load
8 High High
forecasting and enhances the ability to procure the right volumes of
power. Utility can also implement time-of-use (ToU) tariffs for different
categories of customers and encourage load shifting with demand
response programs. These measures could reduce peak load and hence
reduce purchase of expensive power during the peak hours.
Power quality measurement and management
Smart meters are capable of measuring specific aspects in near real-

time, such as power factor, over or under voltage, and over current. This
9 helps DISCOM to enhance system power quality in conjunction with Medium Low
power quality data from other sources. Improved power quality also
leads to lower power losses. Also, avoid costs associated with
investigation of voltage complaints.
Asset optimization
AMI data supports granular monitoring of power flows on the

distribution network which can help DISCOM identify segments of over-
and under-loading. This is valuable information for system planning and
optimizing network upgrades. AMI data can also help balance load,
10 High High
which reduces power losses. Better visibility of loading on the power
system will help faster/delayed capacity enhancement and prevention
of failure/under-utilization of equipment. Furthermore, network
monitoring can decrease equipment failure rate by identifying phase
imbalances and over loading in advance which can be corrected.
11 Ability to operate in pre-paid and post-paid modes Medium High

Remote operations
Smart meters typically include remote switching, which allows utilities

12 to remotely disconnect or reconnect where necessary, such as when load Medium High
is exceeded, for predetermined events, in the case of non-payment, or
when a customer moves. Additionally, Discoms can monitor the health
of the meter and dispatch maintenance only where necessary
Improvement in reliability indices and its accurate measurement
13 Enhanced monitoring of the distribution network operations would Medium Medium

significantly improve the reliability indices like CAIDI/CAIFI, SAIDI/SAIFI
as well as help measure these indices accurately
14 Real time energy auditing and accurate energy accounting from time- High High

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stamped meter data
15 Reduced load on call centres, customer care centres and billing centres Medium Low
Smart meters act as feedback points for understanding the behavioural
16 interpretations of energy demand as consumption which can be Low Low
modified
B. Benefits to Generation and Transmission Companies

1 Deferred or avoided transmission capacity investments High Medium
Deferred or avoided generation capacity investments on peak load
2 plants and spinning reserves High Medium
C. Benefits to Customers
1 Error-free bills and no need for visiting billing centers Medium Low
2 Innovative tariff schemes Medium Medium
3 Faster restoration in case of outages High High
4 Remote control of loads in customer premises High High
5 Ability to remotely manage and control appliances Medium Medium
6 Potential to save money Medium Medium

D. Benefits to Society
Reduction in carbon footprint owing to avoided travel by Discom
1 personnel for meter reading, disconnection, and reconnection Medium Medium
Better customer engagement on energy conservation and demand side

2 management initiatives Medium Medium
3 Enhanced customer satisfaction Medium Medium
4 Energy efficiency and energy conservation Medium Medium
5 CYBER SECURITY OF THE AMI SYSTEM 5

With 250 million smart meters having two-way communication facility with the Discom’s systems, 250
million more entry points to the utility network will be created. This increases the vulnerability and the
potential for cyber-attacks. The possible attacks are:
▪ Bad data injection

▪ Spoofing
▪ Man-in-the-middle-attack
▪ Decryption attacks
▪ Energy theft attacks
▪ Distributed denial of services (DDoS)

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Hence, cyber security in AMI is very critical to ensure the robust security of the power system. Security
breaches in smart meters/AMI systems can lead to revenue loss, consumer data misuse, and potential
blackouts, affecting critical infrastructure and other sectors. The AMI system should address cyber security
requirements and conformance at four levels: manufacturer/vendor security certifications,
device/equipment/component level security conformance certifications, asset owner/utility security
certifications, and operator/staff handling critical infrastructure operations certifications.
AMISPs should partner with best-in-class solution providers having standards-based security solutions. Key
standards include the NIST, NERC and ISO/IEC family of standards - ISO/IEC 27001, 27002, 27019 and 27035.
India has developed its own cyber security standards IS:1633513, focusing on operational technology (OT) in
the power sector. Smart meter standards IS:16444 and IS:15959, along with IEC:62056 series, define
communication protocols and associated security. IEC:62443 and IEC 62351 standards define the
compliances for cyber security for electrotechnical equipment and automation systems. In December 2021,
CEA issued Cyber Security Guidelines for Power Systems14 which should be followed by Discoms and the
AMISPs. Periodic security auditing, conformance testing of smart meters and devices, and cyber-security
lifecycle testing are essential to maintain compliance. Training the personnel associated with critical
infrastructure assets is important to enhance cyber security. Cyber-physical test beds need to be created to
test individual devices in integrated environments.
Some of the general security practices from the experiences of utilities who have implemented large scale
AMI in North America and Europe are summarized below for the considerations of Discoms and AMISPs.
a. Threats from Outside and Inside: Smart meters can be hacked by accessing onboard memory,
thereby reading diagnostic ports and other network interfaces. Besides, cyber criminals, employees
and vendors can unknowingly (or even knowingly) release sensitive information. To prevent such
attacks, utilities should impose intelligent controls on how employees, consumers and partners
access applications and data.
b. Security Principles: The global industry standard is the Confidentiality, Integrity and Availability - CIA
model of security. For AMI systems, Authentication must be added to this CIA model. Confidentiality
is to prevent sensitive data from reaching wrong people while ensuring that the right people still
have access. Integrity means data is consistent, accurate and trustworthy over the entire lifecycle;
and unauthorized people cannot alter data. This requires strong cryptographic mechanisms to ensure
the integrity of meter readings, command and control of the data. Availability of data and equipment
must be ensured by rigorous maintenance of hardware, prompt repairs; and upkeep of the software
free of corruption and conflicts. Firewalls and proxy servers could prevent downtime and mitigate
malicious actions such as denial of service (DoS) attacks. Authentication is to prevent unauthorized
access which happens often due to unmodified default access policies or lack of clearly defined access
policy documentation. Utilities must ensure that only authorized personnel can view information and
perform permitted actions. The HES, the field-tools and network devices must be deployed with
13IS:16335 is presently under revision and the updated version may be issued by end of 2023
14CEA’s Cyber Security Guidelines for Power Systems: https://cea.nic.in/wp-
content/uploads/notification/2021/10/Guidelines_on_Cyber_Security_in_Power_Sector_2021-2.pdf

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certified Root of Trust15. In the absence of a proper authentication system, a malicious attacker could
attempt to spoof themselves as an HES, a field-tool or a network device and attempt to send illicit
command or inject malicious code in to the network.
c. People and Process: Insider attack is a key area of risk whether accidental or intentional. While an
outsider may be attempting to breach HES security which is being resisted by the system, it should
ensure that assigned employees are given legitimate access to the system. HES with role-based
access control (RBAC) may be deployed to provide capabilities to the Security Administrator to assign
appropriate permissions to each user of the system. HES could streamline user administration by
integrating with enterprise single sign-on solutions.
d. Data Protection: Meter data, customer billing information and other important data to be encrypted
end-to-end for maximum protection whether it is in a public or private cloud, on a device or in transit.
The end-to-end encryption help to combat advanced threats and maintaining regulatory compliance.
e. Advanced Security: Advanced security solutions should include signed and verified firmware,
disabled JTAG16-debug communications interface, encrypted flash memory, locked optical ports
(configurable), meter tamper detection, backhaul protection, certified root of trust; and other
physical and system level security features.
f. Key Management: The security solution must provide encryption key segmentation at individual and
group levels. Each end point (meters, DCU/gateway) is to generate its own AES 256-bit encryption
key to encrypt upstream and downstream messages sent to and from each end point. All the
individual keys of end points are vaulted in a Key Manager. HES can assign segment keys to a group
of end points. Device specific keys (protected through encryption) are stored securely during system
use and during rest. Device specific keys and network specific keys should follow configurable and
matured key rolling and lifecycle management processes.
g. Firmware Integrity: All firmware upgrades released are digitally signed using the utility’s private
key. Each end point within the network will validate the signature using the public key provided by
the HES. In case of signature mismatch, the end points will not upgrade the firmware.
h. Message Authentication: All commands may be signed with ECDSA17 standard using utility’s
private key. End points will execute signature validation before acting on any command, thus
providing a control mechanism to prevent rogue commands or man-in-the-middle vulnerability.
i. Third Party Penetration Testing: Utilities should engage certified third parties for penetration testing
to identify vulnerabilities and fix them periodically.
A comprehensive cyber security approach is crucial to safeguard the AMI system. For establishing secure and
15 Root of trust is ensured through Hardware Security Modules (HSM) where the Utility’s private key (encryption key) is vaulted
16
Joint Test Action Group (JTAG) is an industry standard for verifying and testing printed circuit boards after manufacture. It gives a
pins-out view from one IC pad to another so that faults could be discovered. JTAG became the IEEE 1149.1 standard in 1990.
17
Elliptic Curve Digital Signature Algorithm (ECDSA) is a variant of the Digital Signature Algorithm (DSA) which uses Elliptic-Curve
Cryptography (ECC). ECC uses much smaller public keys compared to the other popular encryption methodology called RSA. For AES
128 encryption, the ECC key is 256 bits whereas RSA key is 3072 bits; and for AES 256 level encryption, the ECC key is 512 bits (64
bytes of 8 bits each) while RSA key is 15360 bits. ECC needs much lower processing power and gives faster SSL handshaking and
consequently faster web page loading.

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resilient AMI systems, a standardized cybersecurity framework should be adopted by the AMISP in
consultation with the Discom and other stakeholders. These steps are prescribed in detail in the SBD Section
2.7.7. Some of the key actions that AMISPs should adhere to make the entire AMI system immune to cyber-
attacks are reproduced from the SBD below:
a) All the hardware, operating systems and application software should be hardened
b) Application, scanning and hardware scanning tools should be provided to identify vulnerability and
security threats
c) Data should be encrypted at system/device/technology level
d) Network zoning should be implemented as per the proposed architecture (or other methods of
network architecture without compromising the security of the system)
e) Internal users should be allowed to access all adjacent zones - they will not have access to remote
network zone
f) While procuring cyber security items testing must be done and the system must be secure by design
g) Residual information risk should be calculated by AMISP and same should be submitted to the
Discom for approval
h) All default user ID and passwords should be changed
i) All log in/out and cable plugs in/ out should also be logged in Central Syslog Server
j) Penetration and vulnerability assessment test by CERT-IN certified auditors during SAT and operation
and maintenance period
k) Auditing by third party during SAT and annually during operations and maintenance period should
be in the scope of AMISP18
l) As the computer system in NOMC (SMOC) has access to external environment, the AMISP should
document and implement Cyber Security Policy/Plan in association with the Discom to secure the
system
m) Discoms and AMISPs to follow the latest Cyber Security Guidelines issued by CERT-In
(http://www.cert-in.org.in/); and the provisions under “Testing of all equipment, components, and
parts imported for use in the Power Supply System and Network in the country to check for any
kind of embedded malware /trojans/ cyber threat and for adherence to Indian Standards –
Regarding” vide rder o. o.9 6 0 6-Trans-Part(2) issued by MOP on 18 November 2020 and
amended from time to time or any other competent authority
n) AMISP should adhere with the appropriate security algorithm for encryption and decryption as per
established cyber security guidelines. For smooth functioning of the entire system, it is essential that
the AMISP shall provide in the form of a document enough details of such algorithm including the
mechanism of security key generation to the Discoms. In case of proprietary or secret mechanism,
the same shall be kept in a secured escrow account.
Similarly, Section 2.7.8 of the SBD prescribes the measures to be adopted for data privacy and data security.
AMISPs should ensure that the system is compliant with the applicable provisions of the “Reasonable security
practices and procedures and sensitive personal data or information Rules, 2011 (IT Act ” as well as should
be committed to work with Discoms for compliance to personal data protection requirements. The Discom
should be the sole custodian of the smart meter data19. The AMISP and its contracted vendors will have
18 We hope all Discoms have incorporated these clauses in their RFPs and contracts
19 By law many countries have established that the consumer is the sole owner of the smart meter data; and Discom is the custodian

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limited need-based access to the data20. AM is re uired to prepare and submit a “ rivacy by Design”
document to the Discom which details out all the policies, practices, processes, and technologies deployed
to manage, and process the smart meter data in a secure manner; including the details on methods of
anonymization applied to the personal smart meter data for Aggregated Data, Anonymized Data and
Personal Data.
SBD Section 2.2.3 describes the measures for Network Protection and Security; and section 7.4.1 mandates
that the AMISP should be responsible for monitoring of the system from a cyber-security perspective. The
logs of the system shall be analyzed for exceptions and the possible incident of intrusion/trespass should be
informed to the Discom and analyzed to discover the root cause. The monitoring should encompass all cyber
security devices installed in the cloud data center as well as at the NOMC (SMOC) such as firewalls, all types
of intrusion prevention systems, routers etc. The cyber security system should also be subjected to Annual
Security Audit from CERT-In approved auditors at the cost of the AMISP during the contract period. AMISP
should share with Discom such audit reports and implement the recommendations/remedial actions
suggested by the Auditor. Again, we are afraid whether all the AMISPs who are bidding in different Discoms
have any idea about what it takes to comply with the above provisions in the SBD related to cyber security.
Telecom Engineering Center (TEC) under the Department of Telecoms (DOT) has published the Technical
Report on Security by Design for IoT Devices Manufacturers (TEC 31328: 2023)21. AMISPs and their project
partners may be mandated to study and comply with these procedures as well. REC may consider adding this
provision in the SBD.
6 AMI ROLLOUT STARTEGY AND IMPLEMENTATION METHODOLOGY
As part of R-APDRP, 14 Discoms in India were allotted smart grid pilot projects in 2013. Out which only 11
projects have been completed and all these projects had smart metering ranging from 1200 to 30000
customers. Most of these projects took 4-5 years to implement. Having observed the trials and tribulations
of Discoms with these first set of smart metering projects, ISGF was convinced that the state government
owned Discoms will not be able to procure right AMI systems; and even if they install the right systems, they
will not be able to maintain it for ten years. ISGF published a White Paper in 2016 (which was re-issued in
March 2017 as a joint paper by ISGF and BNEF) that articulated the idea of engaging a Metering Services
Agency (MSA) who will install the AMI system and maintain it for 10 years for a monthly fee per meter. This
is the same business model which is adopted for the 250 million smart metering projects under RDSS. Only
difference is that under RDSS, GOI is giving 15% of the project cost as a grant; and the rest is paid in monthly
installments over 93 months. In our original paper we estimated the cost of a single-phase smart meter at
INR 2250 and the MSA service fee at INR 69 per meter per month for ten years for a project with one million
(or more) meters, which was about one US dollar per meter per month in those days. Today under RDSS, the
average price being quoted by AMISPs is about INR 80 per meter per month for 93 months (which is about
one US dollar).
20 AMISP should commit to ensuring that the data is kept safe by them and their sub-contractors/project partners and not used for
any other purpose
21 https://tec.gov.in/pdf/M2M/Security%20by%20Design%20for%20IoT%20Device%20Manufacturers.pdf

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There are several key issues that needs re-examination in the ongoing program as described below.
a. Is it appropriate to go for 100 % prepaid meters in the country?
In our opinion this is neither practical nor logical to have 250 million smart meters operating in the
prepayment mode. In most Discoms, the high-value customers contribute 70-80% of the revenue who may
be only 15-20% in numbers; and majority of them pay several million rupees per month22. Moving them to
prepayment mode will have commercial and technical challenges. Regular customers who consume above
500 kWh per month (or an appropriate limit set by the state regulator) may be allowed to opt for either post-
paid or pre-paid modes. Those opting for pre-paid in this category may be offered a small rebate to motivate
them. All customers with less than 500 kWh monthly consumption and government offices may be brought
under mandatory prepayment mode. Even their numbers may be in millions in most Discoms.
The smart meters can be configured in either prepaid or post-paid mode. But the trouble with prepayment
operation of smart meters is that most of the HES are not designed to respond to a large number of
disconnect/reconnect requests in less than ten minutes as prescribed in the SBD. If thousands of customers
recharge their meters online, immediately a reconnect order will be generated by the system; but it will get
into a que in the HES – particularly when HES has already issued a command to download the interval read
of millions of meters. In this scenario, the recharge may be updated and electricity supply resumed after few
hours. This can be fixed to certain extent by modifying the HES provided the communication system is
reliable; but most of them would still find it difficult to meet the SLA of ten minutes to reconnect supply after
recharge.
Each Discom in consultation with their state government and respective electricity regulatory commission
may decide what all categories of customers in which all regions should be brought under prepayment mode.
MOP may allow the states to take this decision as appropriate. Afterall, the net-grant from GOI for AMI under
RDSS is only 6% of the project cost23.
b. What is the right price range for the AMI projects?
It is understood that when the RDSS program was launched, the project cost was calculated at INR 6000 per
meter and accordingly the 15% GOI grant was capped at INR 900 per meter. There is confusion about this
number while one argument is that this amount of INR 6000 was the capex cost under the EPC model of
project implementation; while the other argument is that it was the life-cycle cost of AMI implementation
that EESL offered in UP and Haryana in 2017 which was for 6 years (72 monthly installments versus the 93
monthly installments in RDSS). In our view, the life-cycle cost needs to be revised to the range of INR 9000 to
12000 per meter depending on the geographical challenges and the total number of meters involved. The
prices could be higher for very low volume contract packages (below 200,000 meters) as well as for very high-
volume contract packages (above 5 million meters)24.
22 Large C&I customers have HT or LT-CT meters which have no built-in switch for disconnect-reconnect operations; and hence
cannot be moved to prepayment mode
23
GOI is offering 15% grant under RDSS for smart metering; but collects 18% GST on the project cost including the monthly
installments. Out of this 50% is passed on to the state governments; hence the net-grant from GOI for smart metering is only 6% of
the project cost
24
For a project with 5 million meters, even 1% of the meters that cannot be read in a month will be about 50,000 and manually

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c. Who should bear the monthly installments to be paid to the AMISPs?
This is another big question haunting the decision makers in the states. In some states the Discoms have
approached their regulators for a pass-through in the tariff for the monthly installments. Their argument is
that in the initial years Discoms may not be able to bear the additional burden of the monthly installments
to be paid to the AMISPs as it would take few years to realize the full benefits of the AMI system; and such
efficiency gains when realized will be passed on to the customers in tariff relief. If adopted, this approach will
place a huge burden on low-income communities whose electricity bills are in the range of INR 200-300 per
month which will go up by another INR 80-100 per month. The promised tariff reductions after a few years
will not motivate them to get their buy-in for the AMI program. In some states where the existing metering
and billing systems are in poor condition, the benefits of AMI can be realized right from the very beginning
through increased revenue per month which itself will take care of the monthly installments25.
We suggest to offset this monthly fee by dividing it in to 3 buckets – one part may be added to the meter
rent that all Discoms levy in the electricity bills; another part may be borne by the Discoms and the third part
may be funded through a low-interest loan from REC/PFC which may be paid back from the efficiency gains.
The percentage of each of these 3 parts may be decided by each Discom in consultation with their
governments and regulators.
d. What is the appropriate AMI rollout strategy?
Ideally, AMI rollout should start with one city/division in a Discom which has about 1 million meters. This first
contract package should have MDM and system integration components; and the system integrator (SI)
should successfully integrate the MDM with the billing system and other applications and test it. Once the
backend systems are stabilized and the first batch of meters (>100,000) can be read remotely and the
monthly bills can be generated (without human interventions), the Discom should engage multiple agencies
to rollout the smart meters in other cities/divisions. Those new contract packages should have smart meters,
communication, and HES (no MDM). The responsibility for integration of the new HES with the MDM should
be under the scope of the SI of the first contract package.
We recommend a three-phase rollout – first in the pilot city with about 1 million meters, next in all other
urban and semi-urban areas; and lastly extend to the rural areas. This approach gives time to the Discoms to
extend their billing system to non-RAPRDRP towns and rural areas that are still having multiple billing
systems. AMI implementation may not be feasible in several hamlets and habitations in the hill areas and
tribal communities in the forests. Discoms may be allowed to decide which are the pockets/communities
where AMI is not feasible. In such cases, Discoms may install smart meters for feeders (wherever feasible)
and monitor the community’s consumption to prevent misuse.
Some of the Discoms are making changes in qualifying requirements, SLAs and other important parameters
specified in the SBD. These are primarily vendor driven. REC and PFC (MOP) should stop such changes in
reading them in a diverse geography will be very expensive; and these unreadable meters are not the same every month
25
In one of the states, it was estimated that the average revenue growth after AMI implementation was above INR 200 per month
per customer while the monthly installments to the AMISP was well below INR 100 per meter per month

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tender conditions and specifications to favor select vendors and OEMs at Discom level to prevent
cartelization and cost escalation.
In our observation, the preparedness of Discoms for large scale AMI rollout is still lacking in almost all states.
Many states do not have a single Discom-wide billing system which is a prerequisite for successful AMI
deployment. Home grown billing systems that exist in several states may not be easy to integrate with
standard MDMs. Too much of customization of the MDM will diminish its true potential; and prove to be too
expensive to maintain in the long run. Discoms do not regularly update their GIS maps with customer
indexing. Also changes in the field are not communicated to GIS team hence even after the consumer
indexing is done the data mismatch appears. Adequate manpower and other resource constraints continue
to haunt the Discoms. These issues need to be addressed on priority to reap the benefits of the AMI system.
e. Life of Smart Meters
What should be the ideal life of smart meters? As per the BIS certificates issued to the meter manufacturers
it is mentioned that 5½ years of warranty from the date of delivery or 5 years of warranty after the meter is
installed. Hence, typically meter OEMs in India have been giving 5 years warranty. Now for the RDSS projects,
most of the OEMs are offering up to 10 years warranty.
Utilities in USA and Europe mandates minimum 12-15 years life for meters. This is one way of reducing the
overall cost of smart metering. One issue that could hamper long life of smart meters in India is the battery
life26 in high ambient temperatures.
We recommend that BIS amend the certification with minimum 10 years warranty; and mandate highly
accelerated life test (HALT) for meter-life expectancy testing in India.
f. Training and Capacity Building in Discoms and Industry
In general, very few agencies in the country understand the complexity in installing multi-million-meter AMI
systems and maintaining them for nearly 8 years (93 months as per SBD). AMISPs with no prior experience
of smart metering are signing up for implementing 5-6 million smart meters in 28 months! Most of the
Discoms and AMISPs do not seem to be taking any serious efforts to train their engineers in AMI.
This reminds us of the R-APDRP Part-A projects that were awarded by Discoms during 2008-2012. There was
a set of System Integrators (SI) who were empaneled by PFC – mostly large IT companies, both domestic and
foreign. The project implementation time specified was 18 months. R-APDRP Part-A scope included indexing
of Discom’s assets and consumers in 4 towns on the maps which required thousands of trained
technicians who could handle DGPS equipment (which was the only way to do GIS mapping those days); and
there were not even few hundred trained technicians in India at that point in time. Hence, all foreign IT
companies stayed away from bidding for R-APDRP projects. Large Indian IT majors competed aggressively
and signed up to execute projects within 18 months at prices way lower than the amounts budgeted by MOP.
However, all R-APDRP projects took 5-7 years to complete; and all the Indian IT companies who executed
those projects incurred huge financial losses. None of them are participating in the ongoing AMI project
tenders.
26All smart meters have lithium-ion batteries that lasts typically 10-12 years in moderate temperatures. At >45° centigrade
temperatures the long-life expectancy of these batteries is doubtful.

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Similar picture we are witnessing presently – AMISPs with no prior experience of multi-million-meter AMI
projects are aggressively bidding and signing up for large projects, while international companies who have
rich experience in large AMI projects are staying away and watching the scene. Majority of the empaneled
AMISPs do not have deep pockets to incur huge losses which the Indian IT majors could afford during the R-
APDRP phase. To implement 250 million AMI rollout in 50+ Discoms in next 5 years, we need several thousand
IT experts who are proficient in HES - MDM - Billing System integration which is lacking in the country
presently. None of the AMISPs have realized this shortage of talent in the market; but enthusiastically bidding
for projects which is a clear indication that they have no idea what it takes to deliver those multi-million-AMI
projects. Looking at the current situation, we foresee the scenario in which many AMISPs will fail to execute
the large projects awarded which the Discoms will have to re-tender (at much higher prices); and many
AMISPs going bankrupt!
MOP may review the situation and take appropriate measures to ensure that personnel engaged in AMI
projects from both Discoms and the industry are given proper training. The Part-C of R-APDRP had over INR
2 billion for training and capacity building; but actual spend was a minuscule portion of that. PFC engaged
agencies with no prior experience to develop training modules at very low cost. The results and experience
of R-APDRP are evident. We strongly advocate for spending minimum 5% of the project cost of the RDSS
program in training and capacity building for Discom personnel so that 95% of the investment is well spent
and the intended benefits are realized. It is high time for GOI to realize that in areas like training and capacity
building in emerging technologies where best-in-class agencies must be engaged, procurements cannot be
done on the regular L1 bid route.
g. Customer Engagement
For successful AMI rollout and customer’s participation in leveraging the full benefits of the AMI systems, it
is essential to have customer engagement in the program right from the beginning. In many countries
customer groups opposed smart metering. In USA, 15 states had to include Opt-Out option in their AMI
programs because of customer objections; and in many countries AMI rollouts were suspended mid-way and
engaged in long consultations with customer groups for their buy-in. We do not see customer engagement
activities in the ongoing AMI rollout in any of the states in India so far.
7 AMI 2.0
As stated in the beginning, Indian Discoms have the great opportunity to leapfrog to AMI 2.0 as we have done
with our mobile telephony two decades ago. The new features of AMI 2.0 which was not there in the first set
of smart metering projects are additional functionalities that can be realized at marginal cost as explained
below.
a. Advanced Analytics: The time stamped electricity consumption data captured from smart meters
can be analyzed with the help of Artificial Intelligent (AI) and Machine Learning (ML) tools to
understand the power flows in real time and identify overloaded/stressed assets; locate which
transformers to be replaced with higher capacity ones; which transformers have phase imbalance
issues that must be corrected27; detect meter tampers and irregular usage patterns; detect
27
In an AC distribution network, typically loads are segregated amongst the 3 phases based on contracted load; but in real-life, load

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theft/unmetered loads; improve connectivity models; and conduct reliability analysis, storm analysis
and momentary analysis.
b. Grid Management - Distribution Automation and Voltage Management: Modern AMI networks can
support many more devices than smart meters. Devices that add intelligence to the distribution grid
are now common place within an AMI network. These include Reclosers and Automated Switches;
Capacitors; Line Sensors and Fault Passage Indicators (FPIs); and Smart Inverters. New opportunities
for managing the distribution grid are enabled by smart meters - their voltage sensing capabilities
offers the system operators a new level of granularity in monitoring system voltage across the grid.
The smart meters typically provide RMS voltage and sag/swell alarms as warnings of voltage
concerns.
c. ADMS Integration
Integration of last gasps and first breaths with ADMS provide instant notification of outages and
restoration status. These are very useful particularly during weather events and other large
disruptions.
d. Transformer Monitoring: The AMI system can be leveraged to implement transformer monitoring
systems and get the near-real-time data of transformer performance to the Discom control room.
The alerts of over voltage/temperature could trigger advance action before the transformer
burnouts.
e. Demand Response/Demand Side Management: Smart meters often include a home automation
functionality through wireless communication (ZigBee, Wi-Fi or similar technologies). These radios
help enable demand response (DR) programs by creating connections to in-premise displays, smart
thermostats and other smart appliances. When paired with time of use (TOU) rates, the smart
devices may be programmed to react to price signals or curtailments to help manage energy during
peak periods.
f. Smart EV Charging: AMI system could support smart charging of EVs (V1G) which can control the
power flow to the chargers during peak-hours.
g. Distributed Generation: Modern smart meters are capable of recording data on several channels.
This functionality is used to support distributed generation to record several values simultaneously,
including Real Power, Reactive Power; Power Received; Power Delivered etc. These channels support
rates for solar, wind and hydro generation installations. Similar to distributed generation, AMI meters
support Energy Storage Systems through multiple channel recording and HAN communications. In
this case, the meter can become a gateway to manage both the on-site generation and the local
storage. It manages the data flow from the utility to the Distributed Energy Resources to optimally
control the use and flow of electricity.
h. Smart Street Lights: Many AMI systems now offer Smart Lighting Control solutions. Key system
functionalities include:
• Remote control and monitoring of lights
• Improved energy efficiency, via LED lights
• Individual metrology on each fixture
• More timely and efficient repair of lights
• Ability to brighten or flash lights in support of public safety
• Software allows graphical viewing and grouping of lights, measuring, and reporting of power
consumption, fixture failures and alarms, alarm mapping, on/off scheduling
• Ability to integrate Air Quality Monitoring Sensors
on one or two phases may be much higher than what was allocated; this causes overloading of the distribution transformer and it
could even lead to transformer burn-outs

Page No | 21
i. Smart Cities: The modern AMI networks can support a host of smart city applications at marginal
cost to the benefit of infrastructure services providers and customers. Some of the examples are:
• Utility integration and combined billing system for electricity, water, gas, house tax and other
municipal charges
• Smart buildings – grid integrated buildings
• Smart waste management
• Water management including leakage detection and reporting
• Assets tracking
• Smart EV charging
• Smart traffic lights, smart roads, and vehicle detection
• Smart parking
• Video surveillance and remote security monitoring
• Emergency response and mass notifications
In conclusion, we suggest Discoms and AMISPs should brainstorm and design their AMI systems such a way
that additional functionalities could be built in to the system at marginal cost which will be additional revenue
streams for both Discoms and AMISPs which will eventually reduce the burden on the electricity rate payers.
MOP or CEA may like to constitute a committee of technical experts and select utilities to review and suggest
measures to undertake a course correction in the ongoing AMI program.
8 RECYCLING OF OLD METERS
As part of the 250 million smart meter rollout, as many existing old meters (non-smart) will be taken-out
from the customer premises. The model SBD mentions that the old meters should be deposited with the
Discoms. The evolving practice on electronic and other hazardous materials recycling is through Extended
Producer Liability programs in which the producer is liable to take back the product at end of life and
recycle/reprocess it in a scientific manner without emitting or dumping of any hazardous materials in the
environment. The Battery Waste Management Rules 2022 issued by the Ministry of Environment, Forest and
Climate Change (MoEFCC) for disposal of lithium-ion batteries clearly define the responsibilities of the
producer, consumer, public waste management authorities and the recycler.
Majority of the old meters (more than 200 million) are electronic meters which need to be recycled or treated
like other electronic waste. Among the electronic meters installed in India there are two generations – old
meters produced before 2004 which have lead (Pb) in their printed circuit boards (PCB). The later versions
are lead-free. The meters with PCBs having lead is very hazardous to the environment. Both these categories
of meters need to be segregated and send for recycling/disposal. All the electronic meters have batteries
(mostly lithium-ion batteries) which also need to be taken out and recycled separately. Discoms do not have
the bandwidth to do such segregation and disposal in a scientific manner; hence this responsibility for safe
disposal of old meters may be assigned to the AMISPs or the policy makers should help creation of a recycling
industry to handle this huge task.

Page No | 22
APPENDIX - A: Potential Claim of Cellular IPR Fees for Smart Metering
As millions of smart meters connected on cellular telephone networks are deployed in India, there is a risk of
hidden cost towards IPR fees that may be claimed by the technology companies who own these IPRs in 3G,
4G, 5G, and NB IoT technologies. In the journey towards achieving smarter energy grids, it is undeniable that
cellular technologies are playing a pivotal role. Numerous Indian companies are actively developing and
deploying smart meters that rely on cellular networks to transmit data. But as the number of meters
connected on cellular networks increases, the chances of such claims by patent holders are more likely. The
complex landscape of Cellular Standards Licensing is explained here.
Understanding Cellular Standards Licensing
The process of licensing cellular standards and the associated IPR fees is very complex, but it is crucial for
businesses to understand this landscape. IP Europe (www.ipeurope.org) is combining information on
intellectual property and principles, how the licensing is managed globally, and how they are applicable to
India as well. IP Europe is supporting the CEN-CENELEC Workshop Agreement (CWA) “ rinciples and
uidance for the icensing tandard ssential atents in 5 and the nternet of hings o ”. This document
(CWA17431) describes the licensing principles of the major Standard Essential Patent (SEP) owners and how
they are exercising their IPR portfolio. The general principle is Fair, Reasonable and Non-Discriminatory
(FRAND) terms, meaning the license must be granted without discrimination towards any party. It also
defines the value of the patent which is based on its value to the (end) users. That means the cost of license
varies depending on the final use case and the value of the use case. Examples of different use cases could
vary from automotive, healthcare, energy, and the financial sectors. Following the FRAND licensing principles,
similar practices are valid for the smart metering use case which apply technologies to enable the seamless
functioning of cellular networks.
Encounters on the Global Stage
Already, we are witnessing examples of cellular IPR holders like Nokia engaging with IoT product makers who
have integrated cellular technologies into their products and therefore are entitled to collect IPR fees. Nokia
has won a case against Daimler for using cellular connectivity in automobiles which is now binding globally.
We also hear that some of the Standard Essential Patent (SEP) holders are already demanding IPR fees from
smart metering companies/utilities in Europe for deployment of smart meters with cellular connectivity. The
expectation is that similar scenarios will soon unfold in India. With the surging adoption of cellular-based
smart meters, the question of determining the value of cellular communication patents in the context of
smart metering becomes increasingly pertinent. Nokia, Ericsson, Huawei and Qualcomm are important SEP
holders in cellular, all making multi-billion-dollar annual revenue from IPR licensing.
The Significance of Cellular Communication Patents
It is important to recognize that the value of cellular communication patents in the realm of smart metering
cannot be understated. The CWA17431 document recommends engaging with the SEP holders early enough
to collect information on their demands of licensing.

Page No | 23
Incorporating IPR Costs in Business Planning
As already mentioned, Nokia, Ericsson, Huawei and Qualcomm hold majority of the patents. According to the
ETSI IPR Online Database and ABI Research analysis, roughly 172,000 3GPP/5G declarations on essentiality
have been made as of 2022, covering 51,000 unique patent families. China leads the pack for the number of
5G declared patent families. In every cellular network, multiple patents of different companies are deployed;
and each one of them can claim their IPR fee separately. So far there are no inter-company agreements for
collectively claiming IPR fee and sharing amongst these companies.
As Indian companies forge ahead with their smart meter deployment strategies, they must factor in the
potential costs associated with cellular IPR fees. Integrating these costs into business plans is not only a
prudent step but also a necessary one. By being prepared to address these fees, companies can ensure the
viability and sustainability of their smart meter initiatives and minimize potential disruptions and financial
challenges down the line.
Conclusion
The smart metering deployments are propelling India towards a greener and more intelligent energy future.
However, as the landscape evolves, it is essential for all stakeholders to recognize the significance of IPR fees
when choosing to use these technologies. By understanding the licensing processes, anticipating potential
encounters with patent holders, and factoring in IPR costs during the planning phase, companies can position
themselves for success in the rapidly evolving world of smart metering. IPR licensing fee should be considered
in overall project costing and ROI calculations by Discoms and AMISPs if they are deploying smart meters
connected on cellular networks. Ideally, AMISPs (or the communication services providers) should indemnify
the Discoms from potential claims of IPR fees by SEP Holders. In this dynamic era, staying informed,
adaptable, and strategic will be key to harnessing the full potential of smart metering while navigating the
complexities of intellectual property rights and associated fees.
APPENDIX – B: List of Utilities who have Implemented AMI and the Communication
Solutions Adopted
This list is compiled from publicly available data and may not be exhaustive and very accurate. There could
be several more utilities who would have undertaken AMI in the recent past. Most of the data in this list is
updated up to 2021.
Communication
Number of Year of Project
Sl No Utility Name Technology
Meters Execution
Deployed
A. USA
1 AEP (APCO) 1,100,000 2017 RF
2 AEP (PSO) 530,000 2014 RF
3 AEP (SWEPCO) 560,000 2020 RF
4 AEP Texas 1,041,000 2017 RF
5 Arizona Public Service 1,200,000 2012-2014 RF

Page No | 24
Communication
Meters Execution
Deployed
Accomack and Northampton Electric
6 36,931 2022 RF
(A&N)
7 Alameda Municipal Power 35,568 2020 RF
8 Alcorn County 19,354 2019 RF
9 Ameren Illinois 2,100,000 2017 RF
10 American Electric Power (AEP) 1,800,000 2010-2014 RF
11 Arizona Public Service Company 305,000 2018 RF
12 Austin Energy 450,981 2018 RF

13 Baltimore Gas and Electric 1,230,000 2010-2012 RF
14 Barbados Light and Power Company 140,000 2018 RF
15 Bartlett Electric Co-Op 13,048 2015 RF

16 Beauregard Electric 45,986 2016 RF
17 Benco Electric 20,222 2016 RF
18 CenterPoint Energy 2,400,000 2009-2012 RF
19 City of Beatrice 12,619 2017 RF
20 City of College Station 19,254 2017 RF
21 City of Grand Island Utilities 12,023 2018 RF
22 City of Oxford 19,348 2019 RF

23 City of Waterloo 13,716 2019 RF
24 Clay Electric Co-op, Inc 192,000 2019 RF
25 CLECO 317,626 2015 RF
26 Columbus Light Water 13,086 2016 RF
27 Commonwealth Edison 4,000,000 2013-2018 RF
28 Consolidated Edison 5,000,000 2017-2022 RF
29 Conway Corporation 60,286 2017 RF
30 Co Serv Electric 230,000 2018 RF
31 Cumberland EMC 102,700 2022 RF
32 Delta EPA 30,376 2016 RF
33 Dixie Electric Membership Co-Op 15,401 2017 RF
34 Dominion Energy Virginia 2,400,000 2013 RF

Page No | 25
Communication
Meters Execution
Deployed
35 Dominion Energy South Carolina 770,000 2019 RF
36 DTE Energy 2,600,000 2011-2013 RF
37 Edgecombe-Martin County EMC 12,082 2020 RF
38 El Paso Electric 400,000 2013-2014 RF
39 Empire Electric Association 17,358 2021 RF
40 Entergy 1,500,000 2012-2015 RF

41 EQUS 12,107 2020 RF
42 Eversource Energy 1,200,000 2015-2018 RF
43 FirstEnergy 1,200,000 2012-2014 RF
44 Florida Power & Light (FPL) 4,500,000 2010-2013 RF
45 Fort Loudoun Electric Co-Op 34,540 2020 RF
46 Fortis Alberta 553,035 2016 RF

47 Georgia Power 2,400,000 2012-2014 RF
48 Grand Haven Light and Power 14,577 2020 RF
49 Grayson RECC 16,223 2020 RF

50 Greystone 139,285 2019 RF
51 Habersham EMC 36,157 2020 RF
52 High Plains Power 14,983 2021 RF
53 Huntsville Utilities 180,000 2019 RF
54 Hydro Quebec 4,200,000 2016 RF
55 Idaho Power 600,000 2011-2013 RF
56 Indianapolis Power and Light 294,329 2019 RF
57 Iowa Lakes Electric Cooperative 19,813 2019 RF
58 Jacksonville Energy 495,728 2019 RF

59 Jones-Onslow EMC 78,052 2017 RF
Kansas City Power and Light
60 921,586 2018 RF
Company

Page No | 26
Communication
Meters Execution
Deployed
61 Kissimmee Utility Authority 76,907 2018 RF
62 Kosciusko REMC 19,144 2017 RF

63 Lakeview Light Power 10,341 2016 RF
64 Lawrenceburg Utility System 22,173 2021 RF
65 Lexington Electric System ASIM 23,144 2021 RF
66 Licking Valley RECC 18,434 2021 RF
67 Long Island Power Authority 816,924 2018 RF
68 Mason County PUD3 35,296 2021 RF
69 Medina Electric Coop w/GSIS 20,628 2021 RF
70 Middle Tennessee EMC 215,000 2018 RF

71 Nashville Electric Service 388,000 2018 RF
72 National Grid 1,300,000 2013-2015 RF
73 Navopache Electric Coop 43,856 2020 RF
74 Nebraska Public Power District 93,958 2020 RF
75 North Alabama Electric Co-Op 19,155 2021 RF
76 Northeast Oklahoma 42,385 2019 RF

77 Northwestern Electric 12,849 2019 RF
78 NV Energy 1,300,000 2010-2012 RF
79 Oakdale Electric Coop 18,626 2021 RF
80 Oncor Electric Delivery 3,600,000 2017 RF
81 Pacific Gas & Electric 5,300,000 2009-2013 RF
82 Peabody Municipal Light Plant 26,252 2020 RF
83 Pee Dee EMC 22,395 2020 RF
84 Pennsylvania Power and Light 1,450,000 2016 RF
85 Pepco Holdings 2,000,000 2012-2014 RF

86 Pickwick Electric 21,495 2020 RF

Page No | 27
Communication
Meters Execution
Deployed
87 Portland General Electric 900,000 2011-2013 RF
88 Poudre Valley REA,Inc. 48,047 2020 RF
89 PPL Electric Utilities 1,400,000 2013-2014 RF
90 Prairie Land Electric 25,475 2020 RF
91 Prentiss County EPA 14,315 2021 RF
Public Service Electric and Gas
92 18,696 2019 RF
Company
93 Puget Sound Energy 1,008,823 2017 RF
94 Rural Electric 13,092 2021 RF
95 Sacramento Municipal Util District 600,000 2009 RF
96 Salem Electric 20,260 2020 RF

97 Salt River Project 616,000 2016 RF
98 San Diego Gas & Electric 1,490,000 2008-2011 RF
99 Santee Cooper 150,000 2020 RF
100 Satilla REMC 60,104 2019 RF
101 Scenic Rivers Energy Co-op 16,214 2020 RF
102 Seattle City Light and Energy 451,281 2016 RF
103 Southern California Edison 5,000,000 2009-2012 RF

104 Southern Company 2,500,000 2012-2015 RF
105 Southern Pioneer Electric 34,836 2019 RF
106 Southern Power District 34,485 2018 RF
107 Tallahatchie Valley EPA 29,341 2019 RF
108 Town of Wake Forest 10,255 2020 RF
109 Trico Electric Cooperative 11,505 2021 RF
110 Tri-County Electric, Texas 110,570 2022 RF
111 Tucson Electric Power Company 160,000 2020 RF
112 United Electric Co-Op 10,634 2020 RF
113 United Illuminating Company 275,778 2017 RF
114 Unitil Energy System Inc 108,339 2018 RF

Page No | 28
Communication
Meters Execution
Deployed
115 Vernon Electric Cooperative 12,921 2021 RF
116 Victory Gridstream RF 20,344 2021 RF

WE Energies (Wisconsin Electric
117 1,829,566 2017 RF
Power Company)
118 Westar Energy 723,013 2017 RF
119 Western Cooperative Electric 12,825 2019 RF
120 Wheatland ECO 33,955 2019 RF

121 Wild Rice 20,652 2018 RF
122 WIN Energy REMC 17,923 2019 RF
123 Woodruff Electric Co-op RF 21,722 2019 RF
124 Wyandotte Municipal 16,086 2019 RF

125 Xcel Energy 3,600,000 2019 RF
126 Yampa Valley 28,370 2019 RF
127 Yellowstone Valley Electric Coop 21,825 2019 RF
128 Black Hills Electric Cooperative ASIM 14,846 2019 PLC
129 Central Texas Electric COOP 37,874 2018 PLC
130 Cherokee County Electric Co-op 22,404 2018 PLC
131 Cherokee Electric Co-op 25,404 2017 PLC

132 City of Farmington 17,062 2018 PLC
133 Claverack REC 19,346 2018 PLC
134 Continental Divide 15,902 2021 PLC
135 Consumers Energy 3,800,000 2011 PLC
136 Fortis Alberta Test 3 668,305 2020 PLC
137 Garkane Energy 114,375 2021 PLC
Hamilton County Electric
138 119,383 2020 PLC
Cooperative
139 Heart of Texas Electric Cooperative 122,369 2021 PLC

Page No | 29
Communication
Meters Execution
Deployed
140 Hawaii Electric Light Company 110,214 2021 PLC

141 Inter-County Energy Coop 129,821 2021 PLC
142 Jemez Mountains Electric Coop 29,083 2021 PLC
Magnolia Electrical Power

143 32,768 2021 PLC
Association
Meriwether Lewis Electric
144 36,702 2020 PLC
Cooperative
145 Mission Valley Power 20,464 2020 PLC
146 Newberry Electric 14,109 2020 PLC
147 New-Mac Electric Coop 19,047 2021 PLC
148 Northern Lights Electric Cooperative 21,441 2021 PLC
149 Southern Pine Electric 16,580 2021 PLC

150 Tri-County Electric MO 53,886 2020 PLC
151 Tri-State EMC 20,821 2020 PLC
152 Vera Water and Power 12,538 2021 PLC
153 Blue Grass Energy 68,637 2021 RF and PLC
154 Blue Ridge Mountain EMC 156,620 2021 RF and PLC
155 Brainerd Public Utilities 111,941 2021 RF and PLC
156 Central EMC 123,676 2020 RF and PLC
157 Central Georgia EMC 168,566 2020 RF and PLC
158 CHELCO 259,900 2019 RF and PLC
159 City of Springville 112,699 2021 RF and PLC
160 Clark Energy Cooperative 128,553 2021 RF and PLC
161 Coast Electric Power Assn. 88,021 2022 RF and PLC
162 Concordia Electric Coop 15,129 2022 RF and PLC
163 Cornhuskers PPD 13,465 2021 RF and PLC
164 Crawford Electric Co-Op 22,863 2020 RF and PLC
165 Duke Energy 10,000,000 2010-2014 RF and PLC
166 Dunn Energy Coop 11,847 2021 RF and PLC
167 FortisAlberta Test 553,054 2016 RF and PLC
168 Lorain-Medina REC Inc 30,799 2021 RF and PLC

Page No | 30
Communication
Meters Execution
Deployed
169 Mille Lacs Energy Cooperative 19,989 2021 RF and PLC
170 Monroe County EPA 12,728 2021 RF and PLC
171 Mountain Electric Cooperative 36,595 2020 RF and PLC
172 Natchez Trace Electric 16,728 2021 RF and PLC
173 Northeast Louisiana Power 18,771 2021 RF and PLC
174 Piedmont EMC 41,745 2019 RF and PLC

175 Riverland Energy 21,475 2019 RF and PLC
176 Rolling Hills 11,910 2020 RF and PLC
177 Roseau Electric Cooperative 13,192 2020 RF and PLC
178 South Alabama Elec Co-op 18,838 2020 RF and PLC

179 Steele Waseca 11,842 2021 RF and PLC
180 Sulphur Springs Valley Electric 54,591 2019 RF and PLC
181 Tallapoosa River Electric Co-op 28,680 2019 RF and PLC
182 Tishomingo County EPA 14,239 2020 RF and PLC

183 Tombigbee EPA 45,694 2018 RF and PLC
184 Wood County Electric Co-Op 39,313 2019 RF and PLC
185 Yazoo Valley Electric Power Assn. 10,561 2020 RF and PLC
Total 103,827,999
B. Canada
1 ATCO Electric 100,000 2020 RF
2 Alectra 1,000,000 2023-2026 RF
3 BC Hydro 1,800,000 2011-2013 RF
4 Enmax 400,000 2011-2014 RF

5 EPCOR 5,250,000 2016 RF
6 Fortis Alberta 500,000 2012-2015 RF

Page No | 31
Communication
Meters Execution
Deployed
7 Hydro One 1,300,000 2010-2012 RF
8 Manitoba Hydro 500,000 2012-2014 RF
9 Newfoundland Power 2,500,000 2015-2017 RF
10 Toronto Hydro 700,000 2010-2012 RF
11 SaskPower 500,000 2014-2017 RF
12 Hydro-Quebec 3,800,000 2013-2017 PLC
Total 183,50,000
C. Mexico
1 CFE 1,100,000 2012-2015 RF
2 Echelon 50,000 2012-2013 RF
3 Elster 50,000 2013-2014 RF
4 IUSA 100,000 2012-2014 RF
Total 1,300,000
D. Italy
1 A2A 1,400,000 2010-2017 PLC
2 ACEA 1,600,000 2010-2017 PLC
3 Enel Distribuzione 32,000,000 2003-2017 PLC
4 1,000,000 2016 RF and PLC
Italy (other utilities)
5 1,320,000 2020 Cellular
Total 37,320,000
E. France
1 GRDF (Gas) 11,000,000 2016-2022 RF
2 Enedis 35,000,000 2010-2021 PLC
900,000 2020 Cellular
3 France (other utilities)
1,220,000 2021 Cellular
Total 48,120,000
F. Spain
1 Gas Natural Fenosa 1,700,000 2013-2020 RF
2 Endesa 13,000,000 2015-2018 PLC
3 Iberdrola 10,300,000 2010-2018 PLC
710,000 2017 Cellular
4 Spain
50,000 2020 Cellular
Total 25,760,000
G. Sweden

Page No | 32
Communication
Meters Execution
Deployed
630,000 2020 RF
1 Sweden
1,160,000 2019 RF
2 Bjäre Kraft 14,000 2022 RF
3 Bodens Energi Nät 17,000 2021 RF
DSOs in Kalmar, Oskarshamn,

4 44,000 2021 RF
Borgholm and Ålem
5 Energy utilities in Karlstad 35,000 2021 RF
6 Eskilstuna Strängnäs Energi & Miljö 65,000 2019 RF
7 Halmstad 44,000 2019 RF

8 Härjeåns Nät 22,000 2019 RF
9 Jönköping Energi 56,000 2020 RF
10 orrtälje nergi’s energy 16,000 2019 RF

11 Oskarshamn Energi 12,000 2020 RF
12 Tekniska verken 95,000 2020 RF
13 Sweden 1,520,000 2020 PLC
670,000 2019 Cellular
14 Sweden
1,710,000 2020 Cellular
15 E. ON 600,000 2009-2014 RF
16 Fortum 500,000 2009-2014 RF
17 Vattenfall 900,000 2009-2014 RF
Total 8,110,000
H. Finland
1 Finland 480,000 2021 RF
2 Helen 120,000 2022 RF
3 Haukiputaan Sähköosuuskunta 10,000 2021 RF
4 Iin Energia 5,000 2022 RF

5 Vantaa Energy Electricity 180,000 2022 RF
6 Finland 2,240,000 2020 PLC
7 Finland 500,000 2020 Cellular

Page No | 33
Communication
Meters Execution
Deployed
370,000 2020 Cellular
8 Caruna 700,000 2013-2016 RF and Cellular
9 Elenia 400,000 2013-2016 RF and Cellular
10 Fortum 600,000 2013-2016 RF and Cellular
Total 5,605,000
I. Germany
1 E. ON 160,000 2019 PLC
Total 160,000
J. Portugal
1 EDP Distribuição 6,100,000 2011-2021 PLC and Cellular
Total 6,100,000
K. Belgium
1 Belgium
1,700,000 2020 Cellular
2 Fluvius 4,100,000 2019-Ongoing RF and PLC
3 ORES 2,900,000 20oi -2019- ongoing RF and PLC
4 Sibelga 1,700,000 2018-Ongoing RF and PLC
Total 104,80,000
L. Ireland
1 Ireland 10,000 2020 RF
2 Ireland 10,000 2020 PLC
3 Ireland 920,000 2019 Cellular
4 ESB Networks 2,400,000 2019-Ongoing RF and Cellular
Total 3,340,000
M. UK
1 UK 2,320,000 2020 RF
2 British Gas 10,000,000 2011-ongoing
2 E. ON 2,700,000 2016-Ongoing
3 EDF Energy 10,000,000 2013-Ongoing
4 Octopus Energy 4,500,000 2018-Ongoing Cellular
5 Scottish Power 5,000,000 2013-Ongoing
6 SSE 73,10,000 2013-Ongoing
7 Utilita 900,000 2016-Ongoing

Page No | 34
Communication
Meters Execution
Deployed
TOTAL 42,730,000
N. Austria
2,650,000 2018 PLC
1 Austria
900,000 2018 PLC
2 Austria 210,000 2018 Cellular
3 KELAG Netz 300,000 2015-2020 RF and PLC
4 Netz Niederösterreich 700,000 2014-2022 RF and PLC
5 Wiener Netze 1,600,000 2017-2022 RF and PLC
Total 6,430,000
O. Australia
1 Ausgrid 1,200,000 2014-2020 RF
2 Ausnet Services 700,000 2009-2013 RF
3 CitiPower and Powercor 700,000 2009-2013 RF
4 Jemena Electricity Networks 300,000 2009-2013 RF
5 SA Power Networks 150,000 2014-2016 RF
6 United Energy 600,000 2009-2013 RF
Total 3,650,000
P. Japan
1 TEPCO 27,000,000 2016 RF
2 Chubu Electric Power Company 10,500,000 2014-2020 RF and PLC
3 Kansai Electric Power Company 13,000,000 2014-2020 RF and PLC
4 Kyushu EPCO 8,500,000 2014-2020 RF and PLC
5 Tohoku Electric Power Company 7,500,000 2014-2020 RF and PLC
Total 66,500,000
Q. South Korea
1 Korea Electric Power Corporation 11,000,000 2009-Ongoing RF and PLC
Total 11,000,000
R. China
1 China Huadian Corporation 20,000,000 2010-2021 RF and PLC
2 China Southern Power Grid 50,000,000 2011-2021 RF and PLC
3 State Grid Corporation of China 601,680,000 2009-2021 PLC
4 State Grid Corporation of China 10,00,000 2009-2021 PLC and Cellular

Page No | 35
Communication
Meters Execution
Deployed
Total 672,680,000
S. Singapore
1 Singapore Power 1,400,000 2014-Ongoing RF
Total 1,400,000
T. Malaysia
1 Tenaga Nasional Berhad 2,300,000 2017-Ongoing RF
2 Majlis Perbandaran Johor Bahru 1,000 2018-Ongoing PLC
3 Sabah Electricity Sdn Bhd 5,000 2018-Ongoing PLC
4 Sarawak Energy Berhad 9,000 2017-Ongoing PLC
Total 2,315,000
U. Thailand
1 Provincial Electricity Authority 3,000,000 2017-Ongoing RF
2 Electricity Generating Authority 1,000 2017-Ongoing PLC
3 Metropolitan Electricity Authority 400,000 2015-Ongoing PLC
Total 3,401,000
V. Indonesia
1 PT.PLN 8,600,000 2017-Ongoing PLC
Total 8,600,000
W. Philippines
1 Phil Power 500,000 2018 RF
2 Manila Energy 400,000 2019 RF
3 Manila Energy 350,000 2017 PLC
4 Cebu Electric 450,000 2020 Cellular
5 Luzon Power 300,000 2021 RF
Total 2,000,000
X. UAE
1 Abu Dhabi Distribution Company 1,900,000 2013-2018 RF
Dubai Electricity and Water
2 2,100,000 2009-Ongoing RF
Authority
Federal Electricity and Water
3 1,000,000 2017-Ongoing RF
Authority
Sharjah Electricity and Water
4 600,000 2016-Ongoing RF and PLC
Authority
Total 5,600,000

Page No | 36
Communication
Meters Execution
Deployed
Y. Saudi Arabia
1 Saudi Electricity Company 10,000,000 2011-2020 RF and PLC
Total 10,000,000
Z. Egypt
Alexandria Electricity Distribution
1 80,000 2018-Ongoing RF
Company
South Delta Electricity Distribution
2 60,000 2017-Ongoing RF
Company
3 Egyptian Electricity Holding Company 1,000,000 2015-2018 RF and PLC
4 Cairo Electricity Production Company 80,000 2017-Ongoing RF

Total 1,220,000
AA. India
Electricity Department, Andaman &
1 75,000 2019-Ongoing RF
Nicobar Administration
2 Ajmer Vidyut Vitran Nigam Ltd 69,000 2018-Ongoing RF
Andhra Pradesh Eastern Power
3 2,000 2019-Ongoing RF
Distribution Company Limited
Assam Power Distribution Company
4 550,000 2019-Ongoing RF
Limited
Bhagalpur Electricity Distribution
5 1,000 Completed RF
Company
2020-Ongoing
6 BSES Rajdhani Power Limited 12,000 RF
(tender in process)
2020-Ongoing
7 BSES Yamuna Power Limited 2500 RF
(tender in process)
Chamundeshwari Electricity Supply
8 20,000 2019-2022 RF
Corporation Limited
9F Chandigarh Electricity Department 24,000 2020-Ongoing RF
10 Cochin Port 25,000 2019-2021 RF
Dakshin Haryana Bijli Vitran Nigam
11 230,000 2019-Ongoing Cellular
Limited
Himachal Pradesh State Electricity
12 150,000 2018-Ongoing RF
Board Ltd
13 India Power Corporation Limited 17,000 Completed RF
12 Jaipur Vidyut Vitran Nigam Limited 440,000 2018-Ongoing RF
13 Jammu Power Distribution 190,000 2020-Ongoing RF

Page No | 37
Communication
Meters Execution
Deployed
Corporation Limited
14 Jodhpur Vidyut Vitran Nigam Limited 56,000 2018-Ongoing RF
Madhya Pradesh Paschim Kshetra
15 250,000 2019-Ongoing RF
Vidyut Vitaran Co Ltd
16 New Delhi Municipal Council 65,000 2019-Ongoing Cellular
North Bihar Power Distribution
Company Limited
18 Puducherry Electricity Department 30,000 2017-2021 RF
Punjab State Power Corporation
19 80,000 2019-Ongoing RF
Limited
South Bihar Power Distribution
Company Limited
21 Tamil Nadu Electricity Board 120,000 2020-Onging RF
Tata Power Delhi Distribution
22 300,000 2017-Ongoing RF
Limited
Telangana State Southern Power
23 8,000 2018-2021 RF
Tripura State Electricity Corporation
24 40,000 2019-2021 RF
Ltd
UP Dakshinanchal Vidyut Vitran
Nigam Limited
UP Madhyanchal Vidyut Vitran
Nigam Limited
UP Paschimanchal Vidyut Vitran
Nigam Limited
UP Purvanchal Vidyut Vitaran Nigam
Limited
29 Uttar Gujarat Vij Company Ltd. 23,000 2017-2021 RF
Uttar Haryana Bijli Vitran Nigam
Limited
West Bengal State Electricity
31 15,000 2017 RF
Total 5,544,500
AB. Brazil
1 Copel Distribuição S.A. 1,200,000 2010-2017 RF
2 Elektro 140,000 2019 RF
3 Light 1,100,000 2019 RF
4 CPFL Energia 3,000,000 2013-2019 PLC

Page No | 38
Communication
Meters Execution
Deployed
5 Enel Distribuição São Paulo 3,300,000 2009-2019 PLC
Total 8,740,000
AC. Argentina
1 Edenor 2,400,000 2010-2017 PLC
2 Edesur 2,100,000 2010-2017 PLC
3 EPEC 550,000 2014-Ongoing PLC
Total 5,050,000
AD. Columbia
1 Codensa S.A. ESP 600,000 2016 PLC
2 Empresa de Energia de Bogota (EEB) 800,000 2016 PLC
3 Empresas Publicas de Medellin (EPM) 500,000 2018 PLC and Cellular
Total 1,900,000
AE. Chile
1 CGE Distribución 1,400,000 2014-2018 PLC
2 Enel Distribución Chile 2,400,000 2017 PLC
3 Luz del Sur 500,000 2014-2019 PLC
4 Chilquinta Energía 600,000 2019 Cellular
Total 4,900,000
AF. Norway
2,220,000 2018 RF
1 Norway
670,000 2018 RF
2 Elvia 950,000 2016 RF
3 Glitre Energi Nett 100,000 2018 RF
4 Lede 220,000 2014 RF
5 Lnett 160,000 2014 RF
6 Lyse 140,000 2014 RF
7 Midtkraft Nett 14,000 2016 RF
8 Nettselskapet AS 37,000 2019 RF
9 Trondheim Electric 50,000 2021 PLC
10 Norway 330,000 2020 Cellular
Total 4,891,000
AG. Croatia

Page No | 39
Communication
Meters Execution
Deployed
1 Croat Power 80,000 2019 PLC
2 Zagreb Energy 100,000 2020 RF
3 Adriatic Utilities 70,000 2018 PLC
4 Adriatic Utilities 90,000 2021 RF
5 Istria Power 60,000 2017 Cellular
Total 400,000
AH. Cyprus
1 Cyprus Power 70,000 2019 RF
2 Nicosia Energy 60,000 2020 RF
3 Mediterranean Utilities 55,000 2018 PLC
4 Limassol Electric 65,000 2021 RF
5 Paphos Power 50,000 2017 Cellular
Total 300,000
AI. Czech Rep
1 Czech Power 120,000 2018 RF
2 Prague Energy 90,000 2019 RF
3 Bohemian Utilities 80,000 2017 PLC
4 Moravia Electric 100,000 2020 Cellular
5 Vltava Energy 70,000 2021 RF
Total 460,000
AJ. Denmark
1 Danmark Power 150,000 2019 RF
2 Copenhagen Energy 120,000 2020 RF
3 Nordic Utilities 100,000 2018 PLC
4 Aarhus Electric 80,000 2021 RF
5 Zealand Power 90,000 2017 Cellular
Total 540,000
AK. Hungary
1 Magyar Power 120,000 2018 RF
2 Budapest Energy 100,000 2019 RF
3 Danube Utilities 90,000 2017 PLC
4 Transdanubia Power 80,000 2021 RF
5 Pannon Electric 110,000 2020 Cellular
Total 500,000

Page No | 40
Communication
Meters Execution
Deployed
AL. Greece
1 Hellas Power 120,000 2018 Cellular
2 Athens Energy 90,000 2019 RF
3 Aegean Utilities 80,000 2017 PLC
4 Thessaloniki Electric 100,000 2020 Cellular
5 Peloponnese Power 70,000 2021 RF
TOTAL 460,000
AM. Latvia
1 Latvija Power 90,000 2019 PLC
2 Riga Energy 110,000 2020 RF
3 Baltic Utilities 75,000 2018 PLC
4 Vidzeme Electric 80,000 2017 RF
5 Kurzeme Power 70,000 2021 Cellular
Total 425,000
AN. Lithuania
1 Lithu Power 100,000 2018 Cellular
2 Vilnius Energy 80,000 2019 RF
3 Baltic Utilities 70,000 2017 PLC
4 Kaunas Electric 90,000 2020 Cellular
5 Curonian Power 60,000 2021 RF
Total 400,000
AO. Luxembourg
1 Lux Power 60,000 2019 PLC
2 Luxembourg Energy 50,000 2020 RF
3 Moselle Utilities 45,000 2018 PLC
4 Alzette Power 40,000 2017 Cellular
5 Ardennes Electric 55,000 2021 RF
Total 250,000
AP. Malta
1 Malta Power 60,000 2018 RF
2 Malta Power 50,000 2020 RF
3 Mediterranean Utilities 45,000 2018 PLC
4 Gozo Electric 55,000 2021 RF
5 Maltese Energy 40,000 2017 Cellular
Total 250,000

Page No | 41
Communication
Meters Execution
Deployed
AQ. Netherland
1 Dutch Power 150,000 2018 RF
2 Amsterdam Energy 120,000 2019 RF
3 Holland Utilities 6,980,000 2017 PLC
4 Rotterdam Electric 620,000 2020 Cellular
5 Utrecht Power 90,000 2021 RF
Total 7,960,000
AR. Poland
1 Pol Energy 100,000 2019 PLC
2 Warsaw Power 75,000 2020 PLC
3 Eco Utility 120,000 2018 PLC
4 Baltic Energy 85,000 2021 RF
5 Krakow Electric 60,000 2017 Cellular
Total 440,000
AS. Slovenia
1 Slovenian Power 100,000 2018 PLC and Cellular
2 Ljubljana Energy 90,000 2019 RF
3 Alps Utilities 80,000 2017 PLC
4 Maribor Electric 95,000 2020 RF
5 Adriatic Power 70,000 2021 RF
Total 435,000
AT. Slovakia
1 Slovak Power 100,000 2019 PLC
2 Bratislava Energy 80,000 2020 RF
3 Carpathian Utilities 70,000 2018 PLC
4 Tatras Electric 90,000 2017 RF
5 Kosice Power 60,000 2021 Cellular
Total 400,000
AU. Romania
1 Rom Power 130,000 2018 PLC
2 Bucharest Energy 110,000 2019 RF
3 Carpathian Utilities 90,000 2017 PLC
4 Transylvania Electric 100,000 2020 Cellular
5 Danube Power 80,000 2021 RF

Page No | 42
Communication
Meters Execution
Deployed
Total 510,000
AV. Switzerland
1 Swiss Power 180,000 2018 RF
2 Zurich Energy 150,000 2019 RF
3 Alpine Utilities 12,10,000 2017 PLC
4 Geneva Electric 130,000 2020 RF
5 Bern Power 100,000 2021 RF
Total 1,770,000
AW. Bulgaria
1 Bulgara Power 90,000 2018 PLC
2 Sofia Energy 110,000 2019 RF
3 Black Sea Electric 75,000 2020 RF
4 Balkan Utilities 80,000 2017 Cellular
5 Varna Electric 60,000 2021 RF
Total 415,000
SUMMARY TABLE OF TOTAL SMART METERS (THAT WE COULD COMPILE)
Sl RF Mesh + RF Mesh PLC +

Country RF Mesh PLC Cellular Country Total
No. PLC + Cellular Cellular
1 Argentina 5,050,000 5,050,000
2 Australia 3,650,000 3,650,000
3 Austria 3,550,000 280,000 2,600,000 6,430,000
4 Belgium 1,780,000 8,700,000 10,480,000
5 Brazil 2,440,000 6,300,000 8,740,000
6 Bulgaria 245,000 90,000 80,000 415,000
7 Canada 14,550,000 3,800,000 18,350,000
8 Chile 4,300,000 600,000 4,900,000
9 China 601,680,000 70,000,000 1,000,000 672,680,000
10 Columbia 1,400,000 500,000 1,900,000
11 Croatia 190,000 150,000 60,000 400,000
12 Cyprus 195,000 55,000 50,000 300,000
13 Czech Rep 280,000 80,000 100,000 460,000
14 Denmark 350,000 100,000 90,000 540,000
15 Egypt 220,000 1,000,000 1,220,000
16 Finland 795,000 2,240,000 870,000 1,700,000 5,605,000

Page No | 43
17 France 11,000,000 35,000,000 2,120,000 48,120,000
18 Germany 160,000 160,000
19 Greece 160,000 80,000 220,000 460,000
20 Hungary 300,000 90,000 110,000 500,000
21 India 2,499,500 3,045,000 5,544,500
22 Indonesia 8,600,000 8,600,000
23 Ireland 10,000 10,000 920,000 2,400,000 3,340,000
24 Italy 35,000,000 1,320,000 1,000,000 37,320,000
25 Japan 27,000,000 39,500,000 66,500,000
26 Latvia 190,000 165,000 70,000 425,000
27 Lithuania 140,000 70,000 190,000 400,000
28 Luxembourg 105,000 105,000 40,000 250,000
29 Malaysia 2,300,000 15,000 2,315,000
30 Malta 165,000 45,000 40,000 250,000
331 Mexico 1,300,000 1,300,000
32 Netherland 360,000 6,980,000 620,000 7,960,000
33 Norway 4,511,000 50,000 330,000 4,891,000
34 Philippines 1,200,000 350,000 450,000 2,000,000
35 Poland 85,000 295,000 60,000 440,000
36 Portugal 6,100,000 6,100,000
37 Romania 190,000 220,000 100,000 510,000
38 Saudi Arabia 10,000,000 10,000,000
39 Singapore 1,400,000 1,400,000
40 Slovakia 170,000 170,000 60,000 400,000
41 Slovenia 255,000 80,000 100,000 435,000
42 South Korea 11,000,000 11,000,000
43 Spain 1,700,000 23,300,000 760,000 25,760,000
44 Sweden 4,210,000 1,520,000 2,380,000 8,110,000
45 Switzerland 560,000 1,210,000 1,770,000
46 Thailand 3,000,000 401,000 3,401,000
47 UAE 5,000,000 600,000 5,600,000
48 UK 2,320,000 40,410,000 42,730,000
49 USA 86,050,594 5,494,744 12,282,661 103,827,999
Grand Total 179,096,094 748,205,744 57,155,000 156,682,661 4,100,000 7,700,000 1,152,939,499

Page No | 44
NOTES

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Smart Metering Program in India - A Critical Assessment

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ISGF White Paper

Smart Metering Program in India – A Critical

About India Smart Grid Forum

2 KEY CONSIDERATIONS IN SMART METERING IMPLEMENTATION

1 Latest version of the SBD can be accessed here: https://recindia.nic.in/SBD-AMISP

ISGF White Paper on Smart Metering Program in India – A Critical Assessment

2.2 Communication System

ISGF White Paper on Smart Metering Program in India – A Critical Assessment

2.4 Smart Meter Operations Centre (SMOC)

ISGF White Paper on Smart Metering Program in India – A Critical Assessment

2.5 AMI Architecture

ISGF White Paper on Smart Metering Program in India – A Critical Assessment

Typical AMI Architecture is presented below.

Dashboard and Map ayer oca on

Meter or rders ield orce

Asset Database Advanced utage and estora on ADA

raud elated vents raud

Figure 1: Typical AMI Architecture

ISGF White Paper on Smart Metering Program in India – A Critical Assessment

Figure 2: AMI Communication Architecture

ISGF White Paper on Smart Metering Program in India – A Critical Assessment

▪ PLC (narrow band) ▪ Telecom Cables, Fiber Optic

3.1 Choice of Communication Technologies

Criteria for choice of different communication technologies is presented below.

Table 2: Choice of Different Communication Technologies

3.2 Telecom Operators Interest in AMI Projects

ISGF White Paper on Smart Metering Program in India – A Critical Assessment

ISGF White Paper on Smart Metering Program in India – A Critical Assessment

4 BENEFITS OF AMI TO DIFFERENT STAKEHOLDERS 4 B

ISGF White Paper on Smart Metering Program in India – A Critical Assessment

Reduction in cost of disconnection and re-connection as it can be

Enhanced Revenue per Month

Reduction in Aggregate Technical & Commercial (AT&C) losses

Enabling faster outage detection and service restoration after faults

Traditionally utilities know about an outage only when they receive

ISGF White Paper on Smart Metering Program in India – A Critical Assessment

Power quality measurement and management

Smart meters are capable of measuring specific aspects in near real-

AMI data supports granular monitoring of power flows on the

11 Ability to operate in pre-paid and post-paid modes Medium High

Smart meters typically include remote switching, which allows utilities

13 Enhanced monitoring of the distribution network operations would Medium Medium

ISGF White Paper on Smart Metering Program in India – A Critical Assessment

B. Benefits to Generation and Transmission Companies

2 Innovative tariff schemes Medium Medium

3 Faster restoration in case of outages High High

4 Remote control of loads in customer premises High High

5 Ability to remotely manage and control appliances Medium Medium

6 Potential to save money Medium Medium

Better customer engagement on energy conservation and demand side

3 Enhanced customer satisfaction Medium Medium

4 Energy efficiency and energy conservation Medium Medium

5 CYBER SECURITY OF THE AMI SYSTEM 5

▪ Bad data injection

ISGF White Paper on Smart Metering Program in India – A Critical Assessment

ISGF White Paper on Smart Metering Program in India – A Critical Assessment

ISGF White Paper on Smart Metering Program in India – A Critical Assessment

ISGF White Paper on Smart Metering Program in India – A Critical Assessment