October 2, 2018


Smart Grid Deployment Project of Korea Electric Power Corporation


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1. Background

Due to the fast industrialization and economic development in Korea, energy-guzzling industries such as steel, shipbuilding, oil refining and chemistry came to form a majority of the Korean industrial structure, and the rapidly rising power demand from the industries has been met by increasing power supply facilities. However, due to several reasons including increased uncertainty of the power supply and demand since the large-scale blackout on September 15th, 2011, strong resistance to establishment of T&D facilities and power plants, environmental concerns related to GHG emissions and safety issues on the nuclear power plant stemming from the Fukushima nuclear power plant’s catastrophe, the paradigm of the power policies has shifted from expansion of the power supply to demand management, which has raised awareness of the role and necessity of the Smart Grid to secure flexibility in the power grid. Accordingly, the Korean government implemented a Smart Grid test bed project in Jeju island by investing $220.3 million in it for 42 months from December 2009 to May 2013. During the project, KEPCO invested $21.9 million in 5 areas including Intelligent Consumer, Intelligent Transport, Intelligent New & Renewable energy, Intelligent Power Grid and Intelligent Services to establish a Smart Grid environment and developed a new business model by integrating and verifying relevant technologies.

[Table 1] The overview of the Smart Grid test bed project in Jeju island

Location Gujwa-eup, Jeju Island  

Scale 5 Fields, 2 S/S, 4 D/L,
3,000 Households
Partner 12 Consortiums (168 Companies)
Duration Dec ’09 ~ May ’13 (42 Months)
Budget Total $226.4 million

(Government $67.9m, KEPCO $21.9m, Private $136.6m)

Results Development and verification of 153 technologies including, AMI, EMS, EV charge infrastructure, energy storage

9 business models including, management of demand response, EV charging service

During the COP 21 held in Paris in December 2015, the Korean government announced its goal to reduce greenhouse gas emissions by 37% compared to BAU by 2030. To abide by the Paris Agreement, the government has decided to implement the Smart Grid deployment project as a major way to ease the burden of the Korean industry to reduce its greenhouse gas emissions and enhance the energy efficiency by controlling and distributing the power demand in real time.

2. History

KEPCO is the only power utility in Korea which can sell electricity to consumers, and it manages all watt-hour meters and installs and manages the watt-hour meters differently according to supply voltages.

[Table 2] Installation & management of watt-hour meters in the terms & conditions of the power supply

Division Low voltage (Contract per household) High voltage (1 contract for a group)
Mgmt. method Installation & mgmt. by KEPCO Total usage : Installation & mgmt. by KEPCO

Household usage : Installation & mgmt. by consumers

After the SG test bed project in Jeju island, KEPCO invests $10.6 billion in building AMI for 22.5 million households with low-voltage meters managed by KEPCO in Korea from 2010 to 2020. This project is called “AMI establishment project”. On the sidelines of the project, KEPCO also deploys the Smart Grid in cooperation with the Korean government and municipalities by investing $32.1 million for household meters not managed by KEPCO from 2016 to 2018. KEPCO proposed “AMI-based power services” and “Consulting services for energy consumption” verified during the test bed project on Jeju island by forming a consortium of 8 companies including LG U Plus Corp. in cooperation with 12 municipalities including Seoul. Thanks to this, in October 2013, KEPCO was selected as a company to implement the Smart Grid deployment project and signed a business agreement with the Korean government in December 2015 and undertook the project in March 2016.

[Table 3] Process of the PJT implementation

* Expandes from the existing 8 regions to 12 regions

(Seoul,Incheon,Gwangju,Chungnam,Gyeongbuk, Jeju,Namyangju,Gangneung,Daejeon,Ansan,Chungju,Naju)

As a result of the pilot project, the “AMI-based service” and “Consulting for energy consumption” reduced the power consumption by 3.4% and 12.1% respectively. Currently, the services are provided through 73,000 AMIs and until 2018, 145,000 AMIs will be completed to be built for providing the services by 2025.

[Table 4] Plans & performance of the SG deployment project(watt-hour meters of customers)

Subject Plans Performance
‘16 ‘17 ‘18 Total
No. of meters (10,000) 7.3 4.1 3.1 14.5 7.3
Total cost (100 mil won) 189 102 74 365 189

※ KEPCO AMI establishment project (watt-hour meters installed by KEPCO) : 22.50 million AMIs will be built by 2020

3. Overview of the System

The system of the Smart Grid deployment project consists of smart meters, PLC modem, DCU, EMS and TOC. The smart meters communicate with DCU through PLC, and DCU communicates with TOC through LTE.

[Figure 1] The system configuration

TOC(Total Operation Center) The system configuration
▪ Monitoring the overall operation & data collection status

▪ Data storage in DB, overall monitoring/control of operation

▪ Collecting/verifying/analyzing/managing the metering data

▪ Providing customer services including power planner(App/Web)

▪ Alignment with SG project’s control center etc.


[H/W area]

The smart meters which are the key component of the SG deployment project have 2 types. AE-Type is applied to apartments and G-Type is applied to shopping malls, and the LP metering cycle is 15 minutes for both of them. DCU is a device to gather data of meters and it can communicate with 200 or more meters at the same time. Furthermore, the PLC modem is a device inserted in meters for PLC communication between DCU and meters, and it is very economical as it can communicate with up to 30 meters through RS-485 and has a repeater function to enhance the communication success rate.

Components Details Note
Smart Meter ▪Metering function : Active, reactive, VA, peak power
▪LP metering cycle : 1, 5, 10, 15, 30, 60 min.
▪Channel : 8(4 for sending & receiving power)
▪Other function : Instantaneous metering of voltage, current, frequency etc.
▪Rate sys. : Progressive charging system, TOU etc.
▪Power line communication btw data concentrator & modem
▪Support for coding 128-bit AES or more
▪Communication with 200 or more w/h meters
Com. method ▪Wired/wireless communication including PLC, RS-485, LTE etc. ISO IEC 12139-1
IEEE 802.15.4
EIA-485-A etc.
Modem ▪PLC communication btw data concentrator & modem
▪Protocol relay btw data concentrator & smart meter
▪Support for coding 128-bit AES
▪Communication btw up to 30 Ea-type, G-type w/h meter & RS-485
EMS ▪Various electric power services including processing/analyzing/controling energy
▪Operation/mgmt./control services for managers and various consumer services via web & a smart phone application
TOC ▪Gathering & storing data from LOC, overall monitoring & control of operation by each data storage location


[S/W area]

Not only does EMS carry out remote metering for consumers and power managers, it also provides additional services such as real-time energy usage notification and consulting services via PCs and a smart phone application by processing and analyzing the energy information. It provides monthly estimates for electric bills as well as the real-time power usage and current electric charging rates. Furthermore, it analyzes consumers’ energy consumption patterns and compares them with those of average people and energy savers in the neighborhood to motivate them to save their energy. It also provides Push functions through the smart phone application to notify usage goals and progressive & maximum demand to induce consumers to voluntarily join the demand response.

[Figure 2] Main functions of the APP services

4. Approach

1) Project overview

Since March 2016, KEPCO has been pushing forward with “AMI-based power services” and “Consulting services for energy consumption” to meters in apartments and shopping malls not managed by KEPCO in cooperation with the Korean government and municipalities.

[Table 6] Details of Project

PJT AMI-based power services Consulting for energy consumption
Subject 131,500 apartments 13,000 shopping malls
PJT cost $ 29 million($0.14/month per household) $ 3.4 million ($0.88/month per mall)
Details Inducing consumers to voluntarily save energy through notification of the progressive charging range and comparison with the neighborhood Encouraging the reduction of peak load and energy consumption by providing consulting services such as offering real-time electric charging info.
PJT period Establishment : 2016∼2018(3 years), operation : 2016∼2025(10 years)
Consortium 21 participants (Municipalities : 12 areas including Seoul, 9 business partners including KEPCO)

[Figure 3] Business models of the project

From 2016 to 2018, 144,500 AMI facilities are going to be built for apartments and shopping malls in 12 municipal areas.

Areas Establishment plans  



Apt. Shopping Total
Seoul 15,150 15,150
Incheon 4,174 5,000 9,174
Gwangju 20,420 20,420
Daejeon 19,900 19,900
Chungnam 16,174 16,174
Gyeongbuk 22,200 5,000 27,200
Jeju 5,178 5,178
Ansan 519 519
Namyangju 11,976 11,976
Gangneung 10,000 3,000 13,000
Chung ju 4,631 4,631
Naju 1,178 1,178
Total 131,500 13,000 144,500


2) The purpose of the project

The major goal of the SG deployment project is to secure flexibility of the power system. KEPCO already completed introduction of the SG system in the existing power system about 10 years ago, and it is planning to build the nationwide Smart Grid by installing AMIs for meters directly linking the power supplier and consumers in the power system.

[Table 8] Project Objective

Division Reduction in power consumption Reduction in the

peak load

Reduction in


AMI-based power


2.5% 2.5%
Consulting for energy consumption 3.4% 5.0% 3.4%


3) Pilot project

The pilot project was implemented to 1,181 apartments and 61 shopping malls, which helped the apartments and shopping malls to reduce the power consumption by 3.4% and 12.1% respectively.

[Table 9] The overview & performance of the pilot project

Division Subject No. of consumers Period Reduction rate(%)
AMI-based power services Gumho Daewoo Apt. 1,181 households ‘16.9. 2∼9.30 3.4%
Consulting for energy consumption Tower plus 61 shops ‘16.8.16∼9.30 12.1%


5. Outcome

1) Economic Rationale

Reduction of the peak load & power consumption

The power rate system for Korean households in 2016(3 stages now) was subject to 6 stages of the progressive rate charging and the power rate of stage 6 was 11.7 times more than that of stage 1, one of the world’s top progressive rates. Last summer, the continuous heat wave resulted in the rapid rise in the household power consumption due to the increased usage of cooling machines including air conditioners, which has emerged as a serious social issue as it caused bad press and a series of suits against record high electric bills and the progressive charging system. This issue occurred as the consumers were not aware of their power consumption amount and charging information in real time until they got their electric bills. To resolve the issue, KEPCO is providing AMI consumers and power managers with additional services such as real-time energy use notification and consulting via EIS(Energy Information System) and a smart phone application. KEPCO provides the real-time power usage and charging information to consumers on a daily, weekly and monthly basis, analyzes their consumption patterns and compares them with those of average consumers and energy savers in the neighborhood to induce them to voluntarily join the demand response. The key function of EIS is the Push function notifying the usage goal and progressive & maximum demand. In case of the push function for the usage goal, when the individual energy consumption hits 80% or 90% of the usage goal, it is notified to consumers to be able to effectively manage their energy consumption. And in regard to the push function for the progressive & maximum demand, household consumers are notified of whenever their stage for the progressive charging range changes to prevent them from unexpected and enormous electric bills, and general power users including shopping malls are notified of whenever their maximum demand is reached to effectively manage their peak load. As a result of the analysis on the effects of the services, a remarkable difference was found in the power consumption patterns between consumers who received the services and those who haven’t. The power consumption of households and general users was reduced by 3.4% and 12.1% respectively, and the peak load was cut at a similar level to the power consumption. Through this, consumers can reduce the power rates and KEPCO, in return, can decrease the cost of building power plants and T&D facilities.

[Table 10] Reduction effects (Standard : 14,5000, 2.5% for 10 years)

Reduction in energy


Reduction in peak load Reduction in greenhouse

gas emissions

106,122MWh 2.5MW 48,710 tCO2

Creation of the new business ecosystem and profits

KEPCO’s Smart Grid deployment project makes profits by receiving service charges from customers for providing its services to them after establishing the Smart Grid infrastructure. The AMI based services consist of fixed fee and flexible fee services. The fixed fee service charges each household $0.14(VAT excluded) every month, and the flexible fee service charges consumers 50% of the margin of the fixed arising when consumers’ stage of the progressive system drops to a low level due to their cut in energy consumption. The energy consumption consulting service charges each household $0.88(VAT excluded) every month. The service model in the Smart Grid is the 1st business model in the world and it is expected to make a great contribution to establishing a new energy business ecosystem.

※ VAT : 10%of  supply value

2) Potential impact

Enhancement in the flexibility of the power system by applying the new rate system

Under the Korean power rate system, high-capacity consumers(contract demand-100kW or more, supply voltage-22,900V or more) are subject to Time of Use system(TOU), the low-capacity consumers(contract demand-less than 100kW, supply voltage-220/380V) are subject to seasonal rate system, and household consumers are subject to the progressive charging system, which are decided by the Korean government’s policy. The Korean government is now considering adopting a new power rate system to supplement a weak price signal and increase options for customers. When KEPCO’s Smart Grid deployment project is completed, a new rate system including Time of Use(TOU), Critical Peak Price(CPP) and Real Time Price(RTP) can be applied immediately. When such a flexible power rate system is applied, the volatility of the energy price will be reflected in a timely manner so that the flexibility of the power system will be enhanced by the efficient allocation and usage of national energy resources, improvement in the power demand & supply and increased options for customers.

Stabilization of the power supply & demand by enhancing the flexibility of the power system

As the paradigm of power policies has shifted from supply-centered to demand-centered, the Korean government has been reviewing the National DR in which household consumers can participate in the negawatt market to expand the demand response system from 2018. When this system is implemented, the DR solution is going to be provided to consumers via the infrastructure and smart phone application established by KEPCO’s Smart Grid deployment project, which helps KEPCO to secure the flexibility of the power system by quickly responding to the power supply and demand.

3) Potential for Replication or Adaptation

Establishment of AMI standard & construction standards

Standardization of the AMI was necessary to expand the Smart Grid nationally and secure its flexibility. Therefore, KEPCO standardized purchase specifications and construction & maintenance criteria for AMI applying Korean and foreign technical standards such as KS and IEC and prepared security policies. Through the work, the interoperability between devices and security policies have been secured to lay the foundation for expanding the nationwide Smart Grid and the project’s economic feasibility has been improved thanks to the enhancement in the quality of the facilities and construction.

Cooperation with the government & local municipalities

To maximize the effects of the Smart Grid deployment project and expand them nationally, KEPCO has been forming a virtuous cycle by cooperating with the Korean government, municipalities, big conglomerates and SMEs.(Market creation, new service development, institutional improvement, technological development & foundation establishment) The national project is implemented in line with municipalities to lay a firm foundation for the local economic development and it serves as a new growth engine establishing a new industrial ecosystem by converging various industries and creating jobs.

[Table 12] The participation status of municipalities

Division Municipalities
Metropolitan municipalities
Lower level municipalities

Cooperation with SMEs

KEPCO’s SG deployment project encompasses a consortium of 3 EMS companies, 2 watt-hour companies, 2 DCU&PLC modem companies and 1 telecommunication company. Six out of the total 8 companies in the consortium are SMEs to lay a foundation for co-prosperity with SMEs through fair benefit sharing and technological cooperation and build a SG ecosystem by fostering SMEs in the area.

[Table 13] The participation status of business partners

Division Business partners
Large & mid enterprises

4) Innovation

Development of MDMS & AOS

KEPCO has independently developed Meter Data Management System(MDMS) to provide the overall management of the metering data such as collecting the data, verifying its validity, estimating wrong/omitted meter values and managing & analyzing the remote control, and AMI Operation system(AOS) to inform the internal users and consumers of the metering status, real-time information and the power quality. At the same time, KEPCO also developed open source based software and system in the distributed/parallel processing method in line with international standards to process the nationwide metering data in real time and achieved reliability, stability and scalability of the system.

Meter Data Management System AMI Operation System

[Figure 4] MDMS & AOS


Development of the CBL estimation algorithm

For analysis of the project’s economic feasibility and effects, it is necessary to calculate the reduction rate of the peak load and power consumption, a key effect of the project, in a precise and objective manner. Thus, KEPCO developed Customer Base Line(CBL) estimation algorithm based on the performance data analysis by outsourcing it to an external research institute and secured the legitimacy of participating in the project.

[Figure 5] CBL(Customer Base Line)

5) Other Benefit

 Contribution to reducing GHG emissions

During the COP 21 held in Paris in December 2015, the Korean government announced its goal to reduce greenhouse gas emissions by 37% compared to BAU by 2030. To abide by the government’s decision, KEPCO has been strongly pushing forward with the Smart Grid deployment project as a key way to reduce greenhouse gas emissions and eased the emission reduction burden in the Korean industry by cutting them through optimizing the energy efficiency and demand response.

Providing social safety net services through the convergence with IoT

KEPCO signed an MOU on the SG deployment project and cooperation on the Home IoT project with LGU+, a largest IoT company in Korea in September 2016 for CSV. It is also planning to provide social safety net services through the convergence of AMI and IoT to consumers joining the Smart Grid deployment project from 2018. The major services include providing weather information such as temperature, humidity & fine dust with sensors and care services for senior citizens living alone. Through these services, it is expected to realize public interest and improve the acceptability of the Smart Grid by promoting its good points.

5. Future Plans

Until 2030, KEPCO is planning to complete the SG establishment for apartments and shopping malls nationally to build the nationwide SG. Furthermore, it is scheduled to provide new energy services based on the energy platform in line with Home ESS, integrated metering infrastructure and smart appliances.

 [Figure 6] KEPCO Smart Grid Expansion Roadmap


Customer Service URL of the “Smart Grid Deployment Project”: http://sg.kepco.co.kr

Customer Approval URL of the “Smart Grid Deployment Project”: http://sgadmin.kepco.co.kr


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October 5, 2015


Smart Meter Deployment at domestic customer

By smartgrider In Advanced Metering Infrastructure, Case study Posted 2015-03-01


Market structureElectricity market is liberalized since 1997. The electrical grid belongs to the state. Utilities, distributed by geographical areas, are responsible for installing, operating and maintaining the grid, being smart metering deployment responsibility of them. The regulated transmission and distribution activities are remunerated administratively.
Number of retail customers28.8 million
Electricity consumed -2013 246 TWh
Peak Demand for Power -201340,277 MW
Net Revenue to Distribution Companies 2010€ 5,000 million aprox.
Distribution Network• 447,658 km of overhead lines
• 191,848 km of underground lines
• There are 5 major distribution companies; 98% of the distribution network
Contact Mariano Gaudo Navarro Dipl.- Ing. mgaudo@gasnatural.com


Smart Meter Deployment at domestic customer

Spain has not conducted an economic assessment of long-term costs and benefits for an electricity smart metering roll-out. However, the country has decided to proceed with a full roll-out in the case of electricity in compliance with a Royal Decree 1634/2006 stating that by July 1st 2007 the Spanish regulator had to elaborate a replacement plan for all Spanish domestic meters with contracted power lower than 15 kW. The roll-out covers 100% of 27.8 million meters and is intended to run from 2011 till 2018.

Each of these deployments includes smart meters and the associated communications networks, remote reading and control, data management systems, web portal customer interaction, and some form of dynamic pricing. They differ in size or scale, pricing scheme and in behind-the-meter capabilities such as in-home displays. A summary of the project descriptions are shown in Table 4 under Current Status & Results.
A number of factors, such as late approval of the replacement plan, technological uncertainties in terms of system communication, alleged supply problems of certified meters and negotiations with the regulators about the level of cost acceptance, hampered the achievement of the initial target of 30 % by 2010. The latest developments are related to the introduction of the first set of smart meters in large scale pilot projects deployed by the five major distributors Endesa, Iberdrola, Gas Natural Fenosa, E.ON and Hidrocantabrico (EDP group) Consequently, Spain Smart Meter deployment is advanced, being installed a number of devices very representative of about 9 million smart meters by the end of 2014.

This shows that the smart meter technology deployment in Spain is being developed according to regulation plans. The decision was not conducted an economic assessment of long-term costs and benefits for the electricity smart metering roll-out.

The present Use Case addresses the main smart meter deployment experiences in Spain. The metering activity in Spain is regulated and the distribution system operator (DSO) is the responsible party for implementation and also for granting third-party access to metering data. The choice for the customer to either accept a rented meter by the DSO at a regulated monthly fee or install his own meter is a legal right in Spain.


Objectives & Benefits

The national objectives to be achieved by the employment of smart meters are:

  • Compliance with EU directives of electricity and Energy Efficiency (2006/32/EC, 2009/72/EC and 2010/31/EC).
  • Decreasing energy price for customers by increasing competition in energy market and decreasing the cost of the electrical system
  • Transparency in electricity billing for customers.
  • Remote control, hourly energy metering and option for hourly tariff selection.
  • Increase energy efficiency, making possible user’s actions to achieve energy savings from the profile consumption information provided. Regarding to benefits provided by Smart Meter technology deployment, two main interest groups are differenced: customers and the electrical system.

Benefits for customers:

  • Hourly consumption information close to real-time helps customers managing their consumption and identifying energy efficiency actions for reducing their consumption and saving money.
  • Customer can manage its consumption thanks to the information and services provided, as well as responding to incentives
  • Accuracy and transparency of measurements and electricity bills.
  • The infrastructure implemented make possible customer’s participation in the power system, being available active participation in consumption and generation.
  • A set of services becomes available for the customer, in combination with other smart grid technologies, such as new tariffs, pricing incentives, management consumption systems, etc.

Benefits for the electrical system:

  • The availability of hourly customer consumption makes possible to quantify the potential of demand side management and know the behaviour of the grid.
  • Metering processes and distribution grids can be automatized and smart devices can be controlled in a remote way. As a result, the cost related to these activities decrease. However, the optimal automation level has to be analysed according to technical and economic terms.


Use Case description & key Points

The national objectives to be achieved by the employment of smart meters are:
The Smart Meter Replacement Plan of December 2007 approved by the Spanish Ministry of Industry, Tourism and Trade, established that all electricity meters with a contracted power up to 15 kW (domestic customers) have to be replaced by new meters able to remote management time discrimination before December 31st 2018. All the DSOs in the country had to submit their substitution plan to the government.

Smart Meter deployment Details

  • Smart Meters and AMI
    • 9 million smart meters deployed currently
    • Meters to DCs via PLC; DCs to AMMS via GRPS/3G/Optical Fibber
  • Tariffs:  New tariff basic on hourly energy prices in the daily market (PVPC)
  • Funding: 100% rate recovered by DSOs
  • Project Cost: N/A
  • Project Cost: N/A

Initially, a binding target of 30% of all smart meters had to be replaced by end 2010. However, this initial target was not possible to be achieved by any DSO due to diverse reasons: the delete on approving the replacement plan (May 2009), some deletes in the certification of the meters and problems in negotiations with the regulators about the level of cost acceptance.

As a result, the Replacement Smart Meter’s plan was modified, being established new targets for different periods. For each distributor company, at least 35% of smart meters have to be replaced by 31st December 2014, other 35% between 1st January 2015 and 31st December 2016, and finally between 1st January 2017 and 31st December 2018 the remaining 30%.
The planned steps to carry out this national smart meter legal framework were:

Stage I:

  • Researching and developing of new technologies and services
  • Field tests to validate the developments
  • Solutions’ standardization

Stage II:

  • Large scale deployment of probed solutions into the system
  • Applying real business models for the deployment

The regulation also established the minimum functional requirements for the new smart meter to be installed, mainly characterized by:

  • Remote bidirectional control for reading, energy management, power demand control, connect/disconnect
  • Hourly metering and option of selecting hourly tariffs

According to this regulation, manufacturers developed smart meter devices for Spanish DSOs using two kind of communications technologies: PRIME and Meters & More. Each one is based on different protocols and structures, although both of them uses PLC (Power Line Communications) using broadband and narrowband respectively.

PRIME (PoweRline Intelligent Metering Evolution) is a public, open and standard. Today is a mature, consolidated and worldwide PLC standard for Advanced Metering, Grid Control and Asset Monitoring applications and the objective to establish a set of open international PLC standards has been met.

Meters & More is a new generation protocol which leverages from the experience of Enel’s Telegestore. Currently, both PRIME and Meters & More are working towards standardizing its technologies with the aim of allowing interoperability between all manufactures’ devices and services to favour the competitiveness between them.


Current Status & Results

In November 2014 there are more than 5 million meters with PRIME technology deployed by Iberdrola, Gas Natural Fenosa and Hidrocantabrico. Moreover Endesa and E.ON are deployed 4 million meters, with Enel technology. In any case, at the end of 2014, all distributors have replaced 35% of its domestic electricity meters.

Finally, a relevant fact related to smart metering services is that a new energy tariff for domestic consumers, based on hourly price of the daily market, was approved in 1st February 2014. The aim is provide customers the option of saving money by means of hourly pricing criteria. This service is able thanks to smart meter technology deployment, and it is expected that other new services will be developed at future.


Lessons Learned & Best Practices

In November 2014 there are more than 5 million meters with PRIME technology deployed by Iberdrola, Gas Natural Fenosa and Hidrocantabrico. Moreover Endesa and E.ON are deployed 4 million meters, with Enel technology. In any case, at the end of 2014, all distributors have replaced 35% of its domestic electricity meters.

Finally, a relevant fact related to smart metering services is that a new energy tariff for domestic consumers, based on hourly price of the daily market, was approved in 1st February 2014. The aim is provide customers the option of saving money by means of hourly pricing criteria. This service is able thanks to smart meter technology deployment, and it is expected that other new services will be developed at future.

Smart meters interoperability – Standardization and interoperability of smart meter communication technology is crucial to have a wide portfolio of products compatible between them, as well as promoting the market competitiveness.

Energy cost – Smart meter deployment makes able the reduction of the power system costs thanks to remote and automation of processes.

Real-time monitoring – The interval update of consumption data and providing them to customers and third parties is probably the most difficult functionality to be implemented in smart meter’s technology.

Energy savings – Smart meters are a necessary tool to provide cheaper energy for the customers, in addition to services which to achieve potential savings and make able its participation in the electrical market.

Customer engagement – Informing and making aware the customers about the benefits of consumption management is crucial for the success of many of the potential services which can provide the smart meters.

Privacy and security of information – Guaranteeing the security and privacy of the information of the customer is a relevant aspect to be considered.


Next Steps

In the next years, the steps to be carried out in Spain are focused on achieve the full deployment of smart meter up to 15 kW by December 2018. The smart meter’s standardization technology is expected to be achieved; being available a competitive set of devices from different manufactures compatible among them.

Functionalities and services implemented at several R&D and demo Projects developed recently or currently in progress, will be widespread according to scalability and reliability concepts in the following years. Among these functionalities and services, distributed generation, voltage control, load shifting, dynamic tariffs, outage and theft detection. The final aim is to consolidate these solutions as mature to be used in achieving a more efficient and reliable power system.

In addition, the customer’s engagement is other of the steps to be achieved in the future to implement the Demand Side Management by providing valuable and useful services, mainly characterized by the energy cost reduction improving reliability and security of supply. Special mention to R&D projects: Malaga Project led by Endesa and the PRICE project jointly led by Iberdrola and Gas Natural Fenosa for their relevance and coverage to all functionalities of smart grids, including Demand Side Management.


Key Regulations, Legislations & Guidelines

In the next years, the steps to be carried out in Spain are focused on achieve the full deployment of smart meter up to 15 kW by December 2018. The smart meter’s standardization technology is expected to be achieved; being available a competitive set of devices from different manufactures compatible among them.

The regulation existing in Spain regarding smart meters implementation is represented by the following main regulations:

  • Criteria for the replacement and number of meters to be replaced every year: RD1634/2006, Order to the regulator about the Replacement Plan for all Spanish residential meters.
  • Smart meter’s Replacement plan: ORDEN ITC/3860/2007, publication of the criteria for the Replacement Plan, including every distributor having to present its own plan and AMM system de-sign.
  • Modification of the Smart meter’s Replacement Plan: ORDEN IET/290/2012, publication which modifies the previous order to adjust the Replacement Plan to the current deployment status.
  • Electricity tariff based on hourly price in the daily market for domestic consumers: Royal Decree 216/2014
    http://www.boe.es/boe/dias/2014/03/29/pdfs/BOE-A-2014-3376.pdf ?
  • Benchmarking smart metering deployment in the EU-27 with a focus on electricity [COM(2014)356], 17.6.2014

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October 5, 2015


4 California AMI deployments

By smartgrider In Advanced Metering Infrastructure, Case study Posted 2014-07-12


Market structureISO operates but does not own the grid
• Runs transmission market
•Acquires ancillary services
• Runs an ‘imbalance’ energy market
• Locational Marginal Pricing
Number of retail customers 14.9million
Electricity consumed -2011285TWh
Consumed -201170% in-state, 30% import
Peak Demand for Power -2011 58,000 MW
Total Revenue to Distribution Companies$29 billion USD , Net Revenues not available
Distribution Network• 51,499km transmission lines
• 75 utilities or load-serving entities, including retailers
• 77% of these customers are served by 3 large investor owned utilities.
ContactMackay Miller
National Renewable Energy Laboratory
Eric Lightner US Department of Energy

USA California

4 California AMI deployments

Overall AMI deployment across the USA is expanding, many with pilots in behind the meter technologies such as in-home displays and customer web portals, and many with dynamic pricing schemes. In 2011 the US Energy Information Administration reported over 37 million AMI meters, and over 45 million AMR meters in operation. Over 10.5 million of those AMI meters were in California, with another 0.5 million AMR meters in operation. California in particular has accelerated efforts through policy and programming since 2006, for smart grid investments supportive of conservation and renewable energy integration. As a result, a lot of regulatory and implementation issues have been dealt with in California first, before other states. Most notably, California has developed best practices for managing data and privacy issues in particular, and also managing deployment with alternative options such as opt-out availability. Four California utility experiences are presented in this case to illustrate the deployment of AMI under different smart grid drivers, and with different approaches: Sacramento Municipal Utility District (SMUD), Glendale Water and Power (GWP), Burbank Water and Power (BWP) and San Diego Gas and Electric (SDG&E). These four utilities serve about 2.2 million of the 15 million customers in California.

Each of these deployments includes smart meters and the associated communications networks, remote reading and control, data management systems, web portal customer interaction, and some form of dynamic pricing. They differ in size or scale, pricing scheme and in behind-the-meter capabilities such as in-home displays. A summary of the project descriptions are shown in Table 4 under Current Status & Results.


Objectives & Benefits

California smart grid policy is enacted in part through the California Public Utilities Commission (CPUC) which regulates the three large investor-owned utilities (IOUs). San Diego Gas & Electric is one of them with almost 1.4 million customers. While the CPUC does not have regulatory authority over the municipal utilities, such as the three outlined in this case, its regulation does set the tone across California for smart grid approaches and serves to identify best practices. When authorizing rate recovery from 77% of the California customers for AMI, the CPUC recognized the following benefits to customers, the electricity system and the state from smart meters:

  • Allows for faster outage detection and restoration of service
  • Provides customers with greater control over their electricity use when coupled with time-based rates
  • Allows customer to make informed decisions by providing highly detailed information
  • Helps the environment by reducing the need to build power plants, or avoiding the use of older, less efficient power plants as customers lower their electric demand
  • Increases privacy because electricity usage information can be relayed automatically to the utility for billing purposes without on-site visits by a utility

While each of these benefits are written more from the perspective of the customer, AMI systems also generate significant operational benefits as described below. Together these customer and system benefits served to create the business case for AMI investment.

Looking at the four utilities presented in this case, each had a unique set of objectives. For example, BWP, responsible for water and power services, wanted a mesh network across the whole city. SMUD and SDG&E were driven more by demand for the integration of renewable generation. That notwithstanding, drivers common to each of their AMI deployments can be summarized as:

  1. Operational efficiency and reliability
  2. Customer satisfaction and engagement with more services

The initial focus was primarily on achieving system functionality. As will be discussed later in this case, however, the utility experience with AMI implementation in each of these deployments led to greater focus on customer satisfaction and engagement.


Building the Business Case & Measuring Success

The CPUC recognized smart meters as a key step toward creating a smart grid in California. By enabling greater visibility of grid performance, AMI is seen to contribute to greater reliability and resilience to outages and other problems on the grid. AMI can also allow utilities to meet various operational and customer satisfaction objectives, including conservation, customer control, environmental performance, customer service and privacy.

The technical systems underlying an exemplary AMI implementation are illustrated in Figure 14, which shows the BWP integration schematic. In the BWP deployment, the Meter Data Management System (MDMS) interconnects to 5 other operation and information systems. This tight integration supports a wide range of applications, which in turn supports the business case for the project. As BWP, SMUD, and GWP are municipal utilities, their respective city councils reviewed and approved their smart grid deployments, while the CPUC performed this role in the case of SDG&E.

Figure 14 : BWP Smart Grid Key Operations and Information Systems

Burbank Water & Power’s Meter Data Management System (MDMS) is interconnected with its other operation and information systems. (Image source: B. Hamer, BWP)

The intended functionalities enabled by AMI are evident in the metrics designed to measure AMI functionality and progress toward achieving the stated benefits. The CPUC mandated in April 2012 that AMI metrics be reported by the IOUs each year, including: Number of smart meter malfunctions where customer electric service is disrupted;

  • Number of utility owned smart meters supporting consumer devices with Home Area Network (HAN) or comparable consumer energy monitoring or measurement devices registered with the utility;
  • Number of escalated customer complaints related to the accuracy, functioning, or installation of smart meters or the functioning of a utility administered HAN with registered consumer devices;
  • Number of utility owned smart meters replaced annually before the end of their expected useful life;
  • Number and percentage of customers with smart meters using a utility administered Internet or a web-based portal to access energy usage information or to enrol in utility energy information programs;
  • Number of customers enrolled in time-variant electric vehicle tariffs;
  • System-wide and total number of minutes per year of sustained outage per customer served; and,
  • Total annual electricity deliveries from customer-owned or operated, grid-connected distributed generation facilities.

Half of these metrics focus on the delivery of services to customers, while the other half measure customer response to the delivery of services. This speaks to the challenge of making a business case centred only on customer value. While customer benefits are an important aspect to make the business case, these need to be coupled with operational benefits. Because a business case dependent on customer behaviour is not entirely predictable, the command and control and data management functionalities shown in Figure 14 bolster the value proposition for utilities. Thus, outside of these customer-focused metrics, operational savings are measured against the cost of deploying AMI such as reduced number of truck-rolls from AMR and outage management, and deferred asset investment based on more detailed information about demand profiles.


Current Status & Results

A summary of the drivers, current status and results of each of the four utility deployments of AMI are presented here. They are also outlined in Table 4.

Table 4 : California AMI Project Details


Sacramento Municipal Utility District (SMUD)

As the second largest deployment presented in this case, SMUD’s experience with AMI is interesting in that it includes the largest of the US Department of Energy funded consumer behaviour studies, with approximately 57,000 customers participating. In a randomized control trial SMUD is studying the effect of different rate combinations, in-home displays and mandatory, opt-in and opt-out deployment approaches on overall demand reduction. It is expected that these will be the largest most rigorous tests on how different technologies affect consumer behaviour, with results available in late 2013 or early 2014.

SMUD’s AMI deployment is also part of a solar neighbourhood pilot, demonstrating some of the best communications between solar PV inverters and the meters. The PV integration project is described in the Future Steps section.


  •  Operational efficiencies (reduced truck rolls and O&M costs, meter reading, deferred investment)
  • Improved reliability and reduced line losses
  • Solar PV integration

Current Status

  • ~670,000 meters deployed with the network and billing systems in full operation
  • Opt-out: $127 initial fee, and $14 per month recurring fee.

Complementary Technologies, Systems, and Processes 

  • Majority of Distribution Automation Systems installed, and will be fully operational summer 2014
  • Solar PV and energy storage for smart grids with inverter ? meter communication


Glendale Water and Power (GWP)

When GWP was planning for its AMI roll-out they realized that it would be the beginning of a much greater transition for the utility and the customers they serve. GWP embraced the opportunity with two years of internal preparation before launch. As one executive remarked, “For 100 years the utility worked in silos – customer service, technical, etc. It took 6 months to get people from different silos to come to meetings.” During this time they paid careful attention to the impacts of an AMI program on unionized staff, and developed a plan where some work duties were changed, some were phased out and others were phased in. When it finally came time to launch, GWP adopted a “down home” approach to engaging their customers. Staff from the utility became a fixture in the park or in places around the community every week for citizens to come out and learn about smart meters prior to roll-out. They experienced virtually no push-back as a result (only about 0.25%), which is notable because there had already been a fair amount of negative response in other California service territories around that time.


  • Operational efficiency and loss prevention
  • New customer services
  • Planning for future systems

Current Status 

  • ~85,000 meters installed
  • Out of 40,000 residential customers, ~100 on delay list

Complementary Technologies, Systems, and Processes 

  • Energy storage for peak shifting (162 thermal storage units ≈ 1.27 MW capacity)


Burbank Water and Power (BWP)

As was illustrated in Figure 14, BWP developed a plan that integrated its AMI within a plan for the administration, data management and control systems. Theirs is one of the few deployments with a mesh network backbone that covers the entire city. The resilience of this network will be compared with the hub and spoke type communications backbones adopted by other utilities.
Committed to their second driver of customer empowerment, BWP partnered with Opower, a company focused on customer-facing solutions and products, to engage customers in conservation and demand management programs. BWP’s “Smart Choice” program tests varying ways to present energy use information to customers on their bills (and via a web portal) in order to encourage demand shifting or conservation.


  • Modernizing the business, communications systems, and delivery systems
  • Empowering customers

Current Status 

  • Cisco powered fiber optic network with a Trilliant / General Electric AMI meter system and eMeter Meter Data Management System
  • Opt-out: $175 initial fee, and recurring $10 per month. Opt-out meters are digital meters with the radio modules removed

Complementary Technologies, Systems, and Processes 

  • Tropos city-wide wireless mesh network ? Thermal energy storage for peak shifting (19 Ice Bear rooftop thermal storage units at city and commercial and industrial sites); goal of 285 units
  • 2MW of controllable demand
  • 11 controllable plug-in hybrid electric vehicle (PHEV) charging points


San Diego Gas & Electric (SDG&E)

SDG&E stands out as having an outstanding AMI outreach and deployment methodology. Its “90/60/30” day communications plan prior to each community deployment now serves as a best practice adopted by many other utilities across the USA.

One of the early implementers, SDG&E had almost all of their meters deployed before federal stimulus funding was offered for smart meter deployment. This made them the first utility in the USA to cover their entire service territory with gas and electric smart meters. Taking the lead can also mean running into a lot of unanticipated challenges, but SDG&E also did two years of deep design work prior to doing any deployment. Customers were even involved in a co-design process prior to the first AMI deployment in 2009. Consistent with their commitment to customer engagement, SDG&E has also fully implemented the Green Button data platform, which is described later in the Future Steps section. Unsurprisingly, in California and the broader USA, SDG&E is known as a leader in AMI and smart grid for customer engagement.


  • Early drivers (pre-2009): safety, reliability and efficiency
  • Current drivers: leveraging AMI for distributed generation and customer energy efficiency

Current Status 

  • Fully implemented Green Button data platform
  • High satisfaction: 0.016% claims & complaints rate; 0.05% of customers joined the “delay list”
  • Opt-out program in place (initial $75 fee + monthly $10 charge. Low-income customers may opt out at reduced rates: initial $10 fee + monthly $5 charge.)

Complementary Technologies, Systems, and Processes 

  • 57,000 programmable controllable thermostats


Lessons Learned & Best Practices

Customer Engagement

A lot of the early messaging with smart meter deployment was around conservation and savings. Since then, the messaging has become more tempered to allow for fluctuations in customer bills for unrelated reasons. For example, weather-related billing spikes following the installation of smart meters, can incorrectly lead customers to attribute the billing spike to smart meters. This serves as a reminder that unrelated (e.g. weather) events can impact customer perception of AMI benefits.

In this light, one lesson learned is the relationship between customer engagement and operational benefits. Specifically, utilities that aim to achieve operational benefits that are evident the consumer, such as faster restoration times, find better value in their investments.

Customer communication has also become more sophisticated by using different methods appropriate to reaching different customer segments. SDG&E’s 90/60/30 plan is a good example of how to employ frequent messaging with different channels to facilitate a positive customer experience.
The language has become more direct, avoiding jargon, to help customers understand new systems and realize their benefits. Addressing customer privacy concerns early, with fair, transparent and progressive privacy principles, is an example of how to avoid potential customer opposition.
The intended customer benefits become even more transparent when they’re measured and reported on by the utility to their customers.

Finally, for those customers with concerns that can’t be resolved through outreach and engagement, opt-out provisions within the AMI deployment plan are increasingly a standard component adopted by utilities. Regulatory authorities have recognized the value of customer choice in this regard.

Organizational Change

Utilities have recognized that AMI deployment is not simply about installing new technologies. It marks a shift in the function of the grid, the services the utilities provide, and a shift in the customer-utility relationship.
All of this stimulates organizational change for the utility. The most successful utilities in this respect created a strategy for internal utility change management. This strategy included details such as investing in staff training for customer service and field personnel to be well informed about the full range of smart grid and AMI issues and benefits.

System Integration

On paper the fully integrated system design elegant. However a key challenge remains with tying together numerous software packaged so that billing, monitoring and SCADA all work in unison.In this respect IT & integration costs represent a non-trivial and ongoing expense. Also, a key part of utility change management is involving IT staff early on as an integral part of the planning team.

Business Case

The impact of AMI goes far beyond the direct customer benefits of billing. While these benefits are important to measure, it is also important for utilities to recognize the value of complementary technologies, systems and processes that leverage the value of AMI. For example, AMI provides cost effective outage management, grid visibility and solar PV integration capabilities. This is important to consider because while the AMI business model pays for itself in many cases with direct benefits, standing issues of declining utility revenue margins may require a new regulatory paradigm to support ongoing smart grid integration. Performance-based regulation would assign value to the added capabilities that investment in AMI coupled with other smart grid technologies can offer.


Future Steps

Looking ahead to emerging technologies enabled by AMI, California utilities are participating in some exciting initiatives. The Green Button initiative and solar neighbourhood pilot are examples of ways that AMI is stimulating innovation for customers to participate with both demand-side and supply-side technologies on smart grids.

Figure 15 : PV and Energy Storage Demonstration at Anatolia Subdivision


Sacramento Municipal Utility District solar PV and Storage with AMI pilot in partnership with the National Renewable Energy Laboratory

The solar neighbourhood in SMUD’s network showcases one of the best communications between solar PV inverters and customer smart meters. When a meter gets a signal from the transformer that there is network congestion, it tells the inverter to start feeding the solar electricity into a battery so as to reduce distribution voltage violation. With this capability, smart integration of solar PV can defer overall distribution system upgrades.

The Green Button Initiative, already available for all SGD&E customers, grants customers transparent, timely access to their energy usage data. Customers can download up to 13 months of their personal electricity data in an XML file from the utility website. Customers then can choose to share this data with third parties of their choice, which opens the door for entrepreneurs and customer service companies to offer competitive solutions for customers to manage their energy use.


Key Regulations, Legislation & Guidelines

CPUC rulings: http://www.cpuc.ca.gov/PUC/energy/smartgrid.htm

July 2006: California Public Utility Commission (CPUC) approves first major IOU AMI deployment (PG&E)

April 2007: CPUC approves SDG&E smart meter proposal

September 10, 2009: CPUC expedites review process for smart grid funding under Recovery Act

July 2011: CPUC adopts privacy and security rules aligned with “Fair Information Practice” principles

Sept 2011: CPUC mandates a “delay list” for IOUs to allow customers to temporarily delay installation

April 2012: CPUC mandates an “opt-out” provision for SDG&E and Southern California Edison

Oct 2012: CPUC mandates HAN data be made available to consumers

The Green Button Initiative: http://www.greenbuttondata.org/


California’s Electricity Grid Policy

California’s policy and regulation has been supportive of smart meter deployment, with a provision for handling customer cases for delaying or opting-out of smart meter installation. The California Public Utilities Commission (CPUC) was the first state regulator to adopt privacy rules for customer smart meter data. The privacy rules are centred on the Fair Information Practice Principles adopted by the Department of Homeland Security. Other states are now following California’s lead.

Furthermore, the CPUC required the 3 major investor-owned utilities in California to create a roadmap for modernizing their infrastructure. Since 2011, these utilities have been submitting 10 year smart grid deployment plans outlining their vision for 1) Smart Customer, 2) Smart Market, and 3) Smart Utility under the California policy framework for smart grid.

California also has aggressive renewable energy goals which drive some of the direction of smart grid strategy. With a goal of 20 GW of renewable energy capacity by 2020 (12 GW DG, 8 GW utility-scale), California has targeted to have renewable energy make up 20% of the supply capacity by 2010, 25% by 2013, and 33% by 2020.

While the drivers for smart grid policy and planning vary from state to state and by utility, investment in smart grid technology throughout the US has been bolstered by national funding. The Smart Grid Investment Grant program, which began in 2009, has funded 50% of projects in the US, 62 of which are AMI projects with smart meters, communications networks, hardware and systems related deployment.

※ Sections of this case taken from California Public Utility Commission documents, DOE sponsored Peer- to-Peer workshop findings, and presentations by each of the 4 utilities.

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October 5, 2015


Smart Meter Roll Out

By smartgrider In Advanced Metering Infrastructure, Case study Posted 2014-07-12


Market structureElectricity market is deregulated for supply and production of electricity. The Network Companies operate the distribution network on a monopoly market. Network Companies are responsible for installing, reading and maintaining them. In most cases they own the meters.
Number of retail customers5.2million
Electricity consumed-2011139.3TWh
Peak Demand for Power -2011 27,000MW
Net Revenue to Distribution41 billion SEK, 4.8 billion euro, approx.
※This is only for the network service
Distribution Network• 545 000 km lines of which
• 329 500 km underground and 215 500 km overhead lines
• Transmission lines are 15 000 km at 400 kV and 220 kV
• 170 Network Companies , various size, some publicly and privately owned
ContactMagnus Olofsson
Elforsk AB


Smart Meter Roll Out

Sweden’s large scale deployment of Advanced Meter Infrastructure began in 2003 when the Swedish parliament decided that by 2009 all electricity customers should have monthly billing based on actual consumption from monthly meter readings for residential and small business customers. Action following the legislation was delayed over a relatively long time period in effort to ease the transition. In 2006 the legislation was amended to require hourly readings from larger customers with fuses above 63 A. Altogether, these requirements resulted in a full scale installation of AMR/AMI systems for nearly all Swedish consumers (5.2 million). The total cost for the full roll out of AMR/AMI systems is estimated at 1.5 billion euro.

Figure 7 : Vattenfall type example of different AMR/AMI system used in their smart meter roll -out

The AMR/AMI system architecture consists of the meters, data collectors and the network company’s data management system for billing. Over the six years of the roll-out smart meter technology advanced significantly, resulting in different types of meters throughout Sweden based on when a network company procured the meters. In 2012, a bill was passed enforcing hourly metering at no extra cost for any consumers subscribing to an hourly-based electricity supply contract. Early experiences show that few end-customers sign up for this type of contract.


Regulatory Objectives & Benefits

The main goal of the 2003 electricity meter reform was increased consumer awareness and ability to control their consumption with more accurate electricity bills, simplification of the supplier switching processes, and better information about their actual consumption. It should be noted that there was no regulation as regards to functionalities of the metering system. Smart meters rather became a consequence of the regulation for billing based on actual consumption, requiring automatic and remote meter reading.

Before the reform, electricity for most private customers was read on a yearly basis with billing based on the previous year’s consumption. Customers received a reconciliation bill for the difference between the previous year’s consumption and the actual consumption, as the network company didn’t know the actual consumption until the end of the year. To a large degree this also meant that the customers unaware of their actual consumption, causing frustration once a year when customers were at risk of receiving a large reconciliation bill for the whole year before learning about any change to their consumption. Since July 2009, customers receive monthly bills based on their actual consumption which has led to increased customer awareness and activity in the retail electricity market.


Current Status & Results

By 2009 all Swedish customers had smart meters and AMR systems. Over the years since deployment, many network companies have found their roll-out led to both expected financial benefits and to non-financial benefits in service quality, customer satisfaction and improved safety on the network.

There wasn’t much public opposition to Sweden’s smart meter roll-out. In part this was because the majority of the electricity bill in Sweden is the cost of energy and taxes, not the network costs, so the cost of implementing the AMI/AMR was only a fraction of the bill. In the initial proposal for the meter reform the regulator requested hourly metering instead of monthly metering, this was however strongly opposed by the network companies. In Sweden concerns about the accuracy of data and customer privacy in conjunction with the smart meters has rendered little discussion. In general the handling of meter data is regarded as acceptable by the customer.

In terms of AMI/AMR functionality, Sweden’s infrastructure does not yet have all of the components for customer demand response activities. Dynamic pricing, easy customer access to their own data with visualization tools or other components that improve a customer’s control over their consumption are not yet common across the systems, however the functionalities are in most cases sufficient to deliver significant benefits compared to the alternative of not rolling out the smart meters. As the Swedish regulator is shifting the market to hourly metering and considers hourly energy prices, customers will need support to facilitate their response to price signals from the market and any other load management programs. Some of these capabilities are currently under development through the Proactive Forum discussed at the end of this case, while others will be implemented via other channels.

Project Details

  • Smart Meters and Advanced Meter Management System
    •  5.2 million smart meters deployed
    • Local communication
      •  50 % PLC (power-line carried communication)
      • 30 % LPR (Low power radio)
      • 15 % GPRS
      •  5 % other
    •  Communication to central system
      • 70 % GPRS
      • 20 % POTS (plain old telephony service)
      • 5 % SWR (short wave radio)
      • 5 % private fixed wire copper or fiber optic networks
  • Tariffs:  Currently most customers are charged a price for consumption based on a monthly average but may opt-in to hourly spot-tariffs reflecting to capture more value from AMI/AMR.
  • Project Cost:  1.5 billion euro/ 6 years
  • Project ROI:  Individual network companies have measured operational savings and increased value related to the decreased costs of switching retailers with the AMI/AMR. Nation-wide benefits are still TBD.


Lessons Learned & Best Practices

Customer Engagement

For Sweden, the first step for enabling the customer to participate in a more efficient market was to build their awareness of their consumption and of what type of contract they had signed with their current retailer. Increased customer activity in the retail market was a major driver for AMI/AMR deployment in Sweden. Once customers began to move from annual meter readings to monthly readings, they also became more aware and concerned with their electricity use. This has set the stage for future technology and market pricing that will allow the customer to participate in a more active retail market. There were some opponents to the process of the meter reform, which occurred because important aspects of the customer-utility relationship weren’t clearly investigated before the roll-out. With the initial focus on intended billing and market changes, smart meter installation and customer conservation benefits were a later evolution in the project objectives. With this shift in objectives, customer communication and engagement became more central to the roll-out.

The Role of the Regulator

As with many jurisdictions, a critical factor for the Swedish roll-out of smart meters was the allowance for network companies to include smart meters as part of the asset base to ensure cost coverage. Born out of the initial focus on accurate billing and a more active retail market, the Swedish regulator is now pushing for future customer capabilities built on the AMI system. This pro-active role for the regulator is somewhat unique to Sweden.

The Business Case for AMI

The capability for remote upgrades of the meter software is critical to the overall functionality of the AMI system, and to the value proposition for the customer. Still, all that value was threatened if there wasn’t enough preparation for system accuracy in meter readings and communication. Some early movers found that the business case disappeared with the costs of the field work required to fix inaccuracies and improve the system efficiency. Also the low-voltage network documentation must be accurate and detailed enough for efficient implementation of AMI.

Almost every network company chose to buy complete meter-system solutions under turnkey contracts with long term functionality guaranties. Some of the contracts also included full service for several years, all in the attempt to minimize the risk to the network company and the customer. This shifted the risk to the manufacturer, which had an effect on the meter market. Overall the meter market changed in many ways during the roll-out: several meter manufacturers and suppliers filed for bankruptcy and a few folded their local operations. Some local manufacturers were bought-out in the early wave of consolidations and some players restructured their local business models.

Despite the attempt to mitigate risk, some concern remained over the decision of many network companies to install propriety AMI systems. This was perceived as a risk to technical support and service should the supplier go into bankruptcy. There are some persistent concerns that this might result in many systems being exchanged long before their estimated end of life. This issue is being addressed in part through developing minimum standardized functionality for meters which improves their likelihood of interoperability with other technologies and proper functioning throughout their lifespan. This initiative is discussed later in the Proactive Forum section. Not fully accounted for in the original business case, the improved understanding of the grid behaviour and load pattern has allowed network companies to make more strategic decisions about infrastructure upgrades and has reduced the risk of over-sizing assets. As a platform for other smart grid technologies, many future services will be enabled by the data and the functionality of the AMI.

Communications Operability

A common problem with the roll-out reported by many network companies was the difficulty in getting the communication with the meters to function properly. In general it was found that meter data sent on the electricity grid (PLC-technology) was more problematic compared to for instance radio communication through GPRS which experienced fewer problems. Furthermore, network companies reported situations where meters had to be serviced or replaced because the communication technology was not durable enough.

During the roll-out a few manufacturers delivered batches of meters with faults. This necessitated a replacement of several hundred thousand meters.


Vattenfall, 10 Years of Experience with Smart Meters

Vattenfall Distribution, Sweden’s largest network operators, began its smart meter roll-out in 2003. The roll-out occurred over three phases that each focused on different geographic regions in the country. From 2003 – 2008 Vattenfall installed 860,000 meters for residential and commercial customers. The Smarter Meter development in the market during the roll-out, as well as an increased experience of new meters for each new phase was reflected in an increasing functionality and lower incremental investment and service cost as deployment moved forward. Figure 12 shows the functionality of the meters and metering costs over the roll-out phases (AMR1, AMR2 and AMR3), and the degree to which to the overall system is completely (green) or partially (yellow) functional in the areas of remote reading, interval registering, two-way communication, remote management/remote switch off and visualization.

The initial business case for Vattenfall was primarily based on decreased reading and service costs when manual reading could be automated and done remotely. Besides the savings in regular reading for billing, the AMI/AMR also provided operational savings when customers moved in and out, as well as when customers switched from one supplier to another. During the roll-out it also became clear that it was very important to not underestimate the effort needed to reach the expected system performance. Only a slight increase in the number of errors in comparison to the expected level caused much manual work which had large impact on the business case.

Figure 12 : The increasing functionality and decreasing costs of Vattenfall’s AMR deployment through each phase, and overall system functionality. The level of functionality for different AMI capabilities in relation to common European Commission minimal requirements is indicated by the traffic light images where green indicates total, yellow partial, and red no system functionality.

The reduction of non-technical losses turned out to bring large additional indirect benefits that weren’t accounted for in the initial business case. The AMI/AMR system improved Vattenfall’s control of non-technical network losses caused by broken meters, thefts, faults in data quality, faults and missing meter values, etc.

With the steady state operation of the AMI/AMR system, Vattenfall found that it delivers more network benefits than expected. Some major examples include:

  • Detection of zero ground faults. The AMI can detect a loss of ground connection, and resulting higher voltages in the network, which increases safety for customers and personnel.
  • Reduced customer complaints. The presentation of daily or hourly consumption data to customers has improved the customer service experience with increased transparency
  • Reduced costs from remote connect/disconnect switching. Sites without electricity contracts, such as empty apartments or overdue accounts, can be disconnected efficiently to minimize risk and customer costs.
  • Power outage compensation. Customers no longer need to call in to report an outage, meter data also ensures that customers are compensated correctly.
  • Low Voltage (LV) network quality monitoring. Quality monitoring ensures that customer power quality aligns with the regulation. This increased customer service commitment relies heavily on accurate network documentation.


Next Steps – The Proactive Forum

Swedenergy, the power industry and special interest organisation for companies involved in the supply of electricity in Sweden, has worked out recommendations for requirements on AMI. The work is a result of a working group named Proactive Forum. In brief, the recommendation is to keep the meter simple. This means, for example, that utility signals or communication with the customer will not rely on specific meter functionality. Instead, internet or other protocols through various media such as wireless networks may be used as input for customer participation in demand response.

In order to enable the customer to receive high resolution data at or near real time, it is recommended that customers connect data output from the meter locally using a standard port. This design along with customer data access supports will strengthen the customer position while at the same time avoiding unnecessary investments in data processing and transfer between the network company and the network user. A schematic presentation is given in Figure 13.network company and the network user. A schematic presentation is given in Figure 13.

Figure 13 : Schematic presentation of Swedish recommended division of responsibilities for services related to smart metering and customer participation in demand flexibility


Key Directives, Legislation and Further Resources

Directive 2009/28/EG of the European Parliament and of the Council, on the promotion of the use of energy from renewable sources

Directive 2009/28/EG of the European Parliament and of the Council, concerning common rules for the internal market in electricity

Swedish government bill 2009/10 : 113, Effektreserven i framtiden

Proactive Forum website:  http://www.svenskenergi.se/sv/Kompetens/webbshop/Gratisprodukter/Elaret/Proaktivt-forum-for-Elmatare/

Technical codes and standards work:
local data exchange; Amendment A
: Mode D DFI interface with OBIS codes
http://www.iec.ch/cgi-bin/restricted/getfile.pl/13_1518e_NP.pdf dir=13&format=pdf&type=_NP&file=1518e.pdf


Sweden’s Electricity Grid Policy

Swedish Electricity Grid Policy has been formed out of a combination of regulation and government targets. The European Union’s 20-20-20 targets in 2008 became part of that policy and set targets for decreased GHGs, increased renewable generation and energy efficiency that guided the larger policy objectives for AMM systems in Sweden. There are four general goals for the Swedish energy system pushing the development in the electricity grid:

  • Objective to Reach at Least 50 % Renewable Energy as a Share of Total Energy Use by 2020
  • Objective to Reach 20 % more Efficient Energy Use by 2020 requiring Increased Consumer- Engagement ? Spatial Planning Target for Increased Wind Power from 4.5 TWh (2010) to 30 TWh by 2020
  • By 2030, Sweden should have a vehicle stock that is independent of fossil fuels

In 2012 the government launched a Smart Grid Council made up of representatives from agencies, government, utilities and the private sector, who are currently investigating different strategies for smart grid in Sweden.

※ Information in this case was provided by the Swedish Energy Agency, the Association of Swedish Electric Utilities, Swedenergy and from Vattenfall.

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October 5, 2015


Ontario Smart Meter Deployment Project

By smartgrider In Advanced Metering Infrastructure, Case study Posted 2014-07-19

The Netherlands

Market structure:Liberalised market structure: network operators and energy retailers unbundled. Energy production, trading and retailing have become commercial activities. Smart meters are owned, installed and maintained by the public distribution system operators
Number of retail customersAppr 7.0 million
Electricity consumed-2011Over 120 TWh
Peak Demand for Power-201117 MW in the transmission lines -Tennet TSO figure updated in 2013
Net Revenue to Distribution Companies€32.693 million Euro.
Distribution Network• Electricity: 309.502 km
• Gas: 135.229 km
• Heat: 4.894 km
ContactHenk van Elburg.
Senior consultant, NL Agency,
Ministry of Economic Affairs.
Henk.vanelburg@agentschap nl.nl


Ontario Smart Meter Deployment Project

In 2011 the Dutch parliament accepted a revision with respect to the smart meter in the Dutch Electricity Act andthe Gas Act. This revision mandates net operators, who are the owners of the smart meters, to offer households and small businesses a smart meter with minimal functional and technical requirements. Actually this entails two meters, one for electricity usage and one for gas. The smart meter rollout takes place following a two-stage approach. From 2012 until 2014 a small-scale rollout is in place for experience purposes. During the small-scale rollout, up to 500.000 smart meters for electricity and gas will be installed in cases of regular meter replacements (e.g. depreciation), newly built houses, large scale renovations and on request by customers. Based on these experiences, from 2014 the rollout will continue on a larger scale, eventually offering every household (and small business) a smart meter. The aim is to have a smart meter fitted in at least 80% of households and small businesses by 2020, as mandated through the 3rd Energy Package.

When offered the opportunity of receiving a smart meter, households and small businesses have a legal choice in accepting this meter, ranging from having no smart meter at all to a smart meter fully equipped to provide interval data to the network operator for self chosen energy management services. For privacy reasons when accepting a smart meter, the customer subsequently has to authorize the network operator to automatically collect consumption data for requested purposes such as bimonthly energy reports, annual billing, switching supplier and moving home.

The revised law also mandates energy suppliers to provide consumers with bimonthly home energy reports as a standard feedback service. Additional regulation has been developed to set out the minimum information requirements for these energy reports. Providing consumers with more detailed smart metering feedback services for household energy management such as displays and internet applications however are considered to be a market responsibility without regulation. The customer is free to choose and authorize any commercial service provider offering (real-time) smart meter data based information services beyond the minimum regulated level. In order to give market players access to the measurement data, the network operators have set up uniform authorization and authentication procedures. These procedures ensure that individual measurement data is only used for the specific purposes for which the customer has given his or her consent.


Objectives & Benefits

The goal of the two-year small scale phase is to gain experience with and detect bottlenecks in an early stage before the next phase, the large scale roll out of smart meters in the Netherlands. The Dutch Energy Regulator (named Nma) supervises the rollout and the consumer satisfaction with installation and issues for example related to privacy protection and security issues. Additionally, NL Agency (part of the Ministry of Economic Affairs) monitors consumer energy savings and economic developments that are expected to come with the introduction of smart meters and new service providers.

In the Netherlands the smart meter roll out is part of a broader new energy market model for domestic and small business users. Apart from the desire to correct and avoid administrative problems, following the liberalisation of the Dutch energy market in 2004, other main drivers were to stimulate competition in the energy market (e.g. easy switching for consumers between suppliers), improve operational efficiency for market parties and support energy savings for end use users. Demand response related objectives, such as limiting consumer peak load demand on hot summer days, played a less important role because of the temperate climatic conditions. The Dutch tariff system today has been based primarily on fixed rates. The only basic and static form of demand response in the Netherlands so far is the option to choose a meter that allows a fixed switch between two tariffs: day and night/weekend tariffs. However, it is expected that the rollout of smart metering in the Netherlands will encourage some introduction of commercial based flexible tariff schemes. Except for these national reasons, the legal roll out proposal was also designed to meet the requirements of the European Energy End-use and energy Services Directive (ESD, 2006/32/EC). The Dutch government states Article 13 is a claim for smart meters and bi-monthly home energy reports.


Planning for Success & Making the Business Case

The Dutch deployment plan for smart meters took advantage of earlier experiences with smart meter out roll in Western Europe, notably Sweden and Italy were the percentage of smart meter penetration and acceptation is close to 100%. Also the UK and Spain developed plans for a 100% roll out of smart meters. Although privacy issues are recognised in Europe, the have not played such a prominent role as in the Netherlands. The reasons for this are not entirely clear except that it is part of a process of growing awareness.

The estimated energy savings in Western Europe range from a few percent to exceeding 10%. Other savings include costs for call centers and meter reading. Furthermore a positive effect is expected on comparing energy retailers by households and switching between them. In 2010 DNV KEMA calculated that in a standard situation of 100% smart meter acceptation and smart meter reading there is a positive business case of 770 million euro net worth. An important condition however is that in case 20% of the households accept the smart meter but refuses the smart meter read out, this business case is seriously compromised, while the households still have the benefit of the digital port. This and the additional costs for security and privacy issues are important modifications to previous calculations made in 2005 by the DNV KEMA (see note 1).


Current Status & Results

As already mentioned, the rollout of smart meters in the Netherlands officially started in 2012 following a two-stage approach. From 2012 until 2014 a small scale rollout will take place for experience purposes. The small-scale rollout will take place only in case of regular meter replacements (e.g. depreciation) or new meters to be placed in newly built houses and finally renovated houses and new meters on request by customers.

Part of the small-scale experience phase is a national monitoring programme to provide evidence and insights in the expected energy saving effects following the introduction of smart metering. By order of the Ministry of Economic Affairs, NL Agency designed a monitoring programme to assess the effects in household energy consumption and support the upcoming decision for an optimally designed universal full smart metering rollout. In order to draw practical lessons on the experience and expertise of relevant (market) actors, a suite of large and scientific designed trials across the country is now being assembled in close cooperation with the Dutch public network operators. Following similar national trial programmes in the UK (EDRP) and Ireland (CBT), the Netherlands is the third EU-Member State to perform such a series of consumer trials to deliver differentiated evidence for the energy efficiency potential to a range of smart metering based feedback methods on energy consumption and associated costs and to contribute to balanced decisions favouring the future rollout of smart meters. The Dutch monitoring program covers the largest and statistically most robust smart metering behavioural trials conducted nationally to date and are expected to provide a wealth of public available information on the impact of smart metering enabled initiatives on Dutch electricity and gas consumers.

The monitoring program distinguishes two types of informational stimuli for dual fuel metering (electricity meters and gas smart metering leveraging the electricity smart metering communications infrastructure).

1. Effect of cost and consumption overviews

On the one hand, the programme will focus on the actual measurable reduction effects in customers’ electricity and gas demand achievable through the use of smart meters in combination with bimonthly home energy reports. The reports will be required to give a comprehensive account of the customer’s energy usage and associated costs. Part of this will be a comparison of the customer’s consumption with the equivalent period in the previous year, and a comparison with the consumption of their peer group. These comparisons should be provided in graphical format where practicable. This is similar with the informative billing requirements in the EU Energy Efficiency Directive (2006/ 73) although the informative statement need not necessarily be paper-based.

For the effect monitoring of the home energy reports, a representative sample of over 30,000 anonymous residential electricity and gas consumers with smart meters throughout the country will be involved in the trial. A control group, made up of app. 300.000 consumers with traditional meters and who are not provided with any additional information about energy consumption, will be included by the statistical advisors to ensure a robust experimental trial design. Their energy consumption will be recorded as well to enable comparisons with the households that have received interventions under the trial programme.

2. Effects of additional information stimuli

On the other hand, a suite of additional smart metering services trials is programmed to investigate the behavioural and potential measurable reduction effects in customer electricity and gas demand achievable through the use of smart meters in combination with other (free market) energy monitoring and managements systems. These interventions include in-home displays, web-based information systems and community-based concepts. In total over 1,400 residential consumers throughout the country will participate in additional metering services trials. The participants are allocated across different population groups and connected to control groups by the statistical advisors to ensure a robust experimental trial design. Unlike the effect monitoring of the bimonthly home energy reports, sample sizes in this ‘alternative’ programme category will not appear large enough to ensure robust statistical soundness. Therefore, the results in this program category should not be qualified as fully representative and reliable from a statistical point of view.

All trials in the national monitoring programme will be performed by or in cooperation with the largest Dutch network operators Liander, Enexis and Stedin (representing approx. 90% of all meter connections in the Netherlands) under the scientific supervision of academic statistical advisors. The statisticians will analyse the consumption data collated from the trials to determine the customer response to the smart metering enabled measures tested in terms of the impact on their overall electricity and gas usage. Pre-trial and post-trial surveys of trial participants will also be conducted to draw demographic, behavioural and experiential conclusions from the trials. Due to the different nature of the trials, technical issues and other issues, most pilots have taken place at different times.
NL Agency oversees these pilots and is responsible for undertaking the design and coordination of the monitoring programme on behalf of the Ministry of Economic Affairs. As part of this work, NL Agency is also responsible for monitoring market developments of commercial based smart metering services. Finally NL Agency will arrange a series of stakeholder meetings with representatives of consumer associations, academic institutions, metering and/ or service providers in order to discuss and find broad support for the outcomes of the national monitoring program.

This way the monitoring program provides robust and fact-based public information about the possible energy saving merits of smart metering services for residential (and SME) consumers in the Netherlands. In addition, the impact of different services on consumer behaviour and attitude might help cast light on the relative attractiveness of various media, function and design options for specific metering service concepts. The key trial findings related to the actual, behavioural and attitude effects on household electricity and gas consumption are expected to be an important source of information for parliamentary evaluation of the small scale roll out in the second half of 2013. The statistical evidence from the trials will also provide relevant consumer information for the commercialising and/ or deployment of these smart metering enabled informational stimuli by free market players. If so desired, the results can also be inputted into future cost-benefit analysis to derive consumer usage-related benefit values.


Lessons learned & Best Practices

The original plan.

In 2008, the Dutch government presented a first legislative proposal to bring the smart meter under the responsibility of network operators in the regulated domain in combination with a mandated rollout to all households. Following consultations in the market sector, the Ministry of Economic Affairs proposed the following meter market changes:

  • All small users will be given a smart meter;
  • The grid operators will be responsible for rollout. The grid operators will own and maintain the smart meter and be responsible for a total distribution;
  • The meters will become part of the regulated domain of the grid operator, being considered as part of the physical infrastructure;
  • The cost of the hardware (meter hire) will be regulated;
  • The energy retailers will be responsible for all customer-related processes and metering data management;
  • The smart meters must comply with the basic functionality and technology mentioned in the smart meter industry standard NTA-8130 and technical requirements according to the Dutch Smart Metering System Requirements (DSMR) set by the Dutch association of network operators.

To meet the obligation arising from the above-mentioned ESD to provide regular feedback to consumers about energy consumption, the government stated a preference for setting a minimum frequency of 6 times per year (every two months).

The government proposed a mandated rollout as a prerequisite, because it was expected that a smart metering rollout in a liberalised market, without further regulation, would probably reach no more than about 30% penetration. In that case, several of the smart meter benefits mentioned above would not be realised.

The rollout will partly be funded from the current meter tariff. This tariff will be stable in the first years of the roll out and should remain unchanged or even drop. To date the meter charge has not been regulated and has increased by up to 100% since 2001. The Dutch regulator (NMa) has stated in 2008 that there was no relation between the increased tariffs and the actual costs of the meter.


Revised plan 2010: voluntary roll out of smart meters

In 2009, after intense political debate, the Dutch Senate declined to approve a mandated rollout of smart meters because of privacy and security concerns raised by the national association of consumers (Consumentenbond). To solve the stalemate, the mandatory roll out of smart meters was turned into a voluntary rollout. Furthermore the revised proposal settled security concerns by introducing additional security guarantees. This proposal was approved by the senate in 2011. In the revised proposal the consumer has the following legal options when offered a smart meter:

  • The option to refuse the installation of a smart meter and keep the traditional meter;
  • The option to have a smart meter fitted (or once it has been installed), but opt out of sending meter readings automatically (so smart meter functions as a traditional meter, a meter reader is still required);
  • The option to have a smart meter fitted, with standard meter reading frequencies of which the most important are: final billing in case of switching energy supplier or moving house, once a year for annual billing and bimonthly meter readings for additional energy advice in cost and consumption overviews.
  • The option to have a smart meter fitted, with full automatic and wireless smart meter reading.

The revised law proposal also required the Ministry of Economic Affairs to perform a recalculation of the national cost-benefit analysis performed in 2005 regarding the business case for the introduction of smart meters in the Netherlands.[1] Two major changes that prompted a new cost-benefit analysis were:

  • The smart meter will only be read once every two months in the standard situation. Only if express and unequivocal permission has been obtained from the consumer, more detailed reading can be done. In the 2005 analysis detailed reading was still the standard situation.
  • The consumer will have the option of refusing the smart meter. This means that the consumer in question will keep his or her traditional meter. In the case of new construction and renovations of houses and small buildings it is compulsory to install a smart meter, and there is no obligation to replace it with a traditional meter at the request of the consumer. In this case the consumer can have the smart meter treated like a traditional meter by registering it as ‘administratively off’.

Considering a situation of almost 100% acceptance of the smart meter as well as almost 100% standard readings, the updated cost-benefit-analysis still showed a positive business case result of approximately EUR 770 million. The main beneficial items (in order of positive contribution) are energy savings, savings on call centre costs, a lower cost level as a result of the market mechanism (increased switching) and savings in meter reading costs. Assuring the freedom of choice for the consumer, the revised law proposal passed in the Dutch House of Parliament on 9 November 2010. The Senate approved the revised proposal in January 2011.

[1]Prior to the original proposed changes in the Electricity Act and the Gas Act, which included a mandated rollout of the smart meter, a thorough cost-benefit analysis was conducted in 2005. This cost-benefit analysis, performed by KEMA by order of SenterNovem (now Agentschap NL), resulted in an expected positive business case of approx. EUR 1.3 billion (SenterNovem, 2005).

Next Steps

The next big step will be the start of a large scale role out of smart grids, as the pilot projects are reaching their final phase in 2015 and international lessons are being learned. Specific actions still are necessary concerning the regulatory framework, standards and interoperability, cyber security and privacy, consumer awareness and behaviour, new products and services.

Key Regulations, Legislation & Guidelines

Regulator NMA website: http://www.nma.nl/wet__en_regelgeving/energiewetten/default.aspx

Handbook Smart Grid Pilot Projects Regulation (in Dutch):
Part I http://dare.uva.nl/document/443770 
Part II http://dare.uva.nl/document/443777

“Intelligente Meters in Nederland: herziene financiele analyse en adviezen voor beleid.” (KEMA 2010)
“Energy in the Netherlands 2011.” (Collaborating Dutch sector organisations)
“Innovation contract Smart Grids. Headlines of a Public Private Partnership and Innovation Agenda 2012”


The Dutch Smart Grid Policy

Smart grid policy is part of the national top sector approach and energy is one of the nine top sectors. Within the top sector energy “smart grids” is an important pillar that contributes to the overall goals of 16% renewable energy, 20% CO2 reduction in 2020 and yearly energy savings of 2%. The top sector energy aims to be of world class in its respective technology fields and assure the competitive position of the sector and the Netherlands with respect to energy. The Dutch top knowledge institute (TKI) for smart grids plays a crucial integrating role for the different technologies connected to the grid and large scale role out of renewable energy sources, related devices and energy storage.

Without smart grid these would lead to higher fluctuations in energy demand and production, unbalances in the grid and higher investments into the energy infrastructure and its maintenance. Finally the application of ICT and smart meters makes it possible to deliver direct feedback to the end consumers concerning their energy usage. According to several studies this can lead to greater awareness and between 3 to 10% energy savings, less CO2 emissions and lower maintenance costs of the grid. In addition new products and services can be developed on top of this smart grid. To explore these new applications and business cases a program of demonstration projects was initiated in 2011 and a year later the TKI for smart grids launched its R&D projects.

※ Information in this case was provided and compiled from existing sources by the Dutch NL Agency, Directorate Energy and Climate.

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October 5, 2015


AMI as a Prerequisite to the Nationwide Smart Grid

By smartgrider In Advanced Metering Infrastructure, Case study Posted 2014-07-06


Market structureHybrid structure of vertically integrated and single buyer utility- KEPCO. KEPCO owns, installs and maintains all meters.
Number of retail customers50 million
Electricity consumed-2011443.4 TWh
Peak Demand for Power-201173,137 MW
Net Revenue to DistributionOver 600V : 209,604 km
Under 600V : 225,945 km
Distribution Network-
Contact Dong-Joo Kang djkang@keri.re.kr
Sung-Hwan Song karysong@keri.re.kr
Electrotechnology Research Institute, KOREA


AMI as a Prerequisite to the Nationwide Smart Grid

Korea’s National Smart Grid Roadmap places Advanced Metering Infrastructure (AMI) as the core to its smart grid functionality. Korea’s approach began with the Power IT project, from 2005 to 2009. It was an R&D project, which mainly focused on core component technologies for applying IT to the power system. The next phase is the Jeju Smart Grid Demonstration project, which is acting as a test-bed for a number of smart grid technologies and use cases. According to the final phase of the Roadmap, it is planned for AMI deployment to take place in major cities of Korea from 2013 to 2020 followed by the nationwide deployment which should be completed by 2030. AMI is positioned as a prerequisite infrastructure for smart grid and customer engagement.

Figure 6 Korea National Smart Grid Roadmap


Objectives & Benefits

Under the National Smart Grid Roadmap, the government has promoted AMI technology development for the accommodation of new renewable energy and for the increase of demand response. When making use of the Jeju Smart Place, the optimization of power supply and demand has been promoted based on the real-time information between the consumers and power providers. This has been done through AMI, Energy Management System (EMS) and bidirectional communication technology.

Figure 7 : AMI Deployment Plan 


The project objectives and benefits are:


  • Establishment of new market for two-way power trades with various resources in the demand side (facilitating negative generation: demand response)
  • Smart Grid ICT Infrastructure for bidirectional information exchange based on Power IT technology. This technology is expected to facilitate electricity market trading and create new value added services
  • Development of smart systems and smart appliances to enable customers with demand response and automatic controls responding to time-variant or real-time tariffs


  • Improvements in power quality, reliability, and cost-effectiveness of the system operation from AMI and related technologies
  •  The reduction of greenhouse gas emission and the stimulation of green energy use
  • The development of value-added services such as demand side management by optimizing power consumption patterns
  • Cost savings through load shifting to cheaper hours with economic incentives


AMI in the Jeju Smart Grid Demonstration Project

The Jeju Smart Grid Demonstration was established in Gujwa-eup, in the northeastern region of Jeju Island, in December 2009. The project will be completed in May 2013, as a precursor to the nationwide implementation of smart grid which is expected to be completed by 2030. The Jeju project was designed to promote the commercialization and export of smart grid technologies. This project consists of the five smart grid technology areas:Smart Place(SP), Smart Transportation(ST), Smart Renewable(SR), Smart Power Grid(SPG) and Smart Electricity Service(SES).

Three of the technology areas: SP, ST, and SR are currently available, while SPG and SES will be enabled once the nationwide smart grid is in effect. There are 12 consortiums involved in the project representing 170 participating companies from various business sectors such as power, communication, automobile and home appliances.

Figure 8 : Five technology areas of Jeju smart grid demonstration project

Advanced Metering Infrastructure (AMI) is included in the Smart Place technology area, with four consortiums participating as shown in Table 2. These consortiums are focusing on finding and verifying new business models for the new smart grid environment, with new electric power. The developed technologies and business models would be tested through a virtual market with real-time tariffs, a demand management market, and electric vehicle-related business. The AMI will also interact with the renewable energy interconnection and power storage devices, and by doing so, it will upgrade the current power grid. More details on individual consortiums have been provided in Table 3.

Table 2 : Jeju project consortiums participating in the Smart Place technology area


Smart Place
A Consortium
B Consortium
C Consortium
D Consortium

Government: $16M
Private: $75M

Table 3 : Jeju Project Use Case Descriptions

A Consortium• 600 households and 3 places, Jeju Venture Maru, etc.
• Formation of five kinds of the demonstration households group by combination of smart meter, in-home display, solar battery and electric vehicle
• Application of various electricity tariff system : TOU, TOU+CPP, RTP, etc.
• Implementation of energy consumption efficiency by providing of incentive-based Demand Response service
• Increases of consumer participation awareness
• Providing smart grid information by utilizing D-CATV and DMB broadcasting
B Consortium• 600 households and buildings of 7 places
• Construction of Building Energy Management Systems for high-voltage consumer such as Convention Center and University
• Excavation of a new business model of an energy sector by performing an energy service provider role. This should provide the energy management services such as load management and load shift in households, buildings and factories.
• Expanding customer choice and maximizing energy efficiency by conducting various electricity pricing system with a consulting service and analysis of the electric power usage pattern by each customer
C Consortium• 30 households and a large-scale consumer of 5 households
• Verification of energy efficiency through the building and demonstration of Smart appliances, air-conditioners, washing machine, refrigerators, etc., which have been approved by the world’s first appliance, ZigBee’s communication standard.
• Providing home energy care service based on the demonstration results of smart server, appliances and renewable facilities in the first step
• Verification of energy efficiency technology through an operation of micro-grid system in Pensions, 21 buildings and administrative building, getting electricity and gas price for 10% cheaper
D Consortium• 560 households and large-scale consumer of 10 households
• Verification of the interoperability and technical excellence between heterogeneous systems with AMI infrastructure based on PLC, Zigbee, and Wibro communication technology
• Identification of outage information from smart meters, and the demonstration of the Out age Management System for supporting the rapid recovery
• Demonstration of HEMS providing the energy management services, depending on the pattern of the consumer’s life such as age, region, occupation, etc
• The optimal demand resource management and market participation by developing regional-based demand resource management system
• Providing and DR service with an incentive-based real-time tariff system, and its effect analysis

Current Status & Results

Currently most high-voltage customers in Korea have the AMI implemented, but only 10%, or 1 million, of the 18 million low voltage customers have AMI, outside of the Jeju Smart Place project. 170,000 households in multi-residential buildings with high-voltage connections have AMI. 110,000 of those customers have a TOU tariff system based on a bilateral contract to consumers of more than 300kW. For these high-voltage customers, the potential for electricity savings could be enhanced with tools for smart phones, tablets or PCs providing usage information communicated through the AMI.

Figure 9

Project Details

  • Korea AMI deployment
    • 10% of low-voltage customers with AMI
    • 100% of high-voltage customers with AMI
  • Korean tariffs
    • TOU for high-voltage customers
    • Fixed rate for low-voltage customers
  • Jeju demonstration project use cases
    • 4 Use cases with 2190 households and 46 larger customers participating
    • Use cases with various smart appliances, In-Home Displays and Energy Management Systems
    • Range of communication PLC, Zigbee and Wibro technology
    • Demand Response cases
    • Outage Management System connection
  • Jeju demonstration project tariffs
    • Cases with Time-of-Use, Critical Peak Pricing and Real Time Pricing
  • Jeju AMI Project Cost
    • Government: $16M
    • Private: $75M
  • Project Benefit Value
    • To be evaluated

Through a phased deployment, Korea aims to have up to 55% (10 million households) of low-voltage customers connected with AMI by 2016. The complete AMI deployment for all households (low-voltage consumers, high-voltage consumers) is planned by 2020.

The AMI deployment has been planned in the National Smart Grid Roadmap as follows:

In 2013:

  • Promoting AMI supply after consultation with the corresponding operators for apartments and Area Electrical Business areas, etc

In 2014:

  • Preferential supply of AMI system in the pilot city
  • Development and supply of an energy integrated metering system that can uniformly read the usage information of electricity, tap water, gas, heat, etc.

In 2015:

  • Obligation of AMI system in construction of Housing, Commercial Area, Buildings and Apartments

In 2016:

  • Phased supply of AMI for 55% (10 million households) of low-voltage customers in the whole country

In 2020:

  • Completion of AMI for all households (low-voltage consumers, high-voltage consumers) in the whole country

While it is still early to determine the results of the Jeju AMI demonstration, a 2012 pilot study on the deployment and demonstration of smart metering system technology with in-home displays found a 12% reduction in energy consumption.


Lessons Learned & Best Practices

Korea has been investing in AMI projects since 2005 with the Power IT R&D project, followed by the Smart Grid Demonstration Project in Jeju island, that started in 2009.Korea is planning to invest approximately $7 billion until 2030 for the development of smart grid core technologies. AMI in particular, is the core infrastructure of the smart grid, and prerequisite for the realization of the green growth policy of the Korean government and global CO2 reduction policies. It is also required to create various value-added service models such as energy monitoring and automated demand response.


Tariff system

The AMI deployment will be combined with various time-variant pricing step-by-step such as TOU, CPP and RTP on the process of replacing current mechanical meters with the smart meters. Consumers can have multiple options considering their unique usage patterns and thereby optimize their consumption and cost. This is expected to bring out the innovative transformation of captive consumers to active prosumers, as well as the overall reduction of energy costs. In addition, power service providers could ensure the stable and efficient services through the collection and analysis of information from real-time data through AMI.

Figure 10 : Korean smart grid deployment timeline


Standardization and Interoperability

The AMI deployment will be combined with various time-variant pricing step-by-step such as TOU, CPP and RTP on the process of replacing current mechanical meters with the smart meters. Consumers can have multiple options considering their unique usage patterns and thereby optimize their consumption and cost. This is expected to bring out the innovative transformation of captive consumers to active prosumers, as well as the overall reduction of energy costs. In addition, power service providers could ensure the stable and efficient services through the collection and analysis of information from real-time data through AMI.


Software Development

The AMI deployment will be combined with various time-variant pricing step-by-step such as TOU, CPP and RTP on the process of replacing current mechanical meters with the smart meters. Consumers can have multiple options considering their unique usage patterns and there by optimize their consumption and cost. This is expected to bring out the innovative transformation of captive consumers to active prosumers, as well as the overall reduction of energy costs. In addition, power service providers could ensure the stable and efficient services through the collection and analysis of information from real-time data through AMI.


Export Strategy

Business models for overseas expansion will need to accommodate common AMI architecture and adhere to global standards. These aspects can be built into the domestic demonstration stages to develop an integrated package model for the overseas business marketing. Demonstration projects should be used to promote the development of strategic technologies and business models, which will have been applied to a broad range of markets such as urban areas, islands and developing countries.


Key Regulations, Legislation & Guidelines

Further information for Korea’s Smart Grid Roadmap, Jeju Test-bed, and Power IT projects:

Further information for R&D strategy on overall energy technologies:

Smart Grid Stimulus Law, 2011.11 The 1st Basic Plan of Smart Grid in Korea, 2012.07

Further information can be found at the Jeju Smart Grid website:


Korea’s Smart Grid Policy

Korea released a National Smart Grid Roadmap in 2010, which built off of the outcomes of its Power IT R&D project from 2005-2010. The Roadmap is toward smart grid deployment across the major cities by 2020 and the whole country by 2030. This Roadmap complements the country’s strategy for ubiquitous connectivity and the convergence of a number of its IT business capabilities. The main focus of Korea’s smart grid policy is placed on the development of new services and business models for the green growth strategy of Korean government.

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October 5, 2015


Telegestore, Automated Meter Management Project

By smartgrider In Advanced Metering Infrastructure, Case study Posted 2014-07-12


Market structureLiberalized demand market; all customers may choose their supplier. About 17% of household and 36% of non-residential customers have chosen free market retailers. The remaining is served by the universal supply regime. DSOs are responsible for metering activities
Number of retail customers Approx. 37 million
Electricity consumed -2011> 300 TWh
Consumed -201170% in-state, 30% import
Net Peak Demand for Power -201150,000 MW
Net Revenue to Distribution Companies> 8 billion euro
Distribution Network -2011830,696 km of LV lines
379,705 km of MV lines
143 DSOs operate the electricity distribution networks in Italy - 54 DSOs with less than 1000 customers
1 main distribution company: ENEL Distribuzione is the first national DSO, covering the 86% of Italy’s electricity demand
ContactMarco Cotti
Enel Distribuzione SpA


Telegestore, Automated Meter Management Project

In 1999, Enel began developing the Telegestore® Project (Italian Automated Meter Management (AMM) System), a system for low-voltage (LV) concentrators and remote meter management. This was ahead of the mandatory installation programme of electronic meters set by the Italian Regulatory Body in 2006. The Project provided the installation of more than 32 million smart meters. These smart meters allow Enel to periodically collect data on voltage quality and interruptions, daily consumption, active and reactive energy measurements, and to remotely manage contractual activities. Meters are able to transmit data regarding consumption, receive updates of the contractual parameters and remotely manage the supply connectivity.

Today with over 99% of electronic meters already installed in Italy, Enel is well ahead of the timetable fixed by the European Commission, of at least 80% by 2020.

The Telegestore infrastructure is composed of the following main elements, shown graphically in Figure 4:

  • Smart meter units (with integrated metering, data transmission and management equipment)
  • Concentrators, transmitting data to and from the smart meters, installed in the MV/LV substations. The concentrator supports four main applications:
    • Aggregation of data from the meters and subsequent transfer to the AMM Control Centre at regular intervals or as required for specific AMM requests-
    • Performing remote operations on meters upon AMM request (e.g. Deactivation, Tariffs or contractual changes)
    • Alarm signal detection for communication problems, meter tampering, metering failure, and communication of these signals to the AMM Control Centre
    • Remote firmware download for electronic meter and LV-C software upgrade
  • The central system for remote management of meters, processing of billing information as well as quality of service monitoring
  • Telecommunication network (power line carrier (PLC) between the meter and the concentrator, mobile communication between the concentrator and the central systems.

Enel designed the overall system, setting out specifications for the meters and data concentrators and leaving the production of the equipments to contract manufacturers. With this equipment, the Telegestore project enabled the following smart grid functionalities:

  • Improved fault identification and optimal grid reconfiguration after faults
  • Enhanced monitoring and control of power flows and voltages
  • Identification of technical and non technical losses through power flow analysis
  • Additional information on supply quality and consumption to support network investment planning
  • Sufficient frequency of meter readings, measurement granularity for consumption / injection metering data (e.g. interval metering, active and reactive power, etc.)
  • Remote meter management

Figure 4 : The Telegestore Architecture

Objectives & Benefits

The Telegestore project was created with the objectives of enabling greater reliability and power quality for customers, creating more customer choice, offering competitive services and complying with regulation. Customers have benefitted in terms of:

  • Transparency as customers can read their energy consumption, rates, and contract on the meter display
  • Billing based on up-to-date meter readings
  • Flexible rate structures with the possibility of daily, weekly, monthly and seasonal modulation,together with the flexibility of billing periods, depending on the retailer’s offer
  • Remote and fast contract changes (connections, disconnections, rates, voltage, subscription transfers etc.), eliminating the customer inconvenience of on-site visits
  • Elimination of human error in meter readings, reducing complaints and disputes
  • Reduction of power disruption events and repair time


Customer Engagement

The full deployment of a smart metering solution represented a revolution, not only in the technology, but also in the business processes, starting from the relationship with customers. Enel built a communication plan to share with customers the details of the innovation project. The plan included: a brochure and documents sent to customer premises, congresses, promotional billboards, press releases in main national newspapers and dedicated trade papers. The aim was to inform customers about the replacement campaign, and to spread the awareness of the benefits Telegestore would bring, such as improving the quality of service. Moreover many dedicated meetings were organized with all the main Italian customer associations as influencing bodies to be properly informed. Following this plan was critical to completing the roll-out in the scheduled time-frame.


Current Status & Results

With a budget of 2.1 billion euro over a five year period, the project, being completed in 2006, has allowed approximately 500 million euro of yearly savings with reference to field operation, purchasing and logistics, revenue protection and customer service. 95% of this cost was associated with the production and installation of smart meters and LV concentrators. The remaining 5% corresponds to costs associated with IT system development, R&D costs and other expenses.

Figure 5: Cost per customer and quality of service improvements

In 2011 more than 400 million remote readings and more than 9 million remote operations had been performed.

The development of the AMM system within the Telegestore, as well as remote control and automation of more than 100,000 MV/LV substations, the Work Force Management system and the optimization of asset management led to a drastic cost per customer reduction and an improved quality of service.

The first phase of the deployment resulted in a remarkable amount of energy recovered. In 2006, the yearly energy recovered had been 1.5 TWh (around 0.75% of the overall energy distributed in Italy). This is the result of several factors:

  • Replacement of worn-out meters, which no longer worked correctly and measured a lower than actual consumption
  • Correction of database records (i.e. Current transformer rates incorrectly reported)
  • Detection of irregular and tampered installations from fraud and theft
  • Accessibility of meter data and the elimination of consumption estimation

The installation of smart meters in the MV/LV substations has allowed energy balance activities to value energy losses and fraud detection. With the energy balance data from the AMM system, the success rate of the meter verification activity has increased from 5% (before the AMM) to 60%.

Moreover, approximately 30,000 tons of CO2 emissions were estimated to be reduced from remote execution of customer management activities and meter readings in 2010.


Lessons Learned & Best Practices

Customer Service

With quality and reliability of customer service as main objectives for Telegestore, there were two key customer service initiatives that serve as best practices: the provision of a minimum social supply to bad payers and the development of the Enel smart info® device.

The remote curtailment functionality ensures in fact minimum social supply to all for a limited period of time, instead of outright cut-offs. Customers with bad payment history have their available power limited to 10% of their contract value. Remote power restoration is performed soon after payment.

Moreover, Enel Smart meters laid the ground for customers’ involvement in consumption management. Enel developed a device it calls smart info® that communicates with the electronic meter and enables customers to have easy local access to metering data, enabling also advanced customer services and active demand. A number of different devices such as personal computers, entertainment equipment, electrical appliances, mobile devices, and dedicated displays can show customers their energy data in easy to understand visual formats. The Enel smart info® uses a standard and open communication protocol to transmit the metering data to the other devices.


Project Details

  • Smart Meters and Advanced Meter Management System
    • 32 million smart meters deployed
    • System designed and meters specified by Enel
    • 358,000 data concentrators at MV/LV substations
    • Central AMM Control Center for remote management of meters
  • Tariffs
    • Time of Use is mandatory for about 24 million household customers and about 5 million non-residential under the universal supply regime
    • Time of Use or Flat rates are optional for the free market customers (about 8 million)
  • Funding: 100% by Enel (investment recognized within the Regulatory Asset Base since 2003)
  • Project Cost: 2.1 billion euro/ 5 years
  • Project Payback : 5 years, 500 million euro yearly
  • Benefits :30,000 tonnes of CO2 emissions reduced in 2010


System Design

Enel developed its charging infrastructure able to serve both electric vehicle owners, through innovative mobility services, and DSOs who must manage the distribution grid in real time. This result was achieved by exploiting Enel’s experiences in design, development, deployment and management of remote control and network automation and in the Telegestore project, over the last 10 years.

The broad deployment of smart meters opened also a new scenario for the development of a dedicated application to fully exploit the potential of smart meters data for network and business purposes. STAmi (Advanced Metering Interface Fully Integrated with remote control system) provides network operators with a dedicated web interface to collect, on demand and real-time, specific high quality and accurate data stored in smart meters without additional load for the AMM system.

Market Impact

The Enel Smart meter technology has become a de facto standard in Italy: 4 million of smart meters have been sold to other distribution system operators in Italy and additionally over 1 million smart meters to other European utilities. Moreover, thanks to the experience gained in the Telegestore, Enel has designed a new AMM generation system, based on the evolution of the Italian solution. Endesa, the Spanish utility within the Enel Group, is deploying the new field components and AMM system modules in Spain with the commitment to install more than 13 million meters. These projects will allow Enel technology to establish itself as the standard de facto for remote management with over 50 million electronic meters worldwide, the most extensive implementation in the world.

Enel Distribuzione and Endesa Distribucion Electrica created a non-profit association, Meters and More, to make the communication protocol used by their electronic meters open. The members of the association include major electricity distribution companies and other enterprises. The Open Meter project sponsored by the European Union deemed the Meters and More protocol a potential European standard for automated Metering infrastructure and nowadays it is one of the protocols under the standardization process by CENELEC.

The Enel Group’s smart meters have passed all the quality and safety tests provided for by current laws and comply with applicable EU directives. Enel’s smart meter complies with current European standards and is therefore certified MID (D.lgs.n.22 of February 2, 2007). At the international level it has been certified in the Netherlands by the Institute NMI (Nederlands Meetinstituut) in Dordrecht, by two Spanish centres, CEM (Centro Espanol de Metrologia) in Madrid and ITE (Instituto Tecnologico de Energia) in Valencia, and also in Germany, Poland, Sweden, Chile, China and Russia.

The Telegestore project has also developed the local economy. The transparent and indiscriminate provision of relevant data to all the electricity providers has enabled an easier growth of the free-market. In 2011 alone, more than 2.9 million switching operations had been remotely performed.

Cyber Security

Within the Telegestore system the data protection is performed not only by hardware mode inside meters and concentrators but also by means of a dedicated set of software features. To each meter installed at customer premises there is a dedicated security key. They are necessary to access customer data through all possible channels (PLC, optical port). The communication between the concentrator and the central system through the GSM/GPRS network is authenticated. The communication between the meter and the concentrator relies on authentication, with no encryption but as the data on the distribution line carrier cannot be directly related to the client (the association is possible only at the level of the central system) the Telegestore system ensures a fair level of data protection and privacy for each customer.

Next Steps

The design and development of a second generation of smart meters to replace the current smart meters at their end of life (expected lifetime 15 years) is underway. This includes a proposal to exploit potential synergies between electricity metering and other utilities metering systems, which could include gas and water. Drawing on the experience from the deployment carried out in Italy in the electricity sector and levering on the existing infrastructure, Enel is framing the basis for smart infrastructural integration between different energy services, representing also a crucial enabler for the massive deployment of gas smart meters set by the Italian Authority by 2018 . Alongside time and operational efficiency, the converging architecture proposed by Enel provides gas distribution system operators with a capillary infrastructure over the territory, guaranteeing a high level of communication and monitoring and assuring security and reliability of the service provision. Multi-utility pilot projects are going to be launched in Italy in late 2013 to validate the technical solutions and provide the Authority with insights and information about the governance models. The technical flexibility of the solution proposed by Enel allows it to fit all of the governance models currently under evaluation by the regulatory body.


Key Regulations, Legislation and Further Resources

Directive 2006/32/EC on energy end-use efficiency and energy services (translated in Italy into Legislative Decree 115/08)

Resolution ARG/elt 292/06 on smart meters roll out for LV customers

Directive 96/92/CE on common rules for the internal market in electricity (translated in Italy into Legislative Decree n. 79/99)

Resolution ARG/elt 22/10 on ToU tariff for residential customers under the universal supply regime


Italy’s Smart Grid Policy

The electricity context has been evolving in Italy driven by policy needs and objectives for increased quantity and quality of information about energy supply for service operation, enabled customers with more information and choice over their consumption, and compliance with the regulatory directive of the European Union. EU Directive 2006/32/EC on energy end-use efficiency and energy services, was translated in Italy into Legislative Decree 115/08, and addressed enabling consumers to make better informed decisions on individual energy consumption, while ensuring system efficiency and reliability. In 2006 the Regulatory Body (AEEG) set the mandatory installation of electronic meters in Italy, with minimum functional requirements for all the DSOs and LV customers starting from 2008 and reaching 95% of them in 2011. Nevertheless, the Enel’s Telegestore® project, launched in 1999, was a voluntary project, bringing forward the massive smart meters installation programme.

Market deregulation has also provided customers with the ability to choose their own energy provider. The increased competition among energy providers required improvements in the electricity distribution system performance levels for higher reliability and power quality to meet customer demand. This increased customer-centric commercial approach has required differentiated tariffs, value added services and reduced service provisioning time. In 2010 AEEG set the introduction of Time-of-Use tariffs for residential customers under the universal supply regime, which was possible because of the massive installation of electronic meters within the Telegestore® project.

※ Sections of this case were provided by Enel

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October 5, 2015


Smart Meter Pilot - Customer Behaviour Trial

By smartgrider In Advanced Metering Infrastructure, Case study Posted 2014-07-12


Market structureTransmission and 1 Distribution company-both regulated. All island single energy market, retail fully deregulated.
Number of retail customers2.24 million
Electricity consumed -201124,881 GWh
Peak Demand for Power-20114,644 MW
Net Revenue to Distribution-
Distribution Network 160,000 KM
ContactJoe Durkan
Sustainable Energy Authority of Ireland


Smart Meter Pilot – Customer Behaviour Trial

In 2009, over 6,000 smart meters were deployed in homes and businesses throughout Ireland as part of a national pilot to determine the most cost beneficial and effective way of achieving a full scale national smart metering rollout. This one year pilot led to the decision to proceed with a nation-wide roll-out of AMI from 2015-2019.

The primary focus of the pilot was on the response of consumers to smart meter specific energy efficiency measures with a view to measuring the impact on their energy consumption. The pilot was lead by the Commission for Energy Regulation (CER), the independent body responsible for overseeing the regulation of Ireland’s electricity and gas sectors in Ireland. The CER established a steering and a working group for the project comprising of representatives from the Department of Communications, Energy and Natural Resources (DCENR), Sustainable Energy Authority of Ireland (SEAI), the Northern Ireland Authority for Utility Regulation (NIAUR) and Irish Gas and Electricity Industry Participants.

For the customer behaviour trial, 5,375 residential electricity customers were recruited and smart meters were installed in their dwellings. A further 700 meters were installed in small businesses and commercial enterprises. The purpose of the trial was to measure the effect of smart meters, in conjunction with TOU tariffs and informational stimuli (detailed bills, in-home displays etc) on participant’s consumption behaviour.


Objectives & Benefits

Smart meters can facilitate energy efficiency by empowering consumers with more detailed, accurate and timely information regarding their energy consumption and costs, thus helping consumers reduce any unnecessary energy usage and shift any discretionary electricity usage away from peak consumption times. The goal of the customer behaviour trial was to ascertain the potential for smart meter enabled, energy efficiency initiatives to drive behavioural changes that would, in turn, reduce or shift peak electricity demand and reduce overall electricity consumption. Specifically, the aim of the behavioural trial was to determine:

  • if smart meters could achieve an overall reduction in electricity / energy consumption
  • if TOU tariffs could cause peak shifting (i.e. causing load to shift away from peak times), and if some of this load shift resulted in lower consumption, and,
  • the effect of various informational stimuli, in conjunction with TOU tariffs.


Use Case description

Profile of Participants

A key requirement of the trial was that the outcome would be statistically robust and representative of the national population. To achieve this, a phased recruitment process was implemented. Participant selection and recruitment followed a voluntary “opt-in” model using a tear off slip and achieved an average response rate of 30%. After each phase the respondents who opted in were profiled to confirm that they were representative of the national profile.

Customer research

During the trial, a number of focus groups were conducted to explore different aspects of the trial design with relevant consumer groups. The trial sought to incorporate consumer feedback for critical consumer impacting decisions during the project. The objective of enlisting consumer support at these stages was to ensure the efficient deployment of communications (letters of invitation, allocation etc), ToU tariffs and DSM stimuli that would be understood from a consumer perspective. Those selected for participation in the qualitative research were selected to mirror the usage and socio-economic attributes of the trial participants.

In order to explore how consumer behaviour changed as a result of the trial and to collect feedback on the participant’s experience and the impact of the trial on their engagement and interest in energy, it was necessary to collect and analyse experiential, behavioural and attitudinal data from the participants of the test and control groups. This data was collected in two surveys: one at the start of the pilot and one at the end of the pilot. Participants were required to take part in these surveys as part of their involvement in the trial and consequently the level of participation was high (79% of households which were part of the trial completed the pretrial survey; 80% of households which had completed the pre-trial survey also completed the post-trial survey).

Design and description of Stimuli

Four different sets of tariffs (each with day, night and peak rates) and 4 associated stimuli (monthly and bi-monthly detailed bills, in-home displays and an overall load reduction reward) were designed for use in the residential trial. The tariffs varied from modest to more onerous (e.g. from 20 cents to 38 cents for peak rate) with commensurate off-peak and night rates, but all were designed to be neutral in comparison with the standard tariff. This was to ensure that the “average” participant who did not alter their electricity consumption pattern was not penalised financially and to reflect the underlying cost of energy transmission, distribution, generation and supply as per standard tariffs.

Like the tariffs, the DSM stimuli in the Customer Behaviour Trial (the energy usage statement, the electricity monitor and the overall load reduction incentive) were designed specifically for the Trial using learnings from other international trials and extensive consumer feedback.

Figure 2: Customer fridge magnet explaining Time-of-Use time bands

During the Trial all participants in the stimulus test groups received a bill, combined with an energy usage statement. The first page presented the bill, was similar to the existing supplier’s bill, with additional lines for time of use (TOU) tariffs. The second page (the energy usage statement) provided additional detail on usage and supplied tips on energy reduction. The majority of participants received this energy statement on a twice monthly basis. One grouping however received the statement monthly to test for the effect of frequency.

The electricity monitor, or in-home display, was designed and developed specifically for the Customer Behaviour Trial. Its aim was to help consumers be more energy efficient by providing additional information on how much electricity they were using and how much it was costing them. The electricity monitor also included a budget setting mechanism, where consumers could decide the maximum they wanted to spend on electricity per day. A usage bar on the home screen showed consumers their usage against their daily budget. (Prior to deployment of the electricity monitor, the historical daily consumption of each participant was calculated and converted to a monetary value based on the new tariffs.)

Participants also received supporting information in the form of a fridge magnet and sticker. The fridge magnet outlined the different time bands and cost per band, customized for each tariff group.

Details of Trial

In July 2009 a 6 month baseline/ benchmark data collection period began. This was to give an indication of “normal” customer behaviour over a demi-seasonal cycle. All meters had been installed prior to the start of the benchmark period. Data was collected on a half-hourly basis from meters during this period in order to establish a benchmark level of use for participants.

Towards the end of the Benchmark period, participants were allocated to either a test or control group. There were 16 “test cells” (i.e. a tariff / stimuli combination). The allocation to a particular tariff and stimulus set was on the basis of profiling of participants across all available survey and usage data. The set of participants allocated to each cell was similar to the allocation in every other cell.

The behavioural stimulus trials commenced at the beginning of 2010 and ran for the full year. During the test period, participants were in either a test group or the control group. The control group were billed on their existing flat rate tariff and were provided with no DSM stimuli and their normal 1-page bill. Participants in the test groups received a bill, combined with an energy usage statement. Some of the groups also tested an electricity monitor or an overall load reduction incentive.


Current Status & Results

The customer behaviour trial found that smart meters in conjunction with TOU tariffs and informational aids (e.g. in home displays, detailed energy statements) deliver an overall reduction consumption of 2.5% and a reduction in consumption at peak times of 8.8%. These results are statistically significant at the 90% confidence level.

The study found that TOU tariffs are effective in both reducing and shifting consumption. The fact that there are different prices at different times, and not the actual price differentials themselves, was found to be the cause for the change in behaviour. Whereas all TOU tariffs tested delivered reductions, the trial found no statistical difference between a TOU tariff that had a peak time cost of €0.20 (42% higher than the day cost) versus one that had a peak time cost of €0.38 (300% higher than the day cost).

With regards to consumer information, the participants who had an In-home display were able to reduce their consumption by 3.2% overall and by 11.3% at peak times. Monthly detailed information statements also delivered significant reductions at 2.7% and 8.4% respectively.

The results of the trial fed into a cost benefit analysis carried out by the Economic and Social Research Institute (ESRI). The ESRI analysed 12 main national electricity smart metering rollout scenarios and found that the estimated total net present values (NPVs) were generally positive, and often substantially so. It was also found that were the results to be borne out in an actual deployment of smart metering, the project would bring about substantial net benefits for Ireland in comparison with the base case (counterfactual) scenario.

In July 2012, the CER published the decision that there will be a national smart meter rollout. Work is currently being carried out on the High Level Design phase. A partial rollout or test deployment of around 10,000 to 20,000 smart meters is scheduled to begin in Quarter 2, 2015. Pending the success of this, the full nationwide rollout is scheduled to begin in Quarter 1, 2016 with a completion date of Quarter 2, 2019.

Figure 3: Consumption Reduction by TOU over 24 hours


Lessons Learned & Best Practices

Customer Engagement Customer engagement at the design stages is vital for later acceptance. When communicating to the customer in the initial stages of a planning, it is important to highlight the role of the smart meter as an enabler of individual understanding and control and emphasising the opportunity for the consumers to reduce their bill.

Consumers tend to understand the basic concepts of a TOU tariff and the concept will be welcomed in general. This is because TOU tariffs are perceived as giving greater control to the consumer and it is expected that ‘electricity packages’ to suit their needs will be offered. However, consumers often do not have an awareness of how and when they actually consume their energy. For example they tend to overestimate the amount of energy they use at peak times and underestimate the amount they use in off peak and at night time in particular.

Communications dealing with TOU tariffs should illustrate how shifting non essential loads to off-peak times can provide an additional way to save money aside from reducing consumption. Explanations of the likely impact of current use patterns were effective, with messages such as “with your level of peak usage, your bill would increase by 10% if you did not reduce your usage during the two peak hours a day.”

Related to this, consumers may have difficulty in accurately estimating their actual cost reductions and tend to have exaggerated expectations of savings (and similarly exaggerated expectations of consequences). 40% of participants in the trial who believed that they had reduced their usage felt that reduction in the bill was not to the degree expected.

Simple information can also be effective. The fridge magnet and stickers supplied to all participants in the electricity Customer Behaviour Trial achieved 80% recall with 75% finding the magnet useful and 63% finding the sticker useful.


Project Details

  • Overall Reduction:   2.5% (3.2% with IHD)
  • Peak reduction:   8.8% (11.3% with IHD)
  • Net Present Value:  €174 million (if implemented)
  • CO2 Reduction:  150,000 Tons per year (if implemented)

Key Regulations, Legislation & Guidelines

The full details on Ireland’s Smart Meter trial and rollout can be found here on the CER website:

Smart Meters and Smart Grid play a key role in enabling Ireland’s commitment to a 20% energy savings target in 2020.

Ireland has published a Smart Grid Roadmap:


Ireland’s Smart Grid Policy

Smart Ireland recognises that for its economy to become carbon neutral by 2050 it must create an energy system built on wind and other renewables, using a smart grid and integrated into a clean EU energy system. Ireland has a small and relatively isolated grid that is already integrating high levels of non-synchronous generation (predominantly wind). This has spurred the deployment of aspects of the smart grid.

There is a supportive regulatory regime which is generally open to investment in smart grid deployment and appropriate R&D activities. Ireland has published a Smart Grid roadmap which identifies a number of measures required for the successful implementation of a Smart Grid. These include developing market structures and policies that encourage: increasing electrification of potentially flexible loads (residential and commercial space heating and cooling and water heating), demand side management, and deployment of technologies that provide greater system flexibility such as energy storage, distributed generation and load aggregators. This in turn will require equipment, control systems and communications networks to operate on harmonised protocols.

The national smart meter rollout, scheduled to be completed by early 2019, is a key requirement of the roadmap as this will enable real time monitoring of the system at the low voltage network level which will allow the participation in the market of distributed generation and virtual power plants. In addition, it will allow electricity suppliers to offer pricing packages that provide customers with options and incentives to manage their electricity usage and costs. This increased level of customer participation is essential as it is this which creates the opportunity to shift electricity consumption to periods where variable renewable energy is available.

※ Information in this case was provided by the Sustainable Energy Authority of Ireland.

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October 5, 2015


Linky project

By smartgrider In Advanced Metering Infrastructure, Case study Posted 2014-07-19


Linky project

Electricity French context

The electricity supply market is wholly open to competition since 2007. This allows companies and individuals a free choice of electricity supplier.

In France, the “Commission de Regulation de l’Energie” (CRE) is one of the official bodies that ensures adherence to market regulations.

ERDF’s missions are performed within the framework of a public-service contract and financed by “TURPE” (Tarif d’Utilisation des Reseaux Publics d’Electricite) or Network tariff charged to all users of the grid.

DSOs are responsible for metering activities.

ERDF manages the electricity distribution network across 95% of mainland France, guaranteeing quality and safety. Local distribution companies manage the remaining 5% in their exclusive service zones. The network belongs to local authorities, i.e., French municipalities or groups of municipalities.

Below you will find some key figures:

  • Electricity consumed (2013): 495 TWh.
  • Power Peak Demand (2013): 92,600 MW.
  • Current net result (2013): 810 MEUR ?697,200 km of LV lines (230 V/400 V).
  • 617,700 km of MV lines (20,000 V).

Contact: Hannah BESSER- ERDF, Linky Project

Email address: Hannah.besser@erdf.fr


Background and objectives

The smart meters project was designed as a step toward modernizing the electricity system with would yield the following benefits to the customer and the electricity system: ERDF’s Linky project is about the modernisation of 35 million electricity meters in France by installing smart meters.

This project, led in conjunction with the French Energy Regulation Commission (CRE), aims at answering the changing needs of various players on the electricity market:

  • to modernise metering infrastructures to face technological and societal evolutions (development of renewables and electrical vehicles, new uses of energy, etc.);
  • to improve the management of the Low Voltage network by collecting technical data on the system and on its availability;
  • to improve the functioning of the electricity market (diversification of tariff offers);
  • to help control energy demand and reduce CO2 Emissions.

Linky is based upon functionalities from the electronic meter, and equipped with 7 new major functions: a clock, a breaker, a software, a PLC modem, an encryption system, 8 managing contact-relays, and a slot for a radio module.

Based on the AMM technology, Linky is able to transmit consumption data, and remotely manage contractual activities (receive updates of the contractual parameters, remotely manage supply connectivity). It also allows ERDF to collect data on voltage quality and interruptions. Consumers will have access to their consumption data through a website.

Linky facilitates energy transition, enabling integration of Renewables on the grid, Electrical Vehicles (EV) and load management.

More than a meter, Linky is a system, a communicating platform which takes advantage of the low voltage network. This system includes five key elements:

  • The smart meter: it’s a “slave” system, receiving and executing orders and in return transmitting reports and validating readings;
  • Linky then communicates them to a concentrator (a data aggregator located in ERDF’s secondary substations). The concentrator polls the meters, processes and stores the received data and transmits it to the central Information System.
  • Linky communicates with the concentrator via the local communication network. It exploits the Power Line Carrier technology (PLC), using the low-voltage electric network to exchange data and orders between meters and concentrators.
  • The concentrator in turn communicates with ERDF’s central Information System, which receives requests from ERDF’s internal Information Systems and processes them automatically.
  • The extended communication network allows concentrators to communicate with the central Information System. This network uses telecommunication network (e.g.: GPRS).

The three main characteristics of Linky system are:

  • Bi-directional communication (to and from the meter);
  • Scalability: each component can be separately upgraded;
  • Interoperable and exchangeable equipments, and standardized protocols of communication

Figure 4. Linky System architecture


ERDF designed the overall system, setting out specifications for the meters and data concentrators and leaving the manufacturing of the equipments to subcontractors, selected by European calls for tender.

Linky’s unique design is the result of the joint work of agency BETC Design, project staff and the manufacturers. The ergonomics of the next generation meter is more intuitive with only 2 buttons visible and more technical controls sealed under the covering box.

In 2009, Linky won an “Observeur du Design” award[1] (created in 1999 by the Agency for the promotion of industrial action) on the topic “the beautiful, the useful and design” for its capacity to be forward-looking by proposing an aesthetic concept tailored to uses and lifestyles.


The modernisation of electricity meters is a legal obligation imposed by the European Commission. In a directive of 2006, Brussels required 80% of meters to be “smart” by 2020, in other words tey must allow users to control their consumption. Linky Project aims at complying with this requirement.

Linky is the first step towards smart grids and will help to optimise the network management:

  • Better fault identification and localisation on low and medium voltage networks ensuring faster interventions;
  • Detailed monitoring of the power quality to better manage customer complaints and to provide a faster answer;
  • Increased capacity to remotely act on the networks, in particular to manage peak shaving programs;
  • New tools to forecast constraints on the network (balance between production and consumption) on local areas and diverse time scales (short term, long term simulation, …);
  • Reinforced observation and control capabilities to maintain the proper voltage level and to optimise the location of Renewables production sites / EV charging stations.

Linky also offers numerous benefits for the consumers:

  • With Linky, billing (under supplier’s responsibility) can be based on actual consumption and no longer on estimated consumption: users’ bills reflect what consumers actually consume.
  • Most operations can be remotely done, in less than 24 hours (the contractual period is 5 days today).
  • Outages can be localised faster, enabling faster interventions of field teams.
  • Linky offers consumers a secured access to consumption data, including a history and analysis of power usage, accessible on the Internet or mobile phones. These data will help the consumers to better understand their energy consumption and to engage in more responsible consumption by adjusting the consumption to the real needs.
  • With its 8 managing contact relays, Linky enables the management of household appliances (hot water tank, electric heating, etc.).
  • At last, it offers a simple and unique device to facilitate demand response: by sending a signal, to make consumer reduce or suppress energy consumption during peak periods.


Current status and results

From March 2009 to March 2011, ERDF launched a pilot to experiment the Linky system in two areas, in the city of Lyon (1750 inhabitants/km²) and in the rural districts around Tours in the Loire Valley (33 inhabitant/ km²). This experiment lasted 24 months.

The objectives of this pilot were to test Linky Information System and the roll out process, and to confirm financial hypotheses (mainly to measure the duration of the installation of meters).

Figure 5: Linky Pilot planning


Installation of concentrators was realised by ERDF teams, and the installation of the meters was realised by service providers.

The financial hypotheses were validated: an average time slot of 30 minutes to replace a meter, 8 per day per electrical fitter. An average of 1500 meters was changed per day.

The system reached the expected performance objectives: 98% of remote operations are achieved in less than 24 hours.

The Linky experiment gave good results and was considered as a success by the French Regulator “CRE”, in its experiment’s report published in 2011. Today, 300 000 Linky smart meters are operational in France.

Lessons learned and best practices

Customer engagement during the roll out

The relationship with consumers was a major stake of the Linky experimentation.

A campaign of communication was launched to inform clients and local authorities in the roll out areas.

Public meetings were organised. Information letters were sent to the clients before the technical interventions.

A dedicated hot line could be used if clients had some questions before or after the installation of the smart meters.

An instruction manual of the meter was given after installation, also accessible on ERDF’s website.

These actions secured the relationship with consumers during the roll out: at last, ERDF received less than 1% of claims related to Linky experiment.


Access to data for final consumers

ERDF launched in 2012 an experiment in Lyon to study the interest of consumers for web energy information and to evaluate the impact of an access to energy consumption.“Watt & Moi” is a Web Site for customer information, experimented with “Grand Lyon Habitat”, a social landlord. 1000 clients equipped with a Linky meter have been given an access to the Web Site.

It enables a secure and educational access to individual consumption information (by season, month, days, hours, etc.), comparison with similar households, basic advices in energy savings and SMS alerts in case of overconsumption.

Note: the data on the individual consumptions are given in kWh and not in Euros, because of the separation between suppliers and DSOs in France.


System design

The Power Line Communication (PLC) carries data on a conductor that is also used simultaneously for electric power transmission or distribution.

During the pilot, the PLC communication protocol of the Linky system was the G1 PLC.

ERDF now plans to deploy a new generation of meters and concentrators using a new protocol, the G3 PLC.

The G3 PLC is a high-speed, highly-reliable, long-range communication protocol. It can function in harsh, noisy environment.

G3-PLC Alliance, sponsored by ERDF, is promoting G3-PLC technology in smart grid applications. The main objectives of the Alliance are:

  • to support G3-PLC in internationally recognised standards bodies to achieve the rapid adoption of G3-PLC specification worldwide;
  • to develop a framework for equipment testing to facilitate interoperability among G3-PLC adopters ;
  • to educate the market and promote the value, benefits and applications of G3-PLC.


Market impact

Some Electricity suppliers are developing new offers or devices using smart meters functionalities. These offers propose new tariff offers, data access and the management of household electrical appliances.

Some industrials (e.g. Schneider Electric, Delta Dore, etc.) develop Smart home management systems that could use the smart meter’s functionalities (diversification of tariff profiles, the 8 virtual contact relays).

Linky is a major project for the French industry: 10,000 job opportunities will be offered for the manufacturing and the installation of the smart meters. 5,000 of these jobs will be devoted to the installation of meters in the French territory.


Cyber security

The Linky Project follows the recommendations of CNIL (the French National Commission for Information Systems and Freedom) and ANSSI (National Agency for Information Systems Security)

ERDF is submitted to a legal obligation to protect commercial data and consumer’s personal data. These data are the consumer’s property and can’t be communicated to a third party.

A decree of January 2012 in France indicates that advanced metering systems must be in conformity with a frame of reference about security, certified by the ANSSI.

The data transmitted to Linky’s information system are encrypted.


Next Steps

On July 9th, 2013, the French Prime Minister announced the decision to roll out 3 million Linky smart meters in France by end 2016 and confirmed the target to replace all the present meters, 35 million units, by the year 2021.

On 2013, July 30th, a notice for participation was released in the Official Journal of the European Union. It was followed on 2013, October 11th by a call for tender to supply the equipment (for the first step of 3 million meters).

The Linky Project represents a 5 billion € investment: the investment is based on a 20 years duration and will be compensated by savings made on field interventions and on non- invoiced consumptions (frauds…).

ERDF is now planning a mass roll out. During the first semester of 2014, the mass roll out plans will be shared with French national and local authorities.

In the middle of the year 2014, a call for tender will be released in the Official Journal of the European Union for the service providing for the installation of the meters.



Key Regulations, Legislation & Guidelines

Law n° 2005-781-2005 July 13th- Program on energy policy orientation (POPE)

Directive 2006/32/EC on energy end use efficiency and energy services

Law n° 2009-967-Aug 3th- Grenelle de l’Environnement (energy efficiency and conservation)http://www.legifrance.gouv.fr/affichTexte.docidTexte=JORFTEXT000020949548

French smart metering decree n° 2010-1022- Aug 31th

Pilot project assessment by the French regulator in 2011 (CRE)

First announcement of Linky roll-out by ≪ Comite Besson ≫, Minister of Energy in 2011 Following the decree, smart meter order ? 2012 Jan 4th http://www.legifrance.gouv.fr/affichTexte.do?dateTexte=&categorieLien=id&cidTexte=JORFTEXT000025126353&fastPos=1&fastReqId=1046397764&oldAction=rechExpTexteJorf

European directive on energy efficiency ? November 14th 2012

9th July : decision announced by Prime Minister for the roll out of smart meters


Linky on the ERDF’s website http://www.erdf.fr/Linky/

G3-PLC Alliance website http://www.g3-plc.com/



French Smart Grid Policy

To face increasing environmental concerns, the European Union adopted ambitious objectives. In conjunction with European policy, France adopted measures, by laws issued from the “Grenelle de l’environnement”, to efficiently handle energy demand. France also took the engagement to divide by 4 its greenhouse gas emission.

The energy transition (development of Renewables and Electrical Vehicles, increasing concerns about energy efficiency) has a strong impact on energy uses and the management of the electrical system. The modernisation of the electrical system and the development of smart grids in France are thus required.

ERDF, the historical DSO, is a reference in the field of smart grid technologies. MV Grid is already ≪ smart ≫ in France (with Regional Control Centers, remote-control appliances). The stake is to develop smart grid technologies on LV Grid.

The DSOs, and particularly ERDF, have already included in their investment programs the implementation of smart grids technologies. ERDF implements numerous smart grid projects and pilots until 2016, and study possible industrialisation plans and roll out process from 2018.

UFE (Union Francaise de l’energie) estimates to 110 billion Euros the necessary investments on the distribution networks to face the impact of energy transition until 2030.

The development of smart grids on LV networks will help to avoid a part of these investments by contributing to a better localisation, and by increasing the capacity to dynamically manage uses and Renewables.

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October 5, 2015

AMI CASE Case02 / Canada

Ontario Smart Meter Deployment Project

By smartgrider In Advanced Metering Infrastructure, Case study Posted 2014-07-13


Market structureA hybrid wholesale electricity market with significant amounts of centrally procured or regulated supply. Retail market created with no active participants. Smart meters are owned, installed and maintained by the Local Distribution Companies - LDCs
Number of retail customers4.8 million
Electricity consumed - 2011141.5 TWh
Peak Demand for Power -201124, 707 MW
Net Revenue to Distribution -2011$3.2 billion CDN
Distribution Network158,951 km of overhead lines
38,637 km of underground lines
674,966 km2 of rural area
6,714 km2 of urban area
80 LDCs - most are small municipally owned utilities, 72% of the province is served by 10 utilities, 25% is served by Hydro One
ContactUsman Syed / Ontario Ministry of Energy

CANADA Ontario

Ontario Smart Meter Deployment Project

In April 2004 Ontario announced the deployment of smart meters in all homes and small business by the end of 2010. In 2010, the energy regulator, Ontario Energy Board, set mandatory dates for the adoption of time of use prices for smart metered customers. As of December 2012, smart meter installation is complete with 4.8 million smart meters installed in the province and 4.5 million customers on time of use (TOU) rates. The TOU rates have 3 bands:

Prices are regulated by the Ontario Energy Board and set twice a year for the summer and winter periods. Each local distribution company in Ontario has deployed its own smart metering infrastructure and each is integrated with a central meter data management repository (MDM/R). The MDM/R is currently operated by the Independent Electricity System Operator (IESO) in its capacity as the “Smart Metering Entity”. The IESO developed the specifications and through a competitive bidding process awarded a contract to IBM Canada to build and operate the system. As a centralized system, the MDM/R serves to provide hourly billing quantity data for the distribution companies so they may use the data to bill their customers on TOU rates. The data that the MDM/R receives is completely anonymized, with only time-stamped consumption data.As a central database which stores valuable data from across the province, the MDM/R is strategically positioned to leverage the data for analysis at an aggregate level and to provide important evidence from which to base conservation and demand management programs off of, and to use in evaluation of those programs. In the future, this data may also be made accessible to companies who want to develop innovative smart grid technologies based off of real consumption data.

Objectives & Benefits

The smart meters project was designed as a step toward modernizing the electricity system with would yield the following benefits to the customer and the electricity system:

Smart meter benefits to the Electricity System

  • Facilitates conservation and demand management programs
  • Accurate meter reads (no more estimates)
  • Timely information to help manage consumption
  • Proactive customer service (e.g. immediate outage notification)

Smart meter benefits to the Electricity

  • Reduces the number of crew visits to read and service meters
  • Reduces tampering and theft of electricity
  • Provides significant operational benefits (better outage management and system control)

The smart metering infrastructure on its own provides significant near-term value to the utilities with the additional information it provides that helps drive operational efficiencies. However, it also provides a strong foundation for building additional value-add products and services on top of it such as home energy management systems and electric vehicle charging, and other technologies that would be components of smart homes.

Following the smart meter deployment, the TOU pricing was intended to leverage smart meter capabilities to enable peak-shifting and build customer understanding of how to control their consumption and how their consumption decisions affect the long-term cost of electricity supply. The intended benefits were:

TOU benefits to the Customer

  • Gives customers ability to move discretionary load to cheaper hours
  • Reduces long-term cost of electricity supply
  • Increases awareness of consumption

TOU benefits to the Electricity System

  • Environmental benefits as a result of load shifting
  • Savings in avoided/deferred capacity investments in new generation and transmission


Figure 1: Areas of responsibility for AMI communications and data processing

Planning for Success & Making the Business Case

Ontario’s smart meter implementation was the product of a coordinated approach between legislation, regulation and the development of guidelines and best practices. The Ontario Energy Board (OEB) as the distribution regulator provided the Energy Minister with a Smart Meter Implementation Plan in 2005, which was a product of working groups that included distribution regulator provided the Energy Minister with a Smart Meter Implementation Plan in 2005, which was a product of working groups that included distribution companies, consumer agencies, vendors, federal standards agencies and unions. The plan provided the estimated costs, key features of the technology and program, and the implementation timeline. Subsequently a benefit/cost review was conducted of the proposed program which calculated that the $1 billion CDN project would be worth $1.6 billion CDN once fully implemented.

With 80 LDCs in Ontario, that could have meant building and maintaining 80 data management systems for meter data. A series of Ministry-led consultations on managing the meter data led to the decision to build a single centralized MDM/R in order to reduce the cost to customers, and to provide access to aggregated consumption data across the provinces for future program planning and policy purposes. The MDM/R receives information from 5 different types of AMI systems operated by the distribution companies across the province, as such the MDM/R had to be built to be interoperable with the communications protocols of each of those systems. It also repackages that information into a common format with facilitates simpler analysis and downstream infrastructure related to billing and other enterprise systems. The MDM/R is now processing over 90 million reads per day, and is designed to process over 120 million meter reads per day ? which, on an annual basis, exceeds the number of debit card transactions processed in Canada and rivals the average payment transactions processed world-wide by VisaNet.

Ontario’s Privacy Commissioner worked with the Ministry and stakeholders to ensure that all smart grid initiatives would be designed to uphold the highest standards in data privacy and security. Working with distribution companies, the Privacy by Design principles were developed and incorporated into a guideline of best practices for smart grid companies to follow when designing their systems. The Privacy Commissioner’s office also helped to produce material that would explain to the public the measures taken to ensure the safety and security of smart grid.

The Energy Conservation Leadership Act (2006) and later the Green Energy and Green Economy Act (2009) housed the smart meter initiative within broader plans to build an economy around clean energy and promote conservation. Home energy management systems have been piloted in several distribution territories to develop technologies and programs that encourage customer empowerment and result in load shifting. The impact and of these programs and technologies have will be attributed in part to the smart meter initiative.

Current Status & Results

As of December 2012, smart meters and AMI have been deployed for all residential and commercial customers in Ontario, with TOU adopted by 94% of customers across the province. The project’s total cost for installation came in at the estimated $1 billion CDN. At this stage it is too early to measure the overall progress on some of the project objectives, with many customers having been included in TOU for less than 1 year. Consumption data is being collected by the OEB for the whole province in order to evaluate the impact of this project once a significant period of time has passed.

In the absence of an aggregate study, some progress has been evaluated in territories that have implemented TOU over a longer period. For example the Newmarket distribution company commissioned a study by Navigant Consulting, published in 2010, to determine if load shifting behaviours could be observed from their customers as a result of TOU pricing. Importantly, they found that during an analysis period of over 800 days that spanned before TOU and after TOU customers shifted approximately 3% of their consumption from peak to off-peak periods.

Project Details

  • Smart Meters and Advanced Meter Infrastructure
    ○ 4.8 million smart meters deployed
    ○ 5 different meters installed across the province
    ○ All communications infrastructure in place
  • Time of Use Pricing:  4.5 million customers, fully implemented by 2012
  • Meter Data Management Repository: 4.5 million meters enrolled (Dec 2012)
  • Project Cost: $1 billion CDN for AMI installation
  • Project Cost Recovery: ~$3-4 CDN /customer/ month through customer rates(declining over time as principle is paid down)
  • Project Benefit : $1.6 billion CDN

Lessons Learned & Best Practices

Project management

As part of maintaining a momentum and making the project implementation transparent and accountable, the OEB required the distribution companies to report every month on their progress of smart meter installation and TOU implementation. The OEB also required the smart metering entity to report on their enrolment of LDC AMI systems into the MDM/R. These reports were used to track the overall progress and were posted online.

Customer Engagement

The government wanted to centralize the communication as much as possible to make it easier for distribution companies to communicate the changes to customers and to help set their expectations for future smart grid initiatives. It created a TOU Rollout working group which developed various customer engagement materials including brochures, bus ads, posters, bill boards etc. All distribution companies were offered these templates for materials which they could brand, and print themselves. The smaller distribution companies, with smaller public engagement budgets, made the most use of these materials. Others commissioned their own materials, and used other methods including hosting town halls, writing articles about it in local newspapers, and engaging customers at community events. Ontario was one of the earliest jurisdictions to deploy smart meters and in comparison to others in North America it has experienced relatively little opposition.

Despite this early success, there is still a fair amount of engagement required help customers fully appreciate how they can leverage their smart meter’s capabilities. As smart meters were deployed along with the implementation of TOU pricing, many customers saw smart meters as tied to TOU and not part of a greater smart grid value proposition. In order to communicate the greater vision for smart grid in Ontario, programs for developing home energy management systems and demand management programs relate back to the smart metering infrastructure that they are building off of. At a policy level, the government has identified “increased customer control of their own energy use” as one of the 3 smart grid objectives. These 3 objectives have helped government, politicians and distribution companies communicate to customers the benefit of smart grid.

Building Smart Grid Policy

Much of the ongoing thinking for smart grid initiatives in the province is captured in the annual reports of Ontario’s Smart Grid Forum. This forum is an independent body, administered by the IESO, which draws together stakeholders from the government, regulator, distribution companies and corporate partners looking to develop new technologies and services for smart grid. In addition to the formal consultative processes, the regular meetings of the Smart Grid Forum have served as a valuable sounding board for government smart grid policy ideas.

Privacy by Design

Ontario’s Privacy Commissioner not only helped to create a robust set of guidelines for managing smart data, once she was satisfied that the program was meeting all of the necessary standards, she became a champion for Privacy by Design (PbD) in smart grid. Working with smart grid stakeholders around the world, she helps industries to incorporate the PbD principles into smart grid planning, and to communicate the integrity of smart grid to customers. Unanimously passed and adopted as an International Framework for protecting privacy at the International Conference of Privacy Commissioners in 2010, PbD has become a best practice around the world.PbD continues to publish on emerging issues for smart grid and “big data.”

Time of Use Pricing

When customers were fist exposed to TOU pricing, the OEB originally set the TOU schedule so that the off-peak period began at 10pm based, on when the demand profile for electricity drops off significantly across the province. The public reaction to this was negative, with many complaints of the impracticality of waiting to run laundry machines (for example) after 10pm. The government and the OEB responded by adjusting the schedule so that off-peak prices applied at 9pm, and then in light of an on-going recession they were adjusted to 7pm ~ 7am. Mid-peak prices were adjusted to be from 7am ~ 11am and 5pm-7pm, on-peak prices run from 11am ~ 5pm.

Procurement Lessons

The OEB, representing the interests of rate payers, implemented the government’s Smart Meters: Discretionary Metering Activity and Procurement Principles regulation in 2008. This regulation stipulated a minimum functionality for meters, including their ability to charge TOU rates. To ensure that all investments in smart meters were prudent, the OEB ruled that if distribution companies wanted to invest above and beyond the minimum requirement, those additional functions would have to be defended with a business case that would demonstrate the added value for the customer. While this has proven a cost effective measure for customers, few distribution companies have chosen to invest in meters with additional technology capabilities that have emerged to serve future smart grid technologies such as home area networks. This decision will continue to be evaluated into the future as more technologies and systems interact with the meters. However, each meter can be upgraded or outfitted with additional technologies so the question of future adaptability is not a technical concern.

Distribution companies also had to be authorized by law before they could procure. This encouraged buying-groups to form that could take advantage of economies of scale. Despite that, the service territories of the various distribution companies across the province ranged from dense urban centres to rural and remote communities. This dictated a variety of technical capabilities, where some distributors procured meters to operate on a mesh-network for urban areas, while others procured meters to operate on tower-based communication system. The result is 5 different AMI systems (Trilliant, Elster, Sensus, Silver Springs, Tantalus). This proved an effective price measure as the average installed price for the AMI averaged around $250 per customer. Technically it required additional programming to repackage the data into the same format for the MDM/R to process and store.

Next Steps

Ontario’s decision to create a central MDM/R for all smart meter data across the province offers a wealth of opportunity for data analysis linking a rich data set of energy demand profiles with other public data sets. The analysis can lead to important insight with which to inform policy and provide feedback on the effects of current programs and regulation. The data also provides a valuable resource for entrepreneurs to create innovative projects and services for customers. To enable this innovation, Ontario is conducting a Green Button pilot to determine best practices for granting customers and third parties safe access to customer data.

Key Regulations, Legislation & Guidelines

Smart Meter Implementation Plan (2005)


Functional Specification for Advanced Metering Infrastructure (2007)


Ontario Green Energy and Green Economy Act (2009)


Smart Privacy for the Smart Grid: Embedding Privacy into the Design of Electricity Conservation (2009)


Ontario Green Button pilot


Ontario’s Smart Grid Policy

Smart grid policy is set provincially in Canada. Ontario’s policy environment for smart grid is the most defined in Canada. Ontario’s large power consumers are connected with interval meters and billed according to the Hourly Ontario Energy Price which tracks market prices. With the deployment of smart meters and time-of-use pricing for residential and commercial customers virtually all of Ontario’s electricity customers are now paying prices that reflect market demand. This has unlocked potentials for new business models and system innovations in the province. Under the Green Energy and Green Economy Act of 2009, Ontario’s Minister of Energy directed the Ontario Energy Board to promote the implementation of smart grid capabilities. The directive also required that the regulator guide the development of mandatory Smart Grid Plans for distribution utilities, and that those plans be regionally coordinated. Ontario smart grid policy objectives are captured under the 3 focus areas: customer control, power system flexibility, and adaptive infrastructure. These policies coupled with feed-in tariffs for renewable energy, aggressive conservation targets, as well as the Smart Grid Fund, have attracted entrepreneurs, businesses, utilities and venture capitalists to invest in Ontario.

※ This case was written with contributions from the Ontario Ministry of Energy, images were taken from the Ontario Energy Board and Independent Electricity System Operator.

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October 5, 2015


Smart Metering Case in Austria

By smartgrider In Advanced Metering Infrastructure, Case study Posted 2014-07-19


Market structureFully liberalized in 2001
TSO: Ownership nbundling/ISO
DSO: legal unbundling
Metering is in responsibility of DSO
Number of retail customers -20110,466 million EnergieAG 5.8 Mio AUT
Electricity consumed - 2011 7,3 TWh EnergieAG
68,8 TWh AUT
Peak Demand for Power -201110.900 MW
Net Revenue to Distribution Companies -2010
Distribution Network LV lines < 1 kV
21.934 km EnergieAG
166.023 km AUT
MV lines > 1 kV, < 110 kV
9.039 km EnergieAG
67.688 km AUT
total area
EnergieAG: 10.150
AUT: 83.850 km2 ~ 130 Distribution System Operators - various size and ownership structure
If your case is going to focus on 1 DSO’s experience tell us about that DSO size, ownership.
ContactAndreas Abart
Dipl.- Ing. Dr.


The Energie AG smart metering project AMIS was started as the first broad test case in the region “Upper Austria” in 2005 and led by the regional DSO. After 8 years the system has reached a mature state with approximately 100.000 smart meters and 25.000 load switching devices, which replaced the common ripple control receivers.

Objectives & Benefits

Smart meter benefits to the Customer

  • Detailed information on energy consumption in near real-time
  • Improvement of customer processes, e.g. change of residence
  • New flexible tariffs
  • Support of decentralized feeding-in

Smart meter benefits to the Electricity System and Market

  • Process enhancement by automation of metering processes
  • Automation of the distribution grid
  • Basic technology for smart grids
  • Enabling new business models e.g. Energy management, Demand side management, Home automation

AMI System Architecture


Current Status & Results

Up to now roughly 100.000 meters were deployed in the area of Upper Austria. The complete roll-out of approximately 600.000 meters will be carried out according to the Austrian legal requirements.

It is obvious that first savings could be obtained by the efficient process automation, but a precise estimate for this achievement will not be available until operation of the complete system over a reasonable period of time.

Customers who do not have an AMIS-meter still are required to read the meter for themselves once a year and provide the result via postcard or web portal.

Currently customers benefit from the online portal which provides their daily consumption and recently load profiles as well. Moreover requests arose to provide additional real-time data of energy consumption.

Project Details

  • Smart Meters and Advanced Meter Infrastructure: 0,1 million smart meters deployed Meters to DCs via PLC; DCs to HES via 66% Radio, 30% fiber optics, 4% GPRS, No MDM
  • Tariffs: Something about the pricing structure for electricity
  • Funding: : 100% rate recovered by DSOs
  • Project Cost: Approx 250 € per metering point
  • Project ROI:  –
  • Project Benefit: • $1.6 billion CDN

Lessons Learned & Best Practices

Lesson 1
The introduction of smart metering resembles more a revolution than an evolution. This stems mostly from the fact that simple autarkic meters are replaced by a very complex complete system.

Lesson 2
The processes for the grid system as well as processes for the customers had to be altered significantly which requires a strong commitment throughout the whole company.

Lesson 3
It is necessary to inform and involve customers about the new technology and its possibilities.

Lesson 4
Privacy and IT security have to be considered from the very beginning and the resulting effort and expenses should not be underestimated.

Lesson 5
Smart metering provides a basic tool to achieve energy saving, however the realization is within the responsibility of the customers.

Lesson 6
Due to the lack of established standards, smart metering contains a high risk for the security of the investments. This includes standards for e.g. the communication technology (Power line), the interfaces for customers and multi utility meters and the necessary IT-security.

Lesson 7
New technologies e.g. DLC (Distribution line communication 30-95 kHz) can cause some EMI-Cases which are not covered by any existing standard yet. (See CLC SC205 A Study Report I + II)


Next Steps

In the future further developments will be carried out to fulfill the Austrian legal requirements (IMA-VO). Moreover international trends, developments and standardizations will be observed to be capable to provide the best decisions for the further required developments. The goal is to finish the complete roll-out until 2019 as required by the Austrian law.

Actually some R&D projects in the field of smart grid focusing on an efficient way to integrate DG from renewable power resources especially rooftop PV-systems are based on the use of smart meters. Smart meters are powerful three phase power analyzers at each costumer site and are used for investigating LV-grids and load characteristics as well as voltage measurement site in voltage control systems compensating the voltage rise caused by decentralized generation. Depending on results new technology will be derived from these demo projects and implemented to further LV-grids.


Key Regulations, Legislation & Guidelines

Directive 2006/32/EC on energy end-use efficiency and energy services


Directive 96/92/EC on common rules for the internal market in electricity


Federal Act Providing New Rules for the Organisation of the Electricity Sector – Electricity Act 2010 (Elektrizitätswirtschafts- und –organisationsgesetz 2010 – ElWOG 2010)


Smart Meter Act (Intelligente Messgeräte-Einführungsverordnung):


Roadmap Smart Grids Austria:


Austrian Energy Strategy (Energieforschungsstrategie für Österreich):


Austria’s Smart Grid Policy

The main drivers for utilities in Austria to implement Smart Grids is the European directive for the full rollout of smart metering until 2020 and the imminent requirement to integrate distributed power generation units into the existing infrastructure.

The Austrian Smart Meter Act envisages simple smart meters which record electricity consumption mainly for billing purposes. By the end of 2017, 70% of all Austrian households are expected to be equipped with smart meters and, if technically possible, 95% of households by the end of 2019. In a future perspective Smart Meter data might also be used for a variety of energy services and might also contribute to model low voltage networks more precisely and thus improve network planning and operation in distribution networks. This has already been demonstrated in some field tests.

The European 20-20-20 targets have led to a surge of renewable energy and the future network must be able to manage its fluctuating generation behaviour and also to integrate infrastructure for electric vehicles and storage technologies. These are important drivers for the further developments.

The Austrian Technology and Innovation Policy is heading to investigate the future role for smart grids by developing and testing smart grids technologies and concepts, as they are seen as a key enabling infrastructure to achieve political goals in the direction of sustainability. In particular smart grids are expected to contribute to

  • the optimal integration of renewable energy sources and of decentralized generation
  • increase the efficiency within the energy systems as well as optimize infrastructure investments
  • adding flexibility to the grids
  • enable and integrate smart services and electro-mobility
  • support the development of “energy regions of tomorrow” which aim at a high degree of self-sufficiency
  • keeping high standards of supply security and power quality while increasing the resilience of energy systems and actively considering security and privacy aspects by design

In 2010, the Austrian Technology Platform Smart Grids published the roadmap “The path to the future of electric power systems”.
It suggests a coordinated and structured way to smart grids – from the description of the context and the necessary technological innovations to achieve a secure and sustainable electricity supply in Austria.

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September 22, 2014

Spotlight on Advanced Metering Infrastructure

The AMI case book includes six case studies providing qualitative insights into the potential costs and benefits of advanced metering infrastructure (AMI), and the associated business cases for investment.

Each case presented has its own unique set of characteristics and drivers, which is indicative of the diverse range of motivating drivers for smart grid and AMI globally.

The lessons learned and best practices presented in the six case studies included in this case book provide qualitative insights into the potential costs and benefits of advanced metering infrastructure (AMI), and the associated business cases for investment. Each case presented has its own unique set of characteristics and drivers, which is indicative of the diverse range of motivating drivers for smart grid and AMI globally. It follows then that the specific costs, benefits and business cases vary from case to case. Still. there are a number of best practices and common themes emerging from these cases that are likely to be useful for any jurisdiction investigating or deploying AMI.Those common best practices and insights are presented here.

It should be noted that these six cases represent only a portion of global experience in considering and deploying AMI. In addition, AMI is only one system of technologies among a broad menu of options that can constitute a “smart grid.” Some countries consider an AMI a prerequisite for their smart grid, while others have dismissed the importance of AMI to grid modernization. Additional cases have been solicited or are under development that will enlarge global understanding of the role AMI can play as one possible component of smarter electricity networks worldwide.

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