DEVELOPMENT AND IMPLEMENTATION OF SMART
GRID PROGRAM IN VIETNAM
REPORT ON RECOMMENDATION OF SMART GRID
PROGRAM FOR VIETNAM
Prepared for:
ELECTRICITY REGULATORY AUTHORITY OF VIETNAM
(ERAV)
Prepared by:
AF-MERCADOS EMI
October 2012
No. 1356
AF-MERCADOS EMI
REPORT ON RECOMMENDATION OF SMART GRID
PROGRAM FOR VIETNAM
TABLE OF CONTENTS
1.
INTRODUCTION ......................................................................................................................... 3
1.1.
1.2.
1.3.
2.
BACKGROUND............................................................................................................................ 3
CONCLUSIONS OF PREVIOUS REPORTS .............................................................................................. 4
OBJECTIVES OF THIS DOCUMENT ..................................................................................................... 5
SMART GRIDS: VISION AND OPPORTUNITIES FOR VIETNAM ....................................................... 6
2.1.
2.2.
2.3.
3.
DEFINITION ............................................................................................................................... 6
VISION ..................................................................................................................................... 6
OPPORTUNITIES ......................................................................................................................... 6
STRATEGIC APPROACH .............................................................................................................. 8
3.1. PHILOSOPHICAL AND OPERATIONAL APPROACH ................................................................................. 8
3.1.1. PHILOSOPHICAL APPROACH ...................................................................................................................8
3.1.1. OPERATIONAL APPROACH .....................................................................................................................9
3.2. PHASING OF THE PROGRAM ........................................................................................................ 10
4.
TECHNOLOGICAL DEVELOPMENT ............................................................................................. 12
4.1.
4.1.1.
4.1.2.
4.1.3.
4.1.4.
4.1.5.
4.1.6.
4.2.
4.2.1.
4.2.2.
4.2.3.
4.2.4.
4.3.
4.3.1.
4.3.2.
4.3.1.
4.4.
4.4.1.
4.4.2.
4.4.3.
4.5.
4.5.1.
4.5.2.
4.5.1.
5.
5.1.
5.2.
SMART SYSTEM OPERATION SUB-PROGRAM ................................................................................... 12
REAL TIME MONITORING – OPERATION ................................................................................................12
INTRODUCTION OF MODERN MANAGEMENT SYSTEMS ............................................................................13
INTEGRATION OF RENEWABLE ENERGY SOURCES ....................................................................................17
ANCILLARY SERVICES ADVANCED CONTROL............................................................................................23
LOAD SHEDDING MECHANISMS ............................................................................................................23
SUMMARY OF THE ACTIVITIES IN THE PROGRAM: .....................................................................................24
SMART DISTRIBUTION NETWORK SUB-PROGRAM ............................................................................. 24
OPTIMIZATION OF THE ENERGY FLOW ...................................................................................................25
PROVISION OF INFORMATION TO THE TSO.............................................................................................26
REORGANIZATION..............................................................................................................................26
SUMMARY OF THE ACTIVITIES IN THE PROGRAM: .....................................................................................27
SMART METERING SUB-PROGRAM ............................................................................................... 27
ENERGY AUDIT GENERAL CONCEPT .......................................................................................................27
RECOMMENDATIONS FOR MIS (MANAGEMENT INFORMATION SYSTEM) INTEGRATION ................................30
SUMMARY OF THE ACTIVITIES IN THE PROGRAM: .....................................................................................33
SMART CUSTOMERS SUB-PROGRAM ............................................................................................. 33
DEMAND SIDE MANAGEMENT .............................................................................................................33
SMART NEW APPLICATIONS: ELECTRIC VEHICLE, INTELLIGENT CONSUMPTION .............................................35
SUMMARY OF THE ACTIVITIES IN THE PROGRAM: .....................................................................................35
TRANSVERSAL SUB-PROGRAMS .................................................................................................... 35
SOCIAL FRIENDLY APPROACH...............................................................................................................35
CYBER-SECURITY ...............................................................................................................................37
SUMMARY OF THE ACTIVITIES IN THE PROGRAM: .....................................................................................37
COST – BENEFIT ANALYSIS........................................................................................................ 37
DESCRIPTION OF COSTS (EU APPROACH) ........................................................................................ 39
DESCRIPTION OF BENEFITS .......................................................................................................... 47
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5.2.1. QUANTITATIVE ..................................................................................................................................51
5.2.2. QUALITATIVE ....................................................................................................................................51
5.3. COST – BENEFIT BALANCE FOR EACH PROGRAM ................................................................................ 51
6.
IMPLEMENTATION ROAD MAP ................................................................................................ 52
6.1. DETAILED PHASING ................................................................................................................... 52
6.1.1. STAGE 1: INITIAL PHASE (2012-2016) .................................................................................................52
6.1.2. STAGE 2: EMERGING PHASE (2017-2022) ...........................................................................................53
6.1.3. STAGE 3: MATURE PHASE (AFTER 2022) ..............................................................................................53
6.2. ROAD MAP ............................................................................................................................. 54
7.
INSTITUTIONAL ROLES ............................................................................................................. 55
7.1.
7.2.
7.3.
7.4.
7.5.
7.5.1.
7.5.2.
7.5.3.
MINISTRY OF INDUSTRY AND TRADE .............................................................................................. 55
ERAV .................................................................................................................................... 55
NPDC AND NPT ...................................................................................................................... 56
PCS AND LDUS ........................................................................................................................ 56
CIVIL ORGANIZATIONS ............................................................................................................... 56
CONSUMER ASSOCIATIONS .................................................................................................................56
UNIVERSITIES AND SCIENTIFIC INSTITUTIONS ..........................................................................................57
TRADE UNIONS .................................................................................................................................57
8.
CONCLUSIONS ......................................................................................................................... 58
9.
ANNEXES ................................................................................................................................. 59
9.1.
BENEFITS CALCULATIONS DETAILS ................................................................................................. 59
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I
1. INTRODUCTION
1.1. BACKGROUND
Vietnam’s power system has been built and developed in traditional centralized, integrated structure
with central power plant, transmission, distribution network and customers. While new upgrades of
grid infrastructure has been made to meet increasing demand, the power system is still operated in
traditional way: energy flows over the grid from central power plant through transmission and
distribution network to customers; dispatch is centralized by levels from national, regional centres for
the transmission network, dispatching to local centres for distribution network.
Reliability of the national power system is challenged in periods of tight reserves or transmission
congestion, compromising sufficient operational reserves to reliably supply the demand in all regions.
There can be blackout risk caused by domino effect – a cascading series of failures which may occur
in generation sector as well as backbone transmission network, especially in dry season where hydro
power plants’ reservoirs run out of water, although until such incidents have not occurred. Moreover,
the fast growth of demand and the high rate of electrification in the last ten years have obliged to
invest in upgrading and extending the grid and networks, without being able to also prioritize
modernization and automation.
In addition, since local primary energy resources (fossil fuels) become depleted and more expensive,
the government is introducing support mechanisms for the development of new renewable energy
(mainly small hydro, wind, solar, biomass). The grid is not well suited to integrate in the transmission
grid and distribute renewable clean energy sources. In particular, modernization is needed for a more
flexible and responsive operation of the system as the share of renewable energy increases in time.
Modernizing the existing power grid in Vietnam would bring consumers to be interactive with the
system, employing real-time, two-way communication between distribution companies and
customers, appliances and power grid in order to monitor and control the energy grid in near-real
time. Benefits of this modernization would be to improve energy efficiency, reduce overall electricity
consumption, improve reliability and utilization, reduce blackouts, and postpone costly new upgrades
(investments of new power plant and other network facilities).
To realize this modernization and its benefits, ERAV needs to assess the latest trends and potential
benefits of Smart Gird technologies in Vietnam power system operation, transmission grid and
distribution networks. Among others, ERAV responsibilities will cover setting standards and other
regulations that enable and promote smart grid technologies that are cost benefit, for example in the
Vietnam Grid Code and the Vietnam distribution Code.
Theoretically, Smart Grid is a digitally enabled electrical grid that gathers, distributes decentralized
energy sources, and acts on information about the behaviour of all connected users of the grid and of
the network that perform both a long distance transmission and local distribution network in order to
improve the efficiency, reliability, economics, and sustainability of electricity services, and its ability
to integrate and scale up new renewable energy.
Smart Grids are currently a worldwide development. Globally there are currently more than one
hundred Smart Grid pilot and full deployment projects under way, with roughly the same number
planned. In Europe, the target has been set for all meters to be converted to smart meters by 2022.
In the USA, there have been installed more than 35 million smart meters as of mid 2012.
The realisation of the Smart Grid vision will require many challenges to be overcome relating to:
technology, legislation and regulation, business models, investment, customer engagement, supply
chain, network management, reputation building, industry structure and skills. Apart from the general
drivers for Smart Grids – which include energy security, economic growth, CO2 emissions reductions,
growing energy demand and integration of renewables – specific drivers in Vietnam are improved
network management, competitiveness, changing regulation and customer engagement.
The primary aim of the electricity system is to generate and transmit electricity according to where
and when it is demanded. Ensuring that supply and demand are always in balance, and therefore the
integrity of the system is protected, currently relies primarily on the availability of sufficient
generation that is predictable, controllable and can be operated flexibly in order to react to
fluctuations in demand and supply shocks. It also requires a fit for purpose network to ensure that
electricity can be moved around the system efficiently and securely.
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The generation mix will evolve from a mix dominated by large power stations providing predictable
and mostly flexible electricity to a mix with a significantly greater proportion of variable and less
flexible generation.
Demand profiles will also change. The level of electricity consumption will increase due to the
expected electrification of heat and transport. Daily peaks and troughs are likely to become more
extreme. The locational profile of demand will also change as residential demand increases to power
cars and heat homes.
Increasingly, technologies that can be used to help balance the supply and demand of electricity
(demand side response (DSR), electricity storage and interconnection) and smarter networks are
likely to be required to help match the supply and demand of electricity efficiently and costeffectively under the changing generation and demand profiles highlighted above.
DSR is an active, short-term reduction or shifting in consumption of electricity at a particular time. In
a world where there is going to be more intermittent and inflexible generation, DSR can be used to
help balance supply and demand of electricity by providing system flexibility, especially at times when
customer demand and availability of variable renewable generation pull in opposite directions (i.e.
demand is increasing while availability of variable renewable generation is falling to a minimum and
vice versa). This could be achieved by self-supplying using local backup generation, or by not using
the electricity at that time, reducing the need for peaking plant and network reinforcement. In this
way, DSR can reduce the total capacity needed on the system, and reduce the need for generation
capacity to meet peaks in demand.
Building a ‘smarter’ distribution network involves network companies applying new technologies and a
communications platform to give them better information about, and more control over, the flow of
power on their networks. This will allow network companies to use existing assets more efficiently by
actively managing power flows, improving their ability to assess what reinforcement is needed (and
therefore reduce or defer investment), fix outages more quickly, and drive up safety standards. It
also has the potential to reduce the amount of generation and transmission investment required,
particularly as more distributed generation comes online. Some of these smart technologies, such as
automatic voltage control devices, are relatively simple and well understood whereas others, such as
those to facilitate community level energy systems, are more sophisticated.
1.2. CONCLUSIONS OF PREVIOUS REPORTS
During the first phase of this project and analysis of the existing local and international initiatives in
this field was undertaken. The following paragraphs summarizes the conclusions achieved.
After the analysis of the different experiences and trends in the world with regard to the Smart Grids,
it can be said that this new approach to the electricity sector has an important impulse in both
developed and developing countries. Though few years ago this technology sounded very incipient
and with no clear target, current situation locates the Smart Grids as a key tool for the future
challenges in the sector, i.e. energy efficiency, renewable energies integration, carbon emissions
reduction, demand side management, etc.
However, it is also true that in every country there are different approaches for solving and or
implementing the Smart Grids. Local framework, sector’s objectives, traditions, and or past legislation
clearly drive the solutions in multiple directions. It is therefore an important role for the local
institutions in Vietnam to guide the process according to the final targets and the expectances from a
process that clearly will bring benefits but no doubt will require large investments in the following
years.
Pilots from existing initiatives in Vietnam show
an interest of the utilities to open the companies
to
the
new
technology
and
approach.
Unfortunately, they have proven not to provide
enough information about the impact of a larger
scale.
The main conclusions from the international
experience with regard to the Regulatory role
can be summarized as follows:

Experience in other countries shows that
the regulator plays an important role in
the development of Smart Grids. In this way, the regulators in expected to provide resources
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

(or determine how to source them) and to eliminate barriers (technical and or regulatory) to
allow the implementation of the technology.
Regulators have internationally used two means for boosting Smart Grids. On one hand
explicit mentioning in the regulation and on the other by establishing performance conditions
only achievable by means of Smart Grids. Decision on selecting one or the other has mostly
related to the hurriedness to implement the new technology and willingness to cover part or
all the expenditures.
Smart Grids have a maturity time for providing benefits. Therefore, there is a need for
financing the costs of the investments. Usual approaches have included among others
subsidies, increase in tariffs, benefits sharing, etc.
The main conclusions from the international experience with regard to the Technical aspects can be
summarized as follows:



It is a lesson learnt that solutions applied differ from Developed to Developing countries. In
that sense, the following conclusions can be extracted:
o Developing Countries usually focus on basic operational aspects for this new
technology may speed up the process to reach sustainable performance. In this way,
Energy efficiency (loss reduction) and Quality of the service improvement are among
the main targets.
o Developed Countries however have already reached a sustainable performance and
they focus on other more sophisticated targets. In that sense Quality excellence, Peak
Demand Reduction, Climate Change support and Further Business restructuring can
be found among them.
Vietnam should combine both approaches in a long-term road map in order to consolidate the
sector and then pursue all achievable targets.
Technology applied is found to be similar worldwide. However, the definition of standards
seems to be an issue that needs to be addressed within the road map.
Finally, the International Experience shows that there are some Barriers that can delay the
expansion of the smart grids technologies. Among them the following may be present:







Economical Barriers for the investments
Uncertainty about assets ownership and operation
Lack of technological standardization
Impossibility to adapt the utilities to the new technologies requirements
Social refusal for new equipment or the new staff conditions
Communication network weakness
Etc.
1.3. OBJECTIVES OF THIS DOCUMENT
This report will recommend and develop a Smart Grid program for Vietnam based on the background
and actual situation in Vietnam.
The Smart Grid Program includes following aspects:

Overall structure of Smart Grid system proposed to Vietnam including each Smart Grid
component (transmission and distribution level);

Institutional arrangements, mainly role of ERAV, and functions and responsibilities of the
transmission company (NPT), the distribution companies (PCs) and the National Dispatch
Centre as system and market operator;

Type of smart grid technologies and their characteristics, use, benefits and requirements for
each Smart Grid components;

Awareness campaigns and mechanisms to motivate and allow consumers to participate in
Smart Grid system and Demand Side Programs;

Implementation roadmap for Smart Grid in Vietnam with indicative timeframe, and prioritizing
first the technologies that can bring the larger benefits to Vietnam power system.
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2. SMART GRIDS: VISION AND OPPORTUNITIES FOR VIETNAM
2.1. DEFINITION
The strategy
2.2. VISION
Vietnam is a blooming country in the South East Asia region and would like to become a technological
leader and reference of the region’s energy sector. The country has already started the
implementation of a challenging road map for the sector reform and next steps shall include the
necessary changes to introduce modern technologies in the energy utilities and customers.
The implementation of Smart Grids shall represent that technological upgrade will be incorporated in
the sector and that a gate to improvement of the quality of the services and new service will be open
for the future. Additionally, the two way capabilities of this kind of technologies shall allow Vietnam to
be leader in the introduction of new energy efficiency and demand side management tools by means
of demand side management capabilities.
Likewise, Vietnam has an opportunity to channel all the know how acquire during the process in order
to develop a new industry that can both serve the domestic market and export the experiences to the
surrounding countries.
In this way, the proposed vision for Vietnam in the field of Smart Grids would be as follows:
To become Vietnam a leader of the efficient use of the new Smart Grids Technologies in the
Region and a leading international example for the South East Asian Region in order to improve
the quality of the service, reduce the unit demand in the country, and create new high value jobs
in the sector.
2.3. OPPORTUNITIES
Smart Grids offer many interrelated benefits such as the integration of large-scale and microrenewable without the need for extensive infrastructure upgrades, reduced need for peak power
plants, improved grid asset utilisation and operational efficiency, improved reliability of service and
accommodation of future demand. In addition, Smart Grids are important enablers for the transition
towards the low carbon economy.
The smart grid is an enabler, not an end itself. It is accepted worldwide that an implementation of
smart grids is absolutely necessary in order to achieve the strategic targets for integration of
renewable energy sources in the most effective manner, a more secure, sustainable electricity supply,
optimal and efficient use of energy and full inclusion of consumers in the electricity market.
At the same time, investments for the development of smart grids should be financially sound. Market
forces must see real financial returns in achieving these energy policy goals to incentivise the
continued significant investments which will be required over the coming decades.
In this way, Vietnam is in an excellent position to capitalize on the opportunities that Smart Grids
present thanks to:





A strong Governmental interest to efficiently and properly develop this new technology
A wide range of internationally significant industries
Key Smart Grid demonstrator and pilot projects already in progress
Its diverse geography, its entrepreneurial climate and its ambitious renewables targets
Significant company and academic strengths in the major PCs. REPORT ON RECOMMENDATION OF SMART GRID PROGRAM FOR VIETNAM
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Therefore, the key market and technology opportunities with the implementation of Smart Grids for
Vietnam are:







Sharp and definite improvement of the quality of the service to the customers for them to
obtain the best value for the money.
Develop a more efficient use of the energy by means of demand side management programs.
Optimal and sustainable integration of new energy sources (renewable, distributed) without
large increases in the investments.
New business models for supplying electricity and additional services
Data acquisition, monitoring and analysis of the entire energy system
Network automation and optimization
Development of future new applications like: Energy storage, electric vehicles, etc
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3. STRATEGIC APPROACH
3.1. PHILOSOPHICAL AND OPERATIONAL APPROACH
3.1.1.
PHILOSOPHICAL APPROACH
The Smart Grids program for Vietnam must be comprehensive and include all areas that can be
developed in the following years. In this way, the following aspects are to be included:

Smart System Operation: this area is required in order to allow the optimization of the quality
of the service by better management of the existing power plants and shall also allow the
introduction of new renewable energy in safe and sustainable conditions.

Smart Distribution Network: this area shall allow the PCs to optimize and improve the
management of the networks in order to:
o Reduce the number of incidences in the grid
o Reduce the time required for energy reestablishment after an incident happens.
o Reduce technical losses by means of efficient distribution of the energy flow through
the grid.
o Reduce/optimize the need for further investments for the demand increase and the
introduction of distributed energy.

Smart Meters: this area shall allow:
o The PCs to provide a better service to the customers by means of a deeper knowledge
of their consumption profile.
o It will also help to improve the operational efficiency (losses, collection, etc) due to
the introduction of modern software and hardware with immediate analysis and
actuation.
o Finally, the customers shall have enough and accurate information to make the proper
decisions.

Smart Consumers: as one of the final purposes of this technology, this area shall allow the
customers to optimize the consumption in order to save money, reduce the peak demand,
and contribute to the reduction of the CO2 and NOx emissions to the grid. They will also be
capable of participating in the generation by means of distributed plants that will both
contribute to a greener generation mix and help to reduce the investments needs in the
network for the source of energy is brought close to the demand.
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Smart
Consumers
Program
Smart
Metering
Smart
Grids
Smart
System
Opera on
Program
Smart
Distribu on
Program
All the aspects above mentioned are necessarily integrated in the same Smart Grid and shall have
internal connections in order to develop a sustainable and modern energy sector.
Finally, all the technological and behaviour based programs must be social friendly. The new
technological upgrade is founded on the benefits that will be achieved through the improvement of
the quality of the service, the increase of the efficiency in the use of the energy and the capability for
developing alternative services for the customers. In this way, it is mandatory that the solutions
provided are fully shared with the population in terms of:




Receive enough and accurate information about the new developments and how they will
affect them
Participation in the design of the programs so that they are involved from the beginning
Receive capacity building about how to profit from the new developments
Receive update information of the deployment progress
This social friendly approach shall become an envelope that will be present in all the phases of the
program.
3.1.1.
OPERATIONAL APPROACH
The operationalization of the strategy shall involve all aspects in the energy supply chain. In that
sense, there will be two dimensions. On one hand, it is the dimension for the natural flow of the
energy. On the other hand, it is the dimension for the analysis of the data and the actions thereof.
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Supply Chain dimension
Exhibit 1 Dimensions and Structure of the Smart Grids Vietnam
As it can be seen in Exhibit 1, Generation, transmission and system operation, distribution network,
smart metering and customers’ applications represent the first dimension. The second dimension,
transversal to the whole first dimension shall integrate the communications paths, the management
information systems and the use of the information from the final users (both utilities and
customers).
3.2. PHASING OF THE PROGRAM
The program for the implementation of smart grids must be progressive and be implemented within a
reasonable range of time. Progressivity represents in the case of Vietnam, the proper implementation
of the different technologies in due time to allow the stakeholders to incorporate and assimilate the
new technologies. Reasonable range of time represents a period that is within the expectance of the
stakeholders and shall not generate conflicts of integration.
Phases of a Smart Grids project comprises the following ones:



Initial Phase: integrating the basic functions of the Smart Grids. This phase is mostly focused
on smart meters and limited automation of the network.
Emerging Phase: this phase develops a deeper integration of the automation of the system
with the existing meters. It also develops tools for energy efficiency and the integration of
generation plants (specially no manageable Renewable Energy Sources).
Mature Phase: in this phase, the systems are already in place, fully operational and
integrated, and advanced demand side tools are implemented. Alternative services are also
integrated in the phase (i.e. electric vehicle) and energy storage.
Exhibit XX shows an example of the phasing for the phasing in Sweden where a similar approach was
implemented.
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Exhibit 2 Sweden Smart Grids Implementation Phasing
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4. TECHNOLOGICAL DEVELOPMENT
As mentioned above, the Smart Grids Program shall cover the entire two dimensions above
described. It will therefore comprise the following sub-programs:




Smart
Smart
Smart
Smart
System Operation Sub-Program
Distribution Network Sub-Program
Metering Sub-Program
Customers Sub-Program
Finally, the whole programs will include social friendly approach in order to facilitate its integration
with the existing social reality.
4.1. SMART SYSTEM OPERATION SUB-PROGRAM
The operation of the system is clearly one of the more technological sub programs. It must define the
changes and improvements to be introduced in the National Load Dispatch Center as well as in the
grid operators (transmission and distribution) in order to transform the system. The main
characteristics of the new system would be as follows:





Management of large data volumes
Intelligent applications for forecasting
Automation and remote operation
Real time interaction with other actors
Transparency
The most important areas for the NLDC comprises the interoperability of different actors/devices
connected to the grid, the management of the renewable generation, the management of eventual
energy storage and the knowledge of the situation of the distributed (embedded) generation in the
distribution network.
4.1.1.
REAL TIME MONITORING – OPERATION
The control of the network requires not only systems and forecasting models but the to have real
capability for remotely controlling the main assets in the network. Aspects like real time monitoring of
the RES, network self-healing, or dynamic network adaption to reduce technical losses and spare
capacity requires that the operators and the system have the opportunity to have information and
operate the equipment in real time. In this way, the following basic facilities are required, at least at
substation level:

Monitoring of real time network parameters:
o Voltage (feeder, transformer, bus bars);
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
o Current (Feeder, Transformer)
o Frequency;
o Harmonics
o Flicker level
o Transformer’s parameters (temperature, changer position, oil level, etc.)
o Breakers and switchgears state
o Protections state
o Capacitors’ bank state
o Auxiliary services state (pumps, temperature, etc.)
Control
o Open and Closure of Breakers (Mandatory)
o Open and Closure of Switchgears (advisable)
o Transformer’s tap changer operation
o Capacitors’ bank operation
Likewise, lines may also have some of the elements above indicated however it is not strictly
necessary at the automation level expected in this project.
In that sense, the table below shows the pending control activities that need to be implemented:
Item
Fully Controlled
Connected Not Working
Not Connected
Total
Power Plants
61
20
20
101
500 kV Substations
18
220kV Substations
77
4
110kV Substations
266
76
180
522
Total
422
100
160
682
81
Therefore, the actuations are necessary in 260 substations (100 for repair and 160 new
developments) in order to automatize the transmission system.
4.1.2.
a)
INTRODUCTION OF MODERN MANAGEMENT SYSTEMS
Software Functions
For this purpose the following functions are necessary to be present in the National Control and
Dispatch Center/s:

State Estimation
The State Estimator calculates the most probable network snapshot compatible with the set of
values received from the field (using the SCADA system) which normally will include missing
and wrong values among the good ones. The state estimator will fill the missing values and
correct the wrong one, inside the observable area of the network. The resulting set of values
has, according with the estimation criteria, is the most probable set of values coherent with
the electric model and the system injections.
State Estimation is also used as a base by the other functions of the Real Time Security
Analysis such as Contingency Analysis and Dispatcher Power Flow Analysis functions. It runs
automatically by event, by operator manual start or by time (every 5 minutes as example).

Tele-measurements acquired from the field cover a minimum of 85% of the total
production.The operator enters data for the remaining 15% manually or employing statistical
tools based on values stored in the real time database. Different weighted factors are for each
variable, so that manually entered data for the un-telemetered part of the network does not
affect the telemetered part. Usually, the state estimator provides a good solution for the
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whole network (telemetered and un-telemetered values). In any case, the use of statistical
or manually entered data limits the accuracy of the state estimator results and (in some
cases) produce convergence problems.

Contingency Analysis
Contingency analysis runs, typically, every 10 minutes1 and determines which contingencies
in a given contingency list would result in overloading and/or abnormal voltage conditions in
the network. Contingencies may be single or multiple outages of network components. Up to
500 contingencies can be included in a contingency list. Contingency Evaluation uses State
Estimator’s valid results as base, and therefore the mentioned limitations on the state
estimations are automatically transferred to the contingency analysis.
A two-step approach for contingency evaluation is used: (i) Contingency Screening (CS) and
(ii) Contingency Analysis (CA).
Contingency Screening provides a ranking of contingencies from the contingency list,
according to expected limit violations in case of an equipment outage. It uses a fast
approximate power flow calculation. The Contingency Analysis module evaluates in greater
detail contingencies at the top of the list. The results of the Contingency Analysis are given to
the operators as violation list for each of the critical (harmful) contingencies.

Dispatcher Power Flow
Load flow program is executed at the operator’s request, in study mode, for establishing a
solution under pre-established operating conditions for study purposes, using as input the
State Estimator output.
The operator can initialize the power flow analysis program with a valid real-time network
solution (from the state estimator) or from a saved case to study particular conditions of load,
generation, topology, and regulation.

Economic Dispatch
The economic dispatch function calculates the optimal (least cost) base points for the
generating units in service, combine cycle blocks and power plants that are included in
economic dispatch. The base points calculated by Economic Dispatch function can be loaded
into the Automatic Generation Control function.
Some of the economic functions in Real Time are now, responsibility of the Market Operator
or simply are not possible as where conceptually designed in the past. As an example the
optimization processes where based in operative variable costs and now the system is based
in prices.

Reserve Monitoring
The purpose of this function is to calculate the various reserve quantities and to alarm the
operator when any of them falls below the operator specified level. The Reserve Monitoring
function:
o Calculates reserve requirements based on reserve policy selected by the operator
(usually the trip of largest generating unit or an interconnection line) plus or minus an
allowable margin by reserve class,
o Calculates the available reserves, by reserve class and gives alarms to the operators
in case current active reserves are not sufficient compared to the calculated
requirements.

Short Term Load Forecast
The Short Term Load Forecast (STLF) function is executed on demand for a user defined
study period (up to 2 weeks) to forecast hourly loads by using historical load values, historical
weather values and weather forecast data. STLF is executed periodically to re-forecast the
loads in case weather forecasts change significantly or if new telemetered data indicate a
significant difference between the actual load and forecasted loads. There is also a userselectable option to execute STLF automatically each hour, to update and refine the current
day's load forecast based on the most recent load data. In case of excessive deviations
between actual and forecasted load, it gives alarm.
1
This value may reduce depending on the technology applied.
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
Dispatcher Training Simulator

Dispatcher Training Simulator (DTS) is available. The simulator provides a separate
environment in which the operator uses a replica of the SCADA/EMS functions to safely
practice the various operator functions in normal as well as emergency conditions. A specific
console has been dedicated for this function.


Remote operation of the elements connected to the grid
The operators must perform the control of all elements in the grid remotely. Breakers (at
least) in all substations require remote operation capabilities and the elements must provide
information about the state of the element at all moment. Alarms remote reports to ELES in
case the manoeuvre is not fulfilled are only present in the substations operated by ELES.
b)
Communications – protocols and equipment
As part of the diagnostic of the current state of the power system the Consultant has identified that
the communication between the communications between the elements of the system and the SCADA
are using the IEC 60870-5-101/104 protocol. In future the NLDC is proposing a reorganization of the
communications with the additional introduction of the ICCP protocol.
Protocols are similar to languages, which allow the RTU/SCADA units to communicate each other.
Depending of the complexity of the contents and speed of the communication the protocols can be
classified in the following seven categories2:

Layer 7 – Application: This layer supports application and end-user processes.
Communication partners are identified, quality of service is identified, user authentication and
privacy are considered, and any constraints on data syntax are identified. Everything at this
layer is application-specific. This layer provides application services for file transfers, e-mail,
and other network software services. Telnet and FTP are applications that exist entirely in the
application level. Tiered application architectures are part of this layer.

Layer 6 – Presentation: This layer provides independence from differences in data
representation (e.g., encryption) by translating from application to network format, and vice
versa. The presentation layer works to transform data into the form that the application layer
can accept. This layer formats and encrypts data to be sent across a network, providing
freedom from compatibility problems. It is sometimes called the syntax layer.

Layer 5 – Session: This layer establishes, manages and terminates connections between
applications. The session layer sets up, coordinates, and terminates conversations,
exchanges, and dialogues between the applications at each end. It deals with session and
connection coordination.

Layer 4 – Transport: This layer provides transparent transfer of data between end systems,
or hosts, and is responsible for end-to-end error recovery and flow control. It ensures
complete data transfer.

Layer 3 – Network: This layer provides switching and routing technologies, creating logical
paths, known as virtual circuits, for transmitting data from node to node. Routing and
forwarding are functions of this layer, as well as addressing, internetworking, error handling,
congestion control and packet sequencing.

Layer 2 – Data Link: At this layer, data packets are encoded and decoded into bits. It
furnishes transmission protocol knowledge and management and handles errors in the
physical layer, flow control and frame synchronization. The data link layer is divided into two
sub layers: The Media Access Control (MAC) layer and the Logical Link Control (LLC) layer.
The MAC sub layer controls how a computer on the network gains access to the data and
permission to transmit it. The LLC layer controls frame synchronization, flow control and error
checking.
Layer 1 - Physical: This layer conveys the bit stream - electrical impulse, light or radio signal
through the network at the electrical and mechanical level. It provides the hardware means of
sending and receiving data on a carrier, including defining cables, cards and physical aspects.
Fast Ethernet, RS232, and ATM are protocols with physical layer components.

ISO (International Standards Organization) standard seven layer OSI (Open Systems Interconnection). The
reader can imagine the analogy of communication protocols with the programming languages of low level and high
level for computer programs.
2
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Protocols until layer 4 allows exchange signals and simple operation commands, the layers 5 and 6
allow exchange the information between systems and develop sophisticated user interfaces, the layer
7 allows in addition to exchange the information and display it support sophisticated processing of the
data, obtain useful information and run complex programs of analysis of the system.
Regarding the protocols typically found in Power Systems the classification is the following:
1. DCCP (Datagram Congestion Control Protocol: Is a protocol of layer 4 (transport), usually
associated with a fast collection of data linked to a elemental/heuristic method of solution of
congestion, often un-useful if the process require complex analysis and fast response.
2. ELCOM (Electricity utilities communication): Is an electrical utility oriented data
communication protocol used to exchange data such as indications, commands,
measurements and short text messages over WAN and LAN between control centers. The
ELCOM provider is a third party solution manufactured by KEMA and it is responsible for
network interaction between control centers.
3. IEC 60870-5-101: is a standard for power system monitoring, control and associated
communications for remote control, remote protection, and associated telecommunications
for electric power systems, and use standard asynchronous serial remote-control channel
interface between DTE and DCE. The standard is suitable for multiple configurations like
point-to-point, star, multidropped etc.
4. IEC 60870-5-104: protocol is an extension of IEC 101 protocol with the changes in transport,
network, link and physical layer services to suit the complete network access. The standard
uses an open TCP/IP interface to network to have connectivity to the LAN (Local Area
Network) and routers with different facility (ISDN, X.25, Frame relay etc.) can be used to
connect to the WAN (Wide Area Network). There are two separate link layers defined in the
standard, which is suitable for data transfer over Ethernet and serial line (PPP - Point-to-Point
Protocol). The control field data of IEC104 contains various types of mechanisms for effective
handling of network data synchronization
The integration of a significant participation of Wind and solar plants in the power system demands an
improvement of the supervision of the system and enhancement of the remote operation of both
generation plants and elements of connection in the transmission and distribution network.
It is clear that IEC 60870-5-104 is, among the exiting in the company, the most suitable protocol to
provide the fully layer 7 requirements for communications with the equipment and among the control
centers.
In any case, the consultant underlines the following aspects for the future implementations of
communication protocols:

Consider open non-proprietary standards and protocols for RTU/SCADA Control and
Monitoring. For this purpose the priority would be to prioritise the use of the IEC 60870-5104 protocol.

Proprietary and vendor specific protocols and programs should be avoided at all costs.

Select programs and equipment interchangeable software and hardware from one vendor to
other

Develop and implement the programs and system software code after purchase of systems.

Note that due to advances in technology and possible custom and off the shelf hardware and
software availability, the distinction between RTUs, PLCs, DCS and PCs are disappearing. All
these now overlap each other with respect to functionality, protocols, hardware and software.

The main requirement for all these networks is: They have to operate in real time
deterministic mode, so that the process and production data can be received and sent in a
timely manner to all required places on the local and wide area networks.
However, new equipment in both EU and USA are currently widely introducing the protocol IEC61850
as the standard for the communications among equipment. This new protocol is more flexible and will
surely represent the future for supporting the communications for Smart Grids. Therefore, ELES must
also start introducing it in the SCADA as existing protocol and within new or retrofitted substations.
Key characteristics of the protocol are as follows:

This is a global standard for “Networks and Substations Communications Protocol”
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




It provides a data and service data model that can be escalated and allows new functions
development.
The protocol itself does not define a specific set of control or protection functions. It is open
for client’s customization.
It is flexible in terms of applicable philosophy. It provides a customization programming
language that can be used to describe the substation configuration as per the client’s needs.
Uses Ethernet and the TCP/IP protocol.
Interoperability among the equipment and more active participation of the power equipment
in the generation of ‘messages’.
4.1.3.
a)
INTEGRATION OF RENEWABLE ENERGY SOURCES
Additional Management information Systems
Additionally, and in particular for the Renewable energy generation, the following functionalities are
necessary:

Wind/Solar Generation Monitoring
Wind/Solar parks must be continuously monitored (solar only above certain level of installed
capacity). Main data to be controlled comprises generation and weather conditions registered
for studies, forecast and statistical purposes.
Correlation between measured parks and uncontrolled generation should be established in
order to obtain real generation estimation as precise as possible.
Differences between forecasted generation and real estimations must be used to define
tertiary reserve requirements.

Wind/Solar Generation Forecast
In order to minimize availability uncertainty, an advanced and accurate (as much as possible)
Wind/Solar generation predictive system is necessary.
Control area operators and power markets in scheduling functions and real-time operating
practices can reduce incremental costs due to the uncertainty in the timing and quantity of
energy delivery from Wind/Solar generation facilities in operational time frames with better
short-term Wind/Solar generation forecasts and appropriate use of those predictions.
One of the main difficulties of Wind/Solar forecast is the variability from one area to another
in the same region, especially due to geographical aspects (mountains, valleys…). In
consequence, the Wind/Solar forecast must be done specifically for each Wind/Solar farm. In
some cases some parks could be grouped, if their characteristics allow it and their connection
the network are near (measured in electrical terms).
Since the Wind/Solar may have a different speed at ground level or some meters above
(which also contribute to this uncertainty), the forecast should be done at propellers level,
which may vary according the aero generator technology and power.
Weather forecasting algorithms are to be implemented for this purpose.

Static Analysis (partially present)
Static Analysis functionalities are compulsory, not only to control the system capacity to
integrate the amount of RES but also to anticipate its capability to provide the Ancillary
Services required by the system with the remaining conventional generation.
It is important to include in the model the technology used in the different parks in order to
consider it in the static studies (voltage control capability…).
As a result of the static analysis and due to security criteria violations, decisions to limit the
RES generation could be taken. In such a case, the volume and allocation of the reductions
required over RES generation is a functionality to be included in the RES Generation
Monitoring System.

Dynamic Analysis (not present)
Dynamic Analysis is a complex study. However, they are mandatory if most important
characteristics of the Wind/Solar parks are to be taken into account in determining the effects
of usual faults in the power system. Due to the limited contribution of this kind of
technologies to the stability of the system, as well as the potential disconnection of important
amounts of Wind/Solar generation after faults (even properly cleared) it is important to
assess in advance the potential evolution of the system after all credible contingencies.
b)
Development of a RES control Center
RES Control Centre should not be seen as an independent control centre, but as an expansion of the
National Load Dispatch Centre, and its functionalities, complementary to the existing ones. The
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objectives of this functionality are to reduce the impact of the RES generation into the system
security and to the quality of the services provided by the electric system.
Wind generation is primarily an energy resource, and cannot be dispatched like conventional
generation. In more traditional utility operations, predictions of system load for the next hour, day,
week, etc.
Incremental costs due to the uncertainty in the timing and quantity of energy delivery from wind
generation facilities in operational time frames can be reduced with better short-term wind generation
forecasts and appropriate use of those predictions by control area operators and power markets in
scheduling functions and real-time operating practices.
b.1)
Wind & Solar Production Forecast
Wind generation forecast is a very difficult task even for short-term periods. Although strong efforts
have been made during last years to improve the results, there are still large differences between the
estimations and actual productions. With high penetration of wind power, the unit commitment of
thermal units may dramatically change with the estimation of wind generation during the study
period. Additional tertiary reserves must be provided to support system reliability while minimizing
operation cost. A daily time frame, with hourly time frames will be a suitable basis for determining
the unit dispatch.
One of the promising arrangements intending to mitigate negative effects of wind intermittency and
its mismatch is horizontal coupling of wind power resources with pumping plants and other
perspective energy storage facilities.
As a matter of fact, the intermittent nature of the wind power resource is a reality that cannot be
eliminated completely. Special regulatory arrangements and state-of-the-art forecasting tools are
required to create conditions for competitiveness of the wind power in the Market.
b.1.1)
Meteorological Data Acquisition and Time Series Data Base
The forecast system requires updated meteorological forecasts which are in general done by
Meteorological Services.
If it is available, the meteorological data collection shall be automatized as much as possible, to
reduce possible manipulation mistakes and to guarantee the best and updated information available.
The forecasts database shall contain at least the following time series:





Meteorological forecasts.
Meteorological real values.
Forecasted wind generation, at different time frames.
Actual wind generation
Forecast errors statistics
One of the characteristics of the system required is the “cleaning” of actual values (meteorological or
wind generation) time series. This “cleaning” should correct anomalies due external factor to wind
generation (i.e. network incidences, instructed reduction in generation, etc.) in order not to mislead
the forecasting process.
b.1.2)
Revision of Historical Data
Wind generation time series are requested for its use in the forecasted tools. In this regard, it is
important, that wind generation reductions due to security or other external factors will be “cleaned“
from the time series, in order not to be replicated them in future forecasts.
The wind forecast tools, for very short-term horizons, require real time information of the wind power
generated, with the best granularity possible. This information can be obtained from the SCADA
system that collects real time information from the parks. To obtain the hourly energy values either
the integration of instantaneous power values inside the hour or the reception of the metering system
in real time could be used.
This methodology will provide the total power and energy produced by the different parks.
It could be that not all parks are metered. In such cases, the power and generation not metered can
be estimated using through similarities with metered parks, making correlations with the generation
of both parks. This method will provide valuable information with enough quality in cases the metered
part is much bigger that the estimated part.
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b.1.3)
Forecasting Models and Algorithms
Once all available information has been collected and revised as per the two subsections above, ELES
need to forecast the potential for production of wind and solar according to the existing proven
models. There are several models to predict this potential production and the company need to
identify the most suitable as per its interests.
In any case, the forecasting model for wind generation must include at least the following
characteristics:

Wind speed probability must be calculated by considering the following aspects:
o
o
At Global Scale level:

Temperatures differences (10.000 km)

Coriolis acceleration (10.000 km)

Geostrophic winds (1.000 km)
At Meso Scale level:

o
o

Temperature differences due to land warming land-mountains-sea (100km)
At Micro Scale level

Obstacles –Natural, artificial- (10km)

Stelae (10km)

Boundary Layer Theory
Calculation methodologies (examples)

Weibull distribution

Wind Rose
o
Height of the Generator Pole
o
Turbulences
Finally the potential for production is evaluated by crossing the wind intensity versus the Wind
Turbine power curve.
b.1.4)
Evaluation of Final Production
The Potential for production will determine the capability of the wind and solar plants to generate in
certain moment of time. However, final dispatched production must also consider the technical
aspects related to the demand and network states at each moment.
In this way, the system must cross check the potential for production with the capability –and
suitability- to evacuate that total potential for production. The final result of this evaluation will
provide the Total Final production forecasting of the RES plants.
b.2)
Real Time Monitoring and Control
To monitor and control de wind generation real time information of each wind park is required in
addition to the enhancement of the control of the generation system. Different processes will use this
information:

Wind and Solar Generation monitoring.

Conventional generation and energy balance services

Generation curtailment.

Wind Generation forecast
b.3)
MAN MACHINE INTERFACES
The operator of the RES Control Centre must have available three MMI: The MMI that controls the
new applications, the Power System Control Centre MMI and a wall map projection system.
b.3.1)
MMI FOR CONTROLS OF NEW APPLICATIONS
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The new applications shall have available a MMI interface from where the operator shall be capable
to:



Visualize the historic data, the actual data and the results of the processes.
Allow the operator to introduce, modify create and delete any information from the historic
time series.
Run and modify the execution parameters of the application.
All this functions shall be possible using any of the following means:



Numerical presentation in form of tables or individual values.
Graphical presentation in form of curves, bars or pie charts, to mention some of the possible
presentation means.
Export the data, adding them to a Data Base or export them as excel format or flat files. Also
the information could be exported in a computer-to-computer communications using different
possible communications protocols, including but not limited to FTP, ICCP, etc.

b.3.2)
MAN MACHINE INTERFACE SYSTEM
The RES Control Centre shall be considered an extension of the Power System Control Centre and in
consequence shall have the same MMI system, in order to not have two different systems working at
the same time.
The operator will be able to do, but not limited, the following actions:

Visualize any value, received from the SCADA, result of a process or calculated using any type
of value, analogue or digital, from SCADA or output of any process.

Be able to set and modify limits to any value, which will generate an alarm when those limits
are violated and he must have also de capacity to recognize and cancel the alarm, but not to
eliminate the message from the historic files.

Trend recording of any value in the database.

Save it in a Data Base, with a frequency predefined in the system database.
b.4)
SYSTEM ARCHITECTURE
There are different potential system architectures to perform the functionality described above. In
following paragraphs two “families” of architectures will be described, depending on the potential
supplies of the new functionalities:


If the supplier is the same one that the actual supplier of the Power System Control Centre
SCADA and EMS System, the architecture shall be an expansion of the current system.
If the supplier is different from the actual Control Centre supplier, the system architecture
shall be separated from the actual and connected to it using standard communications
protocols.
Following figure schematized (in a simplified way) the expected situation of NLDC National Control
Centre simplified architecture is (after the improvements that the NLDC is likely to implement):
MMI
COM
Other
Computers
APPLIC.
Hot – Cold
Back-up
ADM
DB
Field
(RTU’s)
Exhibit 3 Future NLDC Schema
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Where:






ADM is the workstation that makes the Administrative functions (Data Base management…).
At least shall be one ADM, may be some other as back-up
DB is the Data system database, normally based in SQL technologies. In real time there is
normally a faster copy of this Data Base.
COM workstations with the function to communicate with the field (RTU’s) or with other
computers, using standard communications protocols (ICCP, Elcom…)
Applications workstation, where runs the different EMS, AGC among other real time
applications.
MMI or Man Machine Interface represents the information display technologies that facilitate
the visualization of all information to the operator and the capacity of the operator to control
the system.
Hot and Cold Back-ups represents the spare workstation that will assume main
functionalities in case of fails of a dedicated workstation.
This is a schematic architecture and does not intent to perfectly replicate actual system architecture,
but only a mean to facilitate the comprehension of the system expansion.
b.4.1)
Same supplier that the actual Power System Control Centre
In this case, the new functionalities will be integrated in the same architecture and considered as an
expansion of the actual system.
A simplified representation of the proposed architecture is shown in following figure:
MMI
WIND
Data Col.
Meteorological
Services
Wind
Time
Series
Mimic
Map Board
manager
WIND
APPLIC.
MMI
COM
Other
Computers
APPLIC.
Hot – Cold
Back-up
ADM
DB
Field
(RTU’s)
Wind generation
Field (RTU’s)
Wind generation
Owner Control Centres
Exhibit 4 Control Center Expansion - Same Supplier
Where the WLAN has been extended to allocate:





Additional MMI for the use of the wind Control Centre operator.
The Mimic Map Board controller
Wind Applications workstation where the different application will run.
Data collection PC which will collect automatically, if possible, the meteorological
information.
If required, the Power System Control Centre could be expanded with a new COM
Workstation
Information interchange between systems
The system has a single Data Base and as a consequence all information to be presented in the
different displays (including the map-board) must be included in this Data Base.
In consequence, all applications shall be responsible to allocate their results or input data into the
Data Base, in order to be processed by the available software (display presentation, alarms and limits
control, trend recording...)
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The information for monitoring wind generation is already available in the Data Base, as part of the
information collected periodically by the SCADA system. Eventually, new windows for displaying this
information will be required, and they should be developed using the standard tools available at the
system.
b.4.2)
Different supplier that the actual Power System Control Centre
In this case, it is assumed that the software shall be independent and that no modifications shall be
introduced to the existing Power System Control Centre functionalities. The projected architecture is a
separated and independent one. Following figure schematizes this integration:
Mimic
Map Board
manager
WIND
Data Col.
Meteorological
Services
Wind
Time
Series
MMI
MMI
WIND
APPLIC.
COM
Hot – Cold
Back-up
COM
Wind generation
Field (RTU’s)
Wind generation
Owner Control Centres
APPLIC.
ADM
DB
Field
(RTU’s)
Other
Computers
Exhibit 5 Control Center Expansion - Different Supplier
Where:





Additional MMI for the use of the wind Control Centre operator, connected to the Grid Control
System.
The Mimic Map Board controller
Wind Applications workstation where the different application will run.
Data collection PC which will collect automatically, if possible, the meteorological
information.
If required, the Power System Control Centre could be expanded with a new COM
Workstation in order to allocate the communications with new RTU’s in the wind parks or to
computer-to-computer communications with Wind Control Centres.
In this case, a new communication link shall be established, using ICCP standard protocol, to connect
the Grid and Wind Control Centres. The information to be interchanged shall be at least, but not
limited to:


From Wind to Power System Control Centre: all the information, as results of the different
processes that are likely to be consulted by the operator.
From Grid to Wind Control Centre: The real time information required by the wind
applications.
Information interchange between systems
The system has a Data Base from where the different displays from the MMI must have it available
and included in the Grid System Data Base. At the same time, some of the information available in
the Power System Control Centre Data Base is necessary to be used by the new applications. In
consequence some of this information must be made available to new applications Data Bases.
In consequence, the following flows of information are required:
 From Power System Control Centre to Wind Control Centre

SCADA information required for wind monitoring (wind generation by park, etc.)

State Estimation results to perform Real Time Security Analysis (injections as input and
Voltages and Flows as starting point)
 From Wind Control Centre to Power System Control Centre
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
Wind applications input data that must be presented in the MMI

Wind applications results that must be presented in the MMI
4.1.4.
ANCILLARY SERVICES ADVANCED CONTROL
In environments where the integration of Renewable is massive, the most important ancillary services
that NLDC has to manage and monitor include:

Primary Frequency Control (present)
Compulsory for all generation facilities, except RES, above certain installed capacity (defined
by ELES). Primary Frequency Control participation rate is proportional to the total installed
capacity of each generation facility. Primary Frequency Control reserve is determined by
ELES.

Secondary Frequency Control
This service shall be provided by all generation facilities above certain (larger that in the
previous item) installed capacity, except for RES, cogenerations and active facilities without
AGC system installed.
Secondary Frequency services are daily assigned by the System Operator to minimize the
total cost of the service.

Tertiary Frequency Control
In an environment with large integration of RES, the tertiary frequency control becomes more
active in terms of the frequency of plants participation. Whereas a normal situation without
RES may require the participation of the tertiary once or none a day, under a RES scenario
this may reach three or four times an hour in extreme situations. It is also possible that this
scenario requires an increase of the tertiary reserve to cope with all requirements.
This framework requires that the company revise and re-evaluate the costs for the secondary
and tertiary auxiliary services in order to maintain the stability of the system. In the
international experience, the costs for this operation have increased due to these reasons.

Voltage Control (Reactive Power)
All licensed power plants connected to transmission and distribution system shall participate
in reactive power control between 0.85 power factor (over-excited operation) and 0.95 power
factor (under-excited operation). Regulation of this factor is possible through Automatic
Voltage Regulators or by instruction of transmission or distribution system operator.
Wind/Solar farms are allowed to work in any point of the range stated (0.85-0.95). Reactive
power needs shall be determined by ELE for each region.
4.1.5.
LOAD SHEDDING MECHANISMS
Finally, under a smart grid framework Instantaneous Demand Control – Load Shedding can be
implemented to control under-frequency situation in the electric system. NLDC may tender out the
provision of services related to disconnection of consumer plants in the transmission system (loads to
the electric system). Any consumer connected to the transmission system and whose consumption
exceeds the threshold indicated in the call for tender may participate in the provision of Load
Shedding services to the operator.
Consumers participating in these tenders agree with NLDC to be disconnected of the electric grid in
case of under-frequency problems. Disconnection is performed by means of “Instantaneous Demand
Control Relays”; this equipment gives the opening instruction to the breakers that will effectively
disconnect in real time the consumer facility or facilities from the grid.
Capacity and price for this service is stated in each agreement between NLDC and the consumer. The
capacity or power volume the facility is offering for the load-shedding mechanism is called
“Instantaneous Demand Control Reserve”. The disconnection lasts for 15 minutes at most; the
reconnection is done after approval of NLDC.
Also the wind or solar generators shall participate in the energy balance and in the case that all other
control means are already used, the generation rejection will contribute to recover acceptable values
of frequency or international interchanges.
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4.1.6.
SUMMARY OF THE ACTIVITIES IN THE PROGRAM:
The following list summarizes the list of activities and the priorities to be included in the Smart
System Operation Subprogram:
Item
Description
Priority
1
Automation of the Grid
High
2
Improvement of existing EMS system
High
3
Integration of RES into the system
3.1
Development of RES Software Integration Tools
Medium
3.2
Development of a RES Control Center
Low
4
Development of Advanced Ancillary services
Medium
5
Development of Load Shedding Mechanisms
Medium
4.2. SMART DISTRIBUTION NETWORK SUB-PROGRAM
The distribution network also faces important challenges in the future. As the most extended network
in any electricity system, its operation highly affects the final Performance Standards. In that sense
the Distribution System Operator (DSO) are usually requested to implement distributed intelligence.
Likewise, the DSO will find a number of changes for which it must adapt its management to match
with the new sector’s targets. A reorganization of the structure shall be also needed therefore.
As part of the control of the implementation of Smart Grids, the distribution companies have an
important role in terms of the balancing and efficiency of the whole system and to manage the
embedded generation in the Distribution Network.
In particular, distribution companies need to focus on the following aspects:
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4.2.1.
OPTIMIZATION OF THE ENERGY FLOW
It is a Distribution companies’ responsibility to reorganize the network’s layout in real time in order
to:



Reduce losses;
Control voltage;
Increase the network reliability.
Modern DMS are capable of providing the operators of the Distribution Networks enough information
to rearrange the network in order to optimize the energy flow according to the expected generation
profile. The operator can accordingly make the necessary arrangements in the grid. The grid (and the
targets) shall be as dynamic as the remote control capabilities and meshing degree of the distribution
network.
Full implementation of this kind of software requires the following modules:



SCADA;
Assets database with GPS positioning;
DMS
On the hardware side, the DisCos shall need the following:



Meshing the grid with the creation of necessary loops;
Remote control facilities in substations and control points in the lines;
Development of communications.
International experience shows that the remote control of facilities can be fairly done by automatizing
100% of HV/MV assets (substations and feeders) and between 20% and 30% of MV/LV assets.
In fact, Exhibit XX below shows that the 50% of the data is enough for controlling and modelling 90%
of the grid.
Therefore, considering that HV/MV was covered in section 4.1.1 above, the deployment of remote
control in distribution must cover 20% of the 240,000 Distribution Transformers/Centers installed in
the country meaning 48,000 Distribution Transformers.
What data do I need, e.g. for network analysis?
2
Result of
grid calculation
100%
90%
50%
100 %
Data volume and depth
RWE Rhein-Ruhr Netzservice 02.04.2010
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Last researches are pointing to a self-healing mechanism in the distribution networks as part of
profiting the benefits of the Smart Grids. The objective is to provide small portions of the network
with local intelligence so that those areas reorganize internally based on specific targets for losses,
voltage drops, feeders’ load, etc sent from the central SCADA.
This is still experimental and no major deployments have been done yet. In any case, it must be
inserted in the roadmap as a low priority so that it can be included in the mature phase of the
roadmap.
4.2.2.
PROVISION OF INFORMATION TO THE TSO
NLDC have access points to the discos where all energy is transmitted for its further distribution.
Distribution networks shall have not only the traditional demand from the customers but now they
shall be also receiving the injection of RES plants (solar or wind) that are non-manageable from the
point of view of the availability of the production. NLDC has access to some of the RES facilities but
there is a number of other facilities that have no direct communication with the System Operator.
In this way, the Distribution companies need to provide daily forecasting of the following parameters
separately:


Demand forecasting for the following period: this must be done as per the normal procedures
in Slovenia.
Production forecasting for the embedded RES plants: in general terms there is two
alternatives to produce this information:
a) The Distribution company will request the RES plants to provide it’s day ahead
forecasting. This option can be cumbersome for small solar plants and may generate
conflicts and may reduce the interest in the development of RES. International
experience in Spain has solved the problem in the following way:

Small plants (below 100kW) are out of this scheme and follow the above
methodology where the disco undertakes the role for the forecasting.

Medium size plants (100 – 1MW) are requested to associate under a ‘trader’ that
is the one in charge of preparing the forecasting for the whole group (this plants
can also decide preparing the forecasting themselves).

Large size plants (above 1MW) are requested to provide the forecasting
themselves.
In any case, the Distribution Company usually checks the inputs with a similar
methodology integrating the RES generation in one or more forecast.
b) Based on the information provided by the meters and the meteorological conditions
forecast, the distribution company will prepare estimation for the following periods
(day ahead or shorter), as required by NLDC procedures. Inputs from the
meteorological institution in Slovenia will be crucial for the estimation of this
production.
4.2.3.
REORGANIZATION
Current PC’s structures respond to the current (and present for the last decades) understanding of
the electricity business. However, the introduction of the modern technologies shall represent a major
change into the normal operation of the companies and therefore it must be reflected in the
organization. In this way, the major changes expected would be the following:



Data shall be flowing into the company from the different sensors installed in the field (smart
meters, automated substations and lines, etc) so the company shall pivot on the analysis of
the acquired information in order to do analytichs and make decisions (please see Exhibit 1).
Customers are no longer passive receptive actors but now they shall constitute active actors
in the system for several reasons, namely:
o They shall participate in the peak demand control and energy efficiency
o They may participate in the generation sector by means of distributed generation
plants.
Finally, a new assortment of new services shall transform the single-product passive customer
into a multi-product active customer.
For all the above, the reorganization of the companies is included with a medium priority as it must
be undertaken when the degree of implementation is relevant enough.
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4.2.4.
SUMMARY OF THE ACTIVITIES IN THE PROGRAM:
The following list summarizes the list of activities and the priorities to be included in the Smart
Distribution Network Subprogram:
Item
Description
Priority
1
Optimization of the Network’s Layout
1.1
SCADA implementation
High
1.2
GIS Implementation
Medium
1.3
DMS Implementation
High
1.4
Meshing of the network
Medium to Low
1.5
Automation of 20% of distribution Centres
Medium
2
Coordination of information about RES with NDPL
Medium
3
Reorganization of the companies
Low
4.3. SMART METERING SUB-PROGRAM
The Smart Metering Sub-Program shall include the installation of meters for energy audit and demand
control as well as the development and implementation of the necessary systems to withdraw and
process the information.
4.3.1.
ENERGY AUDIT GENERAL CONCEPT
Remote metering implementation must result in a change of mind within the company energy audit
operations. Problems matching energy going inside the network against energy supplied to the
customers may be easily solved now. According to the new information provided by the system, the
company traditional field operations and monitoring must restructure according to the electrical areas
covered by the network. In this way, each substation and each feeder in the grid will become an
independent electricity provider that must have a manager responsible for the annual targets of
energy losses, collection, and operational costs. The system must be implemented to ensure accurate
information to the managers in order to help to obtain the results.
Therefore, each feeder/substation will become an energy area within the company and will result in a
four level energy balance that will ensure the losses and collection through accurate on line
operational monitoring. In this way, the four levels will be as follows:
Level 1: HV-MV/MV Substations control
This is the high level energy monitoring at a company. The implementation of this control is
mandatory in order to determine loads and potential energy leakages in the grid.
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Exhibit 6 Level 1 Energy Areas Control
HV
MV
Cons 1
Auditing Meter
Consumer's Meter
LV Cons 1
Cons 2
Cons 3
Cons …
Cons n
Level 2: Feeder Control
The second level involves the balance within a MV energy feeder in a substation. It includes the MV
feeder in the substation and all elements connected at MV level (i.e. MV/MV and MV/LV substations
and MV customers). This level may become the management lowest level in the company involving a
large energy balance of all MV and LV customers.
Exhibit 7 Level 2 Energy Areas Control
HV
MV
Cons 1
Auditing Meter
Consumer's Meter
LV Cons 1
Cons 2
Cons 3
Cons …
Cons n
Level 3: LV Substations Control
This is the lowest control level where accurate and geographically precise energy balance is made.
This information will be the most important for final losses detection as it involves little amount of
consumers that may be easily reviewed searching for energy irregular registration.
Exhibit 8 Level 3 Energy Areas Control
HV
MV
Cons 1
Auditing Meter
Consumer's Meter
LV Cons 1
Cons 2
Cons 3
Cons …
Cons n
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Level 4: Meter Events Control
Electronic meters have the capacity to register and later inform of much of the electricity events that
happen around them regarding potential irregular energy balance. In this way, the lowest level to
inform and perform a balance will be the meter itself. Additionally, the meter will provide information
to perform all the above mentioned balances as mandatory information.
It is obvious that the profitability of the whole system involves that the whole elements in the chain is
remotely monitored at the same time. Lacking of some of the elements in the chain will result in
useless investment since there will not possible to perform the balance properly. The result will be an
electrically vertical integrated system that can monitor accurately all the energy entering and being
supplied in the network.
Some exceptions, however, in terms of implementation of remote metering in some elements of the
grid may appear. In this way, remote metering of HV substations and large customers connected at
MV level may be reasonable due to the large amount of energy under control by that implementation.
a)
Criteria Definition
The Consultant proposes the following criteria for the deployment of smart meters.
a.1)
HV/MV Substations and large customers (Levels 1 & 2)
Substations HV/MV was covered in section 4.1 above. This section nevertheless will include them for
high accuracy metering purposes. Large customers connected at MV are the following most important
control points in a distribution utility. They must therefore be therefore high priority in this subprogram. On one hand, substations energy registering will determine how much energy is necessary
to be paid to generators. In this way, all level 1 meters (boundaries in the company) must implement
remote metering technology to have accurate periodical control of the energy flowing through the
company. MV feeders will provide substations energy balance and first approach to electrically
integrated areas. Thus, MV in feeders should be remote metered only when it is part of a level 2 and
3 area.
On the other hand, a large percentage of the energy is usually supplied to a few consumers
connected at MV level. Thus, they are key elements for preserving and controlling present and future
revenues. In this way, The Consultant proposes to have 100% of these points under constant control
by means of remote metering technology.
The technology to implement proposed is in both cases (due to great geographical dispersion) an
independent communications path (GSM/GPRS, radio, or similar)3 connected directly to the meter in
large customers or set of meters in the substation. Meters must be capable of registering all the
information for long time and will include the modem to connect the meter with the system.
Unit costs will be calculated according to the equipment required per installation. In this way:





Meter
Current and Voltage transformers
Meter Box
Modem
Installation costs (including, among others, signal cables, location preparation, etc)
a.2)
MV/LV Substations (Level 3)
As mentioned above, MV/LV Substations remote metering installations will be useful only when all
customers below the transformers are also using the same technology. Implementing to all the
substations in the company without a clear feedback from the customers’ meters will result in a
useless huge investment (including the increase in operational expenditures due to communications
costs for the whole network). In this way, The Consultant proposes to install remote metering
equipment only in the substations where level 3 monitoring is to be implemented.
The installation will receive all the information from the customers connected through PLC system. It
will be recorded in a concentrator and transmitted to the system through an independent
communication path (GSM/GPRS, radio, or similar).
3
In some cases, the company may prefer using the SCADA communications path instead of an independent one.
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Unit costs will be calculated according to the equipment required per installation. In this way:







Meter
Current transformers (It is estimated that all of them are to be replaced at this level)
Meter Box
Modem
Concentrator
Public Lightning meter
Installation costs (including, among others, signal cables, location preparation, etc)
a.3)
Residential & LV Customers (Level 4)
This segment involves all the meters below the MV/LV transformer. It involves, therefore, customers
with indirect metering set, three phase direct meters, and single-phase direct meters. This is the
largest amount of meters in the company by far and required, in this way, an accurate definition of
the technology to implement in order to determine the optimal trade-off between technical and
economical solution. The efficient solution will involve weighing potential risks with their probability to
determine how costly our solution has to be.
In order to make the system reliable, it is a key issue to prevent the meter and the whole metering
installation to be manipulated by any non-authorized person. In this way, the meters must be in a
public area or, at least be installed in a way that not allow manipulating it easily.
Meters can be selected with connection/disconnection facilities or without them. Meter’s costs
differences are about 10% less4 when the breaker is not installed within the meter. It is advisable
installing this technology in all meters in order to keep real control of the performance (valid for DSM
purposes) and reduce potential need for extra visits to the customer. However, The Consultant also
advises that the operation of this meters must be carefully determine in a clear procedure to avoid
any problem (either from software or from manual operation) that may result in mass disconnection
of customers.
Quite the opposite, LV indirect meters lack of any disconnection capabilities unless the installation
becomes much more expensive5. Due to the quantity of meters to be implemented and the cost of the
required tele-controlled breaker (5,000€/each approx.) of them, The Consultant proposes not to
install them with connection/disconnection facilities and operate them in the traditional way (using
the information provided by the new system).
Indirect meters are estimated to be 1% of the customers according to the data provided. This
quantity must be considered inside the cost calculation estimation. Additionally, EPS considers only
replace current transformers when it is necessary after making the proper revision of them. The
Consultant estimates, according to the international experience during the implementation of massive
remote metering equipment, that 50% of existing current transformers may need to be replaced.
Communications set proposed in here is PLC from the meter up to the level 3 node (detail definition
must be provided by the implementer). The concentrator will deliver all the information from there to
the system. Also GPRS can be an option whenever the prices are competitive. Please note that
periodical service charge of the communications providers make this latter technology very
expensive.
4.3.2.
RECOMMENDATIONS
FOR
MIS
(MANAGEMENT
INFORMATION
SYSTEM)
INTEGRATION
Implementation of a full Automatic Metering Management requires dealing with loads of information
accurately registered and available on line. MIS (Management Information Systems) must process the
information automatically by the to avoid mistakes and to provide quick response to both the
company and the customers.
This section will provide recommendations about how to organize and integrate the remote metering
capabilities with the existing systems.
4
According to International suppliers’ prices.
5
An external tele-controlled circuit breaker would be necessary.
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a)
System scheme proposal
According to the main objectives of the project of accuracy, economy, and interoperability, the
system scheme definition must meet the following criterion:

It must be capable of reading remotely all kind of meters implemented in the network.

It must be capable of connect and disconnect all the meters remotely.

All communications paths must be allowed.

It will replace the meters firmware whenever it is needed.

It must allow manual meter reading when necessary.

It must be capable of read and record all the events defined and register in the meters
firmware.

It must be capable of delivering and receiving information and orders from the billing system
in the DisCo.
Therefore, the scheme shown in Exhibit 10 integrates all the needs listed above considering the
following items:

Remote metering reading platform must be a multiprotocol platform6. This system will be able
to read all the meters in the network independently of the meter’s brand. Meters’
communications protocols must be shared with the software manufacturer in order to
integrate them in the system. The software will read both indexes and events registered in
the meters. If a defined communications’ protocol DLMS is properly defined by the PCs there
should not be any problem at the concentrator level. The implementation of this software will
also allow (if meters are technically capable) integrating the existing remote meters from the
past pilots, what represent integrate the whole company under a unique system scheme.

Remote meter management platform for all meters will be difficult to find. In this way,
independent software for every meter’s brand shall be installed in the system and connected
to the communications’ network. Note also that this software mostly send orders to the
meters. Protocols for those actions are mostly very particular in each meter manufacturer.
So, it can represent a problem when delivering orders to a meter through an else brand
concentrator. The company may find that instructions are not properly deliver to the meter by
the concentrator. In this way, the communications’ protocol must be clearly defined to allow
connect to the meter through the concentrator even if both are from different manufacturers 7.

Measurement Data Base will be installed to record all the data and send it to the billing
system orderly. This software will also allow the PCs to prepare reports about energy balances
at the four level mentioned.

Interfaces with billing system8 must be developed locally as all DisCos own a different
proprietary billing system. These interfaces shall allow sharing the information and orders in
order to perform the whole chain automatically. Description of the integration’s requirement is
provided in the next section.
There are different multiprotocol platform solutions in the market. As an example it can be mentioned solutions
from PrimeStone and Itron widely applied in North and Latin America.
6
7
Prime Allianz led by Iberdrola has provided a free communications standard protocol fro AMM systems.
8
Note that this Billings system may be integrated as a module in a wider CC&B platform.
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Exhibit 9 Systems Scheme Proposal
- Meters Indexes and Events.
- Meters Inventory
Billing
System
- Meters Inventory reporting.
- Connection/Disconnection Orders.
- Revision of Meters' situation.
Readings
Data Base
Remote
Management
Platform
Remote
Reading
Platform
ENERGY
BALANCES
COMMUNICATIONS NETWORK
GSM/GPRS
Meters
Concentrators
PLC Meters
Once data is available in both billing system and Readings Data base, it can be transferred to other
software applications through ad-hoc interfaces. The Consultant advises to perform in that way in
order to avoid any legal or regulatory risk due to orders and/or data mismanagement.
b)
System requirements for integration
According to the billing systems implemented in the companies, a local software developer 9 was
contacted in order to assess the feasibility and costs of developing the interfaces to integrate the
remote metering system with the local billing system. The Consultant found a positive answer and
requested the basic items that the interfaces must include. In this way:




Data transfer from remote metering system to the billing system
Preparation of commands for disconnection of users
Automatic generation of commands for connection of users
Updating (connection of data about meters with consumers, replacing of meters, failures, new
customers etc...)
The quality of the system software and hardware shown during the visit (oracle based system with
independent server and a carefully tailor made software), The Consultant thinks that the integration
can be developed locally ensuring the integration of all systems in the project.
c)
Software & Hardware Costs
System costs estimation (Hardware & Software) will be as follows:
9
DIGIT. Billing System Developer for Centar DisCo
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Table 1 Systems Costs
Item
Multiprotocol Remote Meter Reading Platform
Oracle Data Base
Remote Meter Management Platform
Server
Communcations facilities
Interfaces
Implementation
Total
Qty
5
5
5
5
5
5
1
Unit Price
400.000 €
50.000 €
20.000 €
5.000 €
100.000 €
40.000 €
200.000 €
Total Costs
2.000.000 €
250.000 €
100.000 €
25.000 €
500.000 €
200.000 €
200.000 €
3.275.000 €
Costs have been calculated according to international remote metering software and hardware for
companies around 3 million customers. It was also taken into account prices for local interfaces
development.
4.3.1.
SUMMARY OF THE ACTIVITIES IN THE PROGRAM:
The following list summarizes the list of activities and the priorities to be included in the Smart
Metering Subprogram:
Item
Description
Priority
1
Smart Meters in Large Customers
High
2
Smart meters in MV Substations
Medium
3
Smart Meters in Residential customers
Medium (in areas with high
density or unit consumption) to
Low (the remaining areas)
4
Systems for data analysis
High (for data acquisition and
monitoring of large customers)
to Medium (for residential
customers)
4.4. SMART CUSTOMERS SUB-PROGRAM
Customers are the final link in the energy change. They are the final objective and target as
recipients of all the outputs of the remaining actors in the chain. During many years, the role of the
consumer was merely receptive with low to no involvement in the performance of the sector but to
claim for results. However, the new technologies and in particular the smart grids allow the
customers to become an active actor to participate in the future development of the sector.
In this way, the clients shall have the possibility and or obligation to participate in programs for
energy efficiency and demand side management. Additionally, aspects like new services (electric
vehicles, intelligent consumption, etc) shall also be possible.
4.4.1.
DEMAND SIDE MANAGEMENT
The possibilities in the field of demand side management mostly relate to the management of the
peak demand in Vietnam. Increase of peak demand during the year represents a huge investment for
the country in order to match that demand with available capacity. If demand is constant and
consistent, then the best value for the money is achieved with the investment. However, if the
demand is not permanent but transient, then the cost of the new plan shall be distributed among the
exising consumption with an average increase of the energy unit costs.
An assessment of the demand profiles of Vietnam (see Exhibit 10 Exhibit 11) suggests that there are
two areas where there is room for improvement, namely:

There are non-permanent peaks in July and December 2011 (also in February 2010) that
could have been avoided with modern smart grids technology and the involvement of the
customers.
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
There is a tiny room for improvement within the day for the peak is reached both in the
morning and in the evening. However, central time during the day is less intense in energy
use. In this way, a shift of part of the consumption would definitely reduce the final total
peak.
17000
16000
15000
MWh Peak
14000
13000
2010
12000
2011
11000
10000
30/12
16/12
02/12
18/11
04/11
21/10
07/10
23/09
09/09
26/08
12/08
29/07
15/07
01/07
17/06
03/06
20/05
06/05
22/04
08/04
25/03
11/03
26/02
12/02
29/01
15/01
8000
01/01
9000
Exhibit 10 Daily Peak in Vietnam
16000
14000
12000
MWh Peak
10000
2010 - Non-Rainy
8000
2010 - Rainy
2011 - Non-Rainy
6000
2011 - Rainy
4000
2000
0
0
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
Hours
Exhibit 11 Typical Average Daily Profiles in Vietnam
The two most common methodologies provided by the Smart Grids to participate in the demand side
management is the real time tariffs (as an upgrade of the past TOU) and or the load shedding
extended to all customers.
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a)
Real Time Dynamic Tariffs
Real time dynamic tariffs schedule is a sophisticated methodology that is available thanks to the new
capabilities of the smart meters. Bidirectional communications allow the retailers/distributors to send
the information to the meters in order to adapt the cost of the consumption to the present conditions
in the market and congestions in the network. This is an incipient methodology that is being
implemented in United States and that will be extended to all other places where smart meters have
been deployed and there is a need for demand side management.
Proper managmetn of the real time tariffs (even combined with the current TOU) definitely flattens
the demand daily profile representing a huge benefit for the country.
b)
Load Shedding
Traditionally, load shedding was applied only to large customers. However, new technologies in smart
meters and distribution control allow extending this possibility to any customers in the grid. The
principle is simple. Whenever there is a extra demand that cannot be matched by the generation, the
client accepts (with an economical compensation) to have its energy supply cut off with a warning of
one hour in advanced.
This possibility definitely helps to reduce the undesirable peaks and so the need for additional nonrequired power plants.
4.4.2.
SMART NEW APPLICATIONS: ELECTRIC VEHICLE, INTELLIGENT CONSUMPTION
Finally, new applications for electric vehicle and intelligent consumption shall be developed in the long
future as part of the new set of services that shall be provided by this kind of technologies.
4.4.3.
SUMMARY OF THE ACTIVITIES IN THE PROGRAM:
The following list summarizes the list of activities and the priorities to be included in the Smart
Customers Subprogram:
Item
Description
Priority
1
Demand Side Management
1.1
TOU Tariffs
High
1.2
Real Time Dynamic Tariffs
Low
1.3
Load Shedding Large customers
High
1.4
Load Shedding rest of the customers
Medium to Low (along with the
implementation of the smart
metering subprogram)
2
New Services and facilities
Low
4.5. TRANSVERSAL SUB-PROGRAMS
4.5.1.
a)
SOCIAL FRIENDLY APPROACH
Dissemination Plan
As mentioned above, the present program’s success needs the involvement of the society. In this
sense, the present program shall include a dissemination plan from the beginning for all the activities.
The plan needs to be sponsored by the MoIT with the direct involvement of the different stakeholders
(ERAV, PCs, NLDC, NPT, etc). The plan shall include, but not limited, the following aspects:

Dissemination of the strategic approach for Smart Grids in Vietnam
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


Consultation papers by the stakeholders before the implementation of the subprograms with
the technical solution proposed, affections for customers, and monetary costs and benefits so
that feedbacks and or comments may be issued.
Information of the implementation progress for the programs launched
Capacity building (mass or specific) for the customers to understand the technology and
exploit its potentials.
The methodology used will be defined specifically for each campaign and must be adapted to each
stakeholder’s segment it is addressed to.
b)
Installation Code of Practice
Any of the subprograms, and in particular those related to distribution network, smart meters and
smart customers, require a massive presence on the field for introducing the necessary changes in
the network in order to adapt it to the smart grids. This massive presence requires that the
implementers of the different programs follow a strict a code of practice to avoid any conflict with the
clients and with the society in particular.
The regulator (ERAV) with the valuable collaboration and coordination of the implementers (PCs, NPT,
NLDC, etc) should develop the code including, but not limited, the following topics:



Pre-Installation
o Training/Accreditation
o Customers Communications
o Appointments
Installation
o Responsible, courteous at visit
o Explanation of Smart Meters
Post installation
o Customer follow up
o Complaints resolution
c)
Motivational Campaign
As mentioned above, customers’ participation is crucial for the success of the different programs.
However, the customers usually are little motivated for participating in this kind of programs. That’s a
constraint! Typical motivation for customers may be of two kinds: Rational or Emotional. Rational
regards to the objective benefits for the customer with the implementation of smart grids whereas
emotional regards to the perception of the customers of the use of the electricity.
Due to the weight of electricity cost over the total family incomes, the experience shows that the
campaigns must be focused on the emotional side to be successful.
In this way, the MoIT shall develop a motivational campaign in order to mobilize the population to
participate actively in the benefits of the smart grids.
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4.5.2.
CYBER-SECURITY
Last but not least the cyber security is a everyday more important aspect to take into account. From
the beginning of the program, a detailed study on these aspects is necessary. The energy sector is a
strategic area within any country. Attacks by means of accessing the different actuators an blocking
the access to electricity may represent a huge danger for Vietnam. In this sense the MoIT must
therefore a comprehensive study including the following aspects:




Identification of Threats
Identification of the list of potential attacks that can be received
Determination of the vulnerabilities (consequences of the attack); and finally,
Define the proper actuations and preventions to avoid the risks.
The Process
Extor
①Threats must be identified (who):
> Terrorists
> Former Empoyees
> Organised Crime
Organised cr
Motivation
Funding
Resources
Petty t
Terror
②Then, list of attacks (how)
>
>
>
>
>
Break meter
Turn contactor on
Turn contactor off
Change tariffs
Change f/w
Hack
Equipment / Tools
Expertise / Skill
Knowledge
By-pas
Magn
③Then, list the vulnerabilities (what)
>
>
>
>
Meter can be broken
Contactor can be turned on/off
Tariffs table can be altered
Firmware can be downloaded
STOP
Virus/Trojan/Root
Comms b
Exhibit 12 Itron analysis of Cyber Risks
4.5.1.
SUMMARY OF THE ACTIVITIES IN THE PROGRAM:
The following list summarizes the list of activities and the priorities to be included in the Transversal
Sub-Programs:
Item
Description
Priority
1
Disemination Plan
High
2
Installation Code of Practice
High
3
Motivational Campaign
Medium
4
Cyber security analysis and recommendations
High
5. COST – BENEFIT ANALYSIS
Proposals that require a government decision are, among other things, usually justified by an analysis
of the net societal benefit of various options. A cost-benefit analysis is a mature and well developed
economic tool that helps to assess the relative economic merits of a proposal.
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If the expected monetary value of the benefits exceeds the anticipated costs, there is a net economic
benefit, as long as the project team identifies and manages risks that could negate the benefits.
There have been a number of national and Victorian studies that have focused on the economic case
for the Advanced Metering Infrastructure (AMI) project.
The definition of “performance indicators” quantifying the extent to which a specific smart grid project
is contributing to progress toward the “ideal smart grid”10. This output reveals to what extent a
project or deployment achieves the following smart grid services (characteristics) as defined by EC
expert group 1:






Integration of new users and requirements for sustainability,
Consumer inclusion,
Improving market functioning and consumer service,
Enhancing efficiency in day to day grid operation,
Enhancing better planning of future investments, and
Ensuring network security / control / quality of supply
An assessment framework to qualitatively capture the impact of a smart grid project on the
considered electricity system (in terms of the delivery of smart grid services) is recognised as an
important feature, but is beyond the scope of this paper. However, the authors recognise the
importance of such a framework and the complementary value it can bring to the quantitative results
of a cost-benefit analysis (CBA).
A “Cost and Benefit analysis” assessing the profitability of a smart grid solution and associated
investment. An essential outcome of this analysis is the identification of the specific beneficiaries.
Benefits from smart grid investments accrue throughout the value chain from generators, suppliers
and customers to society as a whole.
This is why economic regulation defining the conditions for the so-called socialisation of a major part
of the investments is key for the successful implementation of smart grids. Too narrow a view when
evaluating the cost efficiency of smart grid investments – to be undertaken mainly by DSOs – should
be avoided.
This paper aims to outline the first step towards the effective attribution of costs and benefits,
necessary to the development of a successful market-based approach to govern the evolution of
smart grids and achieve all related strategic policy goals.
The objective is to define the methodological approach for conducting such cost-benefit analyses of
smart grid projects. Moreover, it provides project leaders with guidance in establishing a broad
approach in their cost-benefit analyses for smart grids, taking indirect benefits and social factors into
consideration.
In the context of this analysis, a ‘benefit’ is an impact (of a smart grid project) that is of value to any
regulated or commercial body, energy consuming households or society at large. To gauge their
magnitude and facilitate comparison, benefits should be quantified and expressed in monetary terms.
For smart grid systems, it is well accepted that there are four fundamental categories of benefits11:

Economic – reduced costs, or increased production at the same cost, that result from
improved utility system efficiency and asset utilisation;

Reliability and Power Quality – reduction in interruptions, service quality assistance
improvement and power quality events;

Environmental – reduced impact of climate change and effects on human health and
ecosystems due to pollution;

Security and Safety – improved energy security (i.e. reduced oil and gas dependence);
increased cyber security and reductions in injuries, loss of life and property damage.
Within each of the broad categories, there are several types of benefit and by definition they are
mutually exclusive in terms of accounting for different benefit categories. However, smart grid
functionalities that lead to one type of benefit can also lead to other types of benefits. For example,
improvements that reduce distribution losses (an economic benefit) mean that pollutant emissions
are reduced as well (which is an environmental benefit).
10
Important to note is that such a measurement towards the “Ideal Grid” for a specific country should be seen as
the relative and not absolute improvement. Moreover the consecutive order of functionality will not follow the
same path throughout Europe; there will be "jumps".
11
EPRI (Electric Power Research Institute) (Faruqui, A., Hledik, R.) (2010). Methodological Approach for Estimating
the Benefits and Costs of smart grid Demonstration Projects, Palo Alto, CA: EPRI. 1020342
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Having identified the achieved benefits, it is very important to identify the beneficiaries in the
process. In general, benefits are reductions in costs and damages, whether to generators, distribution
system operators, consumers or to society at large. In this evaluation process the various benefits
are defined so as to avoid instances of transfer payments between these groups of beneficiaries, to
avoid mistakes in the evaluation of the total benefits, and to illustrate benefits from the separate
perspectives of each group.
Broadly speaking the beneficiaries are the following:



Consumers: Consumers can balance or reduce their energy consumption with the real-time
supply of energy. Variable pricing will provide consumer incentives to install their own inhome infrastructure that supports the smart grid development. The smart grid information
and communication infrastructure will support additional services not available today.
Utilities (generators, transmission system operators, distribution system operators and
suppliers): Utilities can provide more reliable energy, particularly during challenging
emergency conditions, while managing their costs more effectively through efficiency and
information which can be used for more effective infrastructure development, maintenance
and operation.
Society: Society benefits from more reliable supplies and consistent power quality for both
domestic customers and all industrial sectors – manufacturing, services, ICT – many of which
are sensitive to power outages. Renewable energy, increased demand efficiency, and electric
vehicles or other distributed storage support will reduce environmental costs, including
society’s carbon footprint.
A benefit to any one of these stakeholders can in turn benefit the others. For example, those benefits
that reduce costs for a DSO could lower prices, or prevent price increases, for customers. However in
such cases it is vital to ensure that benefits transferred from one party to another are not double
counted. Lower costs and decreased infrastructure requirements enhance the value of electricity to
consumers. Reduced costs increase economic activity which benefits society. Societal benefits of the
smart grid can be indirect and hard to quantify, but cannot be overlooked.
5.1. DESCRIPTION OF COSTS (EU APPROACH)
Over the past few years, there have been various models and constructs put forth related to
evaluating smart grid projects and related investments. The lack of a standard, commonly accepted
operator-level cost-benefit framework or system has led to few effective investment analysis
approaches. However, DSO executives and policy decision makers are in need of such a framework.
Smart grid project investment analysis is particularly difficult because it

involves a large number of technologies, programmes and operational practices;

impacts on all the operational areas of the electricity value chain in an interlinked way
(transfer of costs and benefits);

requires long-term vision12 and commitment to fully implement;

assumes active involvement of customers in using new technologies and software, the
reliability and extent of which is still highly uncertain.
Moreover, variation among European DSOs in existing grid infrastructure (e.g. current
communications and metering systems, network age and condition) or service area characteristics
(e.g. customer geographic density and consumer end-use loads) – even within a single country – is
so great that decision makers so far could not rely on existing studies from other regions or DSOs to
justify smart grid investments.
From an economic point of view, certain challenges arise when attempting to apply traditional costbenefit analysis in the context of smart grid investments. Evaluating smart grid project investments
can be different from traditional investment analyses:

All benefits related to smart grid investments may not be borne by the investing party and
some additional costs required to realise a benefit may be borne by other parties. Should
these additional costs and benefits be incorporated into the analysis? If so, how will all costs
and benefits be attributed to the appropriate parties, in modelling and analysis?

Uncertainty with respect to the magnitude of benefit streams is not unique to smart grids.
However, some potential metrics associated with smart grids present particularly difficult
issues for accurate quantification (e.g. environmental impact, reliable levels of response). The
12
In ’10 Steps to Smart Grids – EURELCTRIC DSOs’ Ten-Year Roadmap for Smart Grid Deployment in the EU’, EURELECTRIC
DSOs outline the 10 steps that are required for implementing smart grids in Europe.
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rationale and assumptions made for some chosen parameters can greatly affect the outcome
of the analysis.
The logical flow of the developed methodological framework is shown in the figure below, which
outlines the proposed process for identifying benefits and estimating their monetary value. The final
methodology foresees seven building blocks:
Figure 1 Cost-Benefit Analysis Framework. Font: EURELECTRIC
In the EU approach there is a Cost‐benefit analysis (or “CBA”): A seven‐step CBA, and a minimum of
two forecast scenarios (“business as usual” and one other), are recommended. In addition, timely
consultation with local promoters and regulatory authorities, to ensure that all the appropriate
communication infrastructure technologies, architectures and measures needed to guarantee
interoperability and compliance with the EU’s available or international standards and best practices
are taken into consideration, and the assumptions underpinning the analysis are adapted to local
circumstances.
STEP 1 – Describe the technologies, elements and goals of the project
The initial step in estimating the benefits of a project is to describe it by identifying the goal of the
project and the smart grid assets.
a) Goal
As a first step it is important to describe the high-level goals of the overall solution and how the
installed components will allow the objectives of the project to be addressed. It should be clear who
the stakeholders are and how their needs are addressed.
b) Smart grid assets
Smart grid assets consist of the technologies, devices, and equipment that are purchased, installed,
and made operational for the smart grid project. Assets could include, for example, in-home displays,
load control devices, voltage control devices, a communications network and associated
infrastructure, cyber security upgrades, enhanced fault detection technology or advanced metering
infrastructure.
It is important to identify what specific assets are installed, where they are installed, how the system
is affected and what they do.
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Furthermore, assets can include energy resources that interact with the grid, including distributed
generation, stationary electricity storage, plug-in electric vehicles, and smart
appliances. These resources can generally communicate and make business decisions or receive
commands based on signals from the grid, customers or other operators like retailers, using either
integrated technology or other assets of the project.
Each of the deployed assets will produce a unique list of possible functionalities. Detailed fact sheets
of the installed products can also help to define those functionalities and illustrate their role in the
project.
STEP 2 – Identify the smart grid functionalities
Once identified, these assets can be integrated to enhance the delivery and use of electricity by
enabling smart grid functionalities. Functionalities describe the enhanced capabilities provided by
smart grid assets for delivering electricity across the grid from power plants to consumers.
Expert Group 1 (EG1) of the EC Smart Grid Task Force has defined the smart grid in terms of six
high-level characteristics (referred to in 1.2 above) that are delivered through 33 specific network
functionalities.
a) Enabling the network to integrate users with new requirements
1.
2.
3.
4.
Facilitate connections at all voltages / locations for any kind of devices
Facilitate the use of the grid for the users at all voltages/locations
Use of network control systems for network purposes
Update network performance data on continuity of supply and voltage quality
b) Enhancing efficiency in day-to-day grid operation
5.
6.
7.
8.
9.
10.
Automated fault identification / grid reconfiguration reducing outage times
Enhance monitoring and control of power flows and voltages
Enhance monitoring and observability of grids down to low voltage levels
Improve monitoring of network assets
Identification of technical and non technical losses by power flow analysis
Frequent information exchange on actual active/reactive generation/consumption
c) Ensuring network security, system control and quality of supply
11.
12.
13.
14.
15.
16.
Allow grid users and aggregators to participate in ancillary services market
Improved operation schemes for voltage/current control taking into account ancillary services
Intermittent sources of generation to contribute to system security
System security assessment and management of remedies
Monitoring of safety particularly in public areas
Solutions for demand response for system security in required time
d) Better planning of future network investment
17. Better models of DG, storage, flexible loads, ancillary services
18. Improve asset management and replacement strategies
19. Additional information on grid quality and consumption by metering for planning
e) Improving market functioning and customer service
20.
21.
22.
23.
24.
25.
26.
27.
Participation of all connected generators in the electricity market
Participation of VPPs and aggregators in the electricity market
Facilitate consumer participation in the electricity market
Open platform (grid infrastructure) for EV recharge purposes
Improvement to industry systems (for settlement, system balance, scheduling)
Support the adoption of intelligent home / facilities automation and smart devices
Provide to grid users individual advance notice for planned interruptions
Improve customer level reporting in occasion of interruptions
f) Enabling and encouraging stronger and more direct involvement of consumers in
their energy usage and management
28.
29.
30.
31.
32.
33.
Sufficient frequency of meter Reading
Remote management of meters
Consumption/injection data and price signals by different means
Improve energy usage information
Improve information on energy sources
Availability of individual continuity of supply and voltage quality indicators
The functionalities defined by EG1 describe in broad terms the different ways in which smart grid
technology can be used to improve the reliability, efficiency, operation, and security of the electrical
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grid. Depending on which smart grid assets are installed, how they are combined and how they are
operated in a system, different functionalities can be triggered.
STEP 3 – Map each functionality onto a standardised set of benefit types
As assets are mapped to functionalities, functionalities are mapped to benefits. Each of the triggered
functionalities has to be considered to determine if and how they can provide any of the smart grid
benefits.
The general categories of benefits include improved economic performance (such as reduced
operating and maintenance costs), enhanced reliability, reduced emissions and greater energy
security. The EPRI methodology has developed a complete list of four benefit categories comprising
22 specific benefits. This has been adopted as a comprehensive list 13 that is also suitable for use in
Europe:
Optimized Generator Operation (Utilities)
Improved Asset
Utilitzation
Deferred Generation Capacity Investments (Utilities)
Reduced Ancillary Service Cost (Utilities)
Reduced Congestion Cost (Utilities)
Deferred Transmission Capacity Investments (Utilities)
T&D Capital Saving
Deferred Distribution Capacity Investments (Utilities)
Reduced Equipment Failures (Utilities)
Economic
Reduced Distribution Equipment Maintenance Cost (Utilities)
T&D O&M Savings
Reduced Distribution Operation Cost (Utilities)
Reduced Meter Reading Cost (Utilities)
Theft Reduction
Reduced Electricity Theft (Utilities)
Energy Efficiency
Reduced Electricity Losses (Consumer)
Recovered Revenue
Detection of anomalies relating Contracted Power (Utilities)
Electricity Cost Savings
Reduced Electricity Cost (Consumer)
Reduced Sustained Outages (Consumer)
Power Interruptions
Reliability
Reduced Major Outages (Consumer)
Reduced Restoration Cost (Utilities)
Reduced Momentary Outages (Consumer)
Power Quality
Reduced Sags and Swells (Consumer)
Reduced CO2 Emissions (Society)
Environmental
Air Emissions
Reduced Sox, Nox, and PM-10 Emissions (Society)
Reduced Oil Usage (Society)
Security
Energy Security
Reduced Wide-scale Blackouts (Society)
Table 1 List of Benefits
STEP 4 – Establish the project baseline
13
Annex I of the JRC report ‘Guidelines for conducting a cost-benefit analysis of smart grid projects’
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The implementation of a smart grid project incurs costs and delivers benefits that have to be
compared with the scenario had the project not taken place. It is therefore essential for any costbenefit analysis to define and characterise the baseline against which all other aspects of the analysis
are compared.
The baseline encompasses all the quantitative data that is needed to represent the current situation.
Since all cost-benefit analyses are based on measuring or assessing change, two cases are required
to measure the change that is to be assessed. The EPRI methodology puts forward the two types of
states of the system necessary to start the evaluation:

The Business as Usual (BAU) scenario14: the baseline (or control) conditions that reflect
what the system condition would have been without the smart grid system in place

The smart grid scenario: The realised and measured conditions with the smart grid system
installed
The quantification of a specific benefit or cost, as explained in the next step, is then the incremental
change in that cost and benefit metric between BAU and the smart grid scenario.
There might be a number of candidate baselines for each benefit, and the smart grid Project will have
to select the baseline that is viewed as the most representative of the state of the grid had the smart
grid project not been implemented. Important factors that have to be taken into account when
defining the baseline include, inter alia, extreme events15, inflation, demand growth, load growth,
evolution of electricity prices and final date of the project.
STEP 5 – Quantify and monetise the identified benefits and beneficiaries
Quantifying the benefits in this case means “measuring the effects or outcomes that the project will
deliver.” The challenge lies in evaluating these effects in monetised terms. The metrics needed to
monetise the benefits may be quantified in terms of physical units (e.g. reduction in kWh). The
quantified benefits should in turn be monetised by applying a cost per unit (e.g. €/kWh).
Every identified benefit requires an approach and data for the calculation of both the BAU condition
and the smart grid condition. The incremental monetary change between both conditions can in
general be expressed as:
Value (€) = [Condition]BAU – [Condition]SG
a) Externalities - Parameter Values for Monetisation
When calculating benefits, it is clear that some benefits, such as reduced emissions or reduced
damages to end-users from power interruptions, are difficult to monetise. A Project would, for
example, need to estimate the emissions before the project on the electricity generated for the area
under study, and after the smart grid investments are in place. In this respect the choice of the right
parameter values is important.16
On top of that, the project may deliver benefits that cannot be accurately monetised. These benefits
include, inter alia, new services and products offered, vehicle-to-grid services, job creation and new
business opportunities. In general, they benefit the public or society at large. They should not be
overlooked and should be taken, quantitatively or qualitatively, into account in the total smart grid
project assessment.
The following benefits require specific attention:
1. Reliability and power quality benefits
To monetise reliability and power quality benefits, the most common approach is to apply the cost
per un-served kilowatt-hour (or customer hour depending on regulatory framework) from the
interruption-cost estimates. Benefits calculated from this approach are a direct function of the change
in the number of interrupted hours (from what is experienced under a baseline conditions to what is
experienced after smart grid investments are made).
14
The analysis should not be always based on a single BAU scenario; it can be useful to consider a limited number
of options for the BAU scenario.
15
“Extreme events” could not be assumed in modelling a baseline scenario due to their sporadic and
unpredictable nature. However, if an extreme event occurs over the period where the smart grid project was in
operation and measurements were made, this will likely impact on the results of the “Smart Grid Scenario”.
Thus, if possible, the impact of the same event should be built into the BAU scenario. The accuracy of this would
depend on there being historical evidence of how the system has dealt with such events in the past.
16
Annex II of the JRC report offers an approach for quantifying and monetizing smart grid benefits illustrated by
parameters.
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2. Environmental benefits
To the extent that they can be reasonably quantified (and that they can be attributed to thesmart
grid investment), environmental benefits should be quantified, monetised in the costbenefit
framework and designated a societal benefit. In some cases, environmental benefits can be estimated
based on the average cost of installing remediation equipment as an alternative, such as emission
reduction technology. In other cases, there are market instruments from which the benefits can be
readily calculated (e.g. spot and future values of allowances traded in market exchanges).
3. Societal benefits
From an economist’s viewpoint, substantial benefits accrue to consumers and, more interestingly, to
third parties because of positive externalities created from a smart grid implementation. The analysis
should include a unique list of societal benefits and internalise all externalities, thereby understanding
and valuating the community welfare effects.
System operators and regulators should ultimately include benefits with a broader societal impact in
their assessments. Some typical benefits include:

Environmental and health benefits due to decreased peak electricity generation and the
associated release of pollutants into the atmosphere (as peaking capacity is generally carbonintensive rather than renewable).

New industries can develop to deliver a whole new spectrum of products (prepayment,
demand response programmes), energy efficiency applications and new technologies (smart
appliances, storage, etc.). Smart grid projects could leverage innovation in distinct areas like
electric vehicles, renewables, distributed generation and energy efficiency.

Sustained job creation: including direct utility jobs created by smart grid programmes (new
skills, jobs created in the broad “energy services” sector), non-utility smart-grid related jobs
(contractors, technology design, manufacturing, for example in new industry lines like plug-in
electric hybrid vehicles).
b) Beneficiaries
When conducting the analysis, it is of extreme importance to take into consideration the complete
value chain and all the effects that a society experiences from producing and consuming electricity in
the smart grid deployment, and not only the effects on the generators that produce electricity and
their registered consumers who consume electricity. Benefits need to be clearly allocated to their
beneficiaries.
STEP 6 – Quantify and estimate the relevant costs
The relevant costs of a project are those incurred to deploy the project, relative to the
baseline. The complete picture of costs is required to determine if the project has delivered
a positive return on investment and, if so, at what stage during or after deployment the
cumulative spend matched the benefits accrued.
EPRI provides some guidelines when defining the appropriate costs:



Cost data can come directly from the project, estimated or tracked by the investor;
Capital costs are amortised over time; each project has to estimate its activity based costs,
using its approved accounting procedures for handling capital costs, debit, depreciation, and
taxes;
Both baseline and actual project costs should be tracked, with a distinctionbetween costs that
would normally be incurred in a-scale investment and those due to the RD&D aspects of the
project.
Moreover, it is important to note that costs should always be estimated and/or calculated on the
same time intervals for which benefits are calculated. In general, following costs could be considered:
Category
Programme
Type of cost
Planning and administration
Smart Grid programme implementation
Marketing
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Category
Type of cost
Measurement, verification, analysis
Participant incentive payments
Capital investments
Generation
Transmission
Distribution
Other
Operation & maintenance
Generation
Ancillary service
Transmission
Distribution
Meter reading
Participant incentive payments
Losses and theft
Value of losses
Value of theft
Reliability
Restoration costs
Environmental costs
CO2 control equipment and operation
CO2 emission permits
SO2, NOx, PM control equipment and operation
SO2, NOx emission permits
Energy security
Cost of oil consumed to generate power
Cost of gasoline, diesel and other petroleum products
Costs to restore wide-area blackouts if any actually occur during the
project period
Research and development
R&D costs
Table 2 Overview of costs
STEP 7 – Compare costs to benefits
Once costs and benefits have been estimated, they need to be compared in order to evaluate the
cost-effectiveness of the project. This comparison could be done by using one of the following
universally accepted approaches (also put forward by the EPRI methodology):

Annual comparison: Compiling the annual benefits and costs over the duration of the
project – i.e. the differences compared with the BAU condition for both benefits and costs for
each year of the study period.

Cumulative comparison: Presenting costs and benefits cumulatively over time, with each
year’s costs or benefits being the sum of that year’s value plus the value of all prior years.
This approach helps identifying the ‘break-even’ point in time when benefits exceed costs.
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
Net present value (NPV): Calculating the net present value, in which benefits minus costs
each year of the project are discounted using an agreed discount rate. The NPV represents
the total discounted value of the project – i.e. the total amount by which benefits exceed
costs after accounting for the time value of money.

Benefit-cost ratio: This method shows the ratio of benefits to costs. It represents the size of
benefits relative to that of the costs. If the ratio is greater than one, the project is costeffective.
Sensitivity analysis
When comparing costs to benefits, this must be carried out around certain factors or parameters
depending on the choice of the project coordinators. These are generally parameters with a high
degree of variability and/or uncertainty. Key assumptions underlying the analysis, including those
that drive estimates of major cost components, should be clearly documented, and the variability or
uncertainty of estimates should be incorporated into those estimates.
The proposed methodology recommends including a sensitivity analysis as part of the costbenefit
information filing supporting the smart grid project investments. Indeed, different geographies and
regulatory environments will have different impacts on the cost and benefits quantification. The
sensitivity analysis should:


Identify the key variables. Good candidates include the cost and reliability of technology,
customer behaviour change achieved, discount factor when calculating net present values,
emission costs and reliability factors, which have a wide range of potential values and are
more subjective in nature.
Produce different cost-benefit results in order to demonstrate the impact various scenarios
might have on the economic and societal profile of the smart grid project.
We consider the following two factors as having a high impact on the final outcome of the analysis:
a) Discount rate
The realisation of smart grid benefits and costs may occur gradually and over extended periods of
time. Therefore, all cost-benefit analyses in support of a smart grid investment should reflect and
adjust for the expected timing of estimated costs and benefits. The rate of return on grid investments
or the interest rate on long-term state bonds could be a reasonable choice for a discount rate.
However, different discount rates can be used to assess the benefits for different beneficiaries, e.g.
consumers may have a different assumed cost of capital compared to system operators.
The question of discount rate as should be applied and the influencing factors in its determination
depend on the context in which the analysis is to be considered. Two cases warrant consideration
here – the rate applied in analysis to inform a purely comercial decision regarding the financial
implications of implementing a technical solution in comparison with other options for the benefit of
the investing party, and analysis for comparative purposes where a project may be publicly funded to
realise potential benefits to society.
Where a smart grid investment is being considered by the grid operator as an alternative to more
conventional investments on purely technical and financial terms, it must be noted that “smart”
investments are often far closer to typical telecommunications investments, generally with a higher
risk level than conventional utility investments. Additionally, this is often less mature technology,
applications and a new technological environment for the utility, increasing the risk of not achieving
expected returns. Thus if the discount rate is to fairly reflect the relative risk of the projects, a higher
discount rate should be applied to the “smart investment” analysis.
However as the useful economic lifetime of smart grid assets will likely be shorter, this higher risk is
limited to a shorter period. Thus should there be a will to incentivise “smart” investments over
conventional ones for societal reasons on the part of government, the regulator or other policy
determining organisations, an appropriate means of achieving this would be through allowing the grid
operator a higher WACC and shorter depreciation on such investments, thus seeing the additional risk
subsidised by the driving body.
There is however, a case for a lower discount rate to be applied on a theoretical level to show what
the return for society on an investment will be relative to the return seen on other public
investments. Where a “smart grid” is being considered for social reasons with the costs and gains to
society, then it would be appropriate for the discount rate to reflect the risk to the state, specified by
the state body responsible for determining whether the project will be publicly funded.
The interaction between discount rate and implementation schedule of a project will have a direct
impact on the NPV cost of the project. Thus it is vital that both are accurate and do not
disproportionately emphasise costs or benefits at any stage in the project. Where the costs or rate of
return vary over the discounting period, this must be factually reflected. This is pertinent in the case
of smart grids, as evidence to date suggests that benefits are achieved later due to the
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interdependence of different systems which must be deployed, the current immaturity of technology
leading to price volatility and the requirement for public engagement to realise potential benefits.
It must be borne in mind that no generic discount rate can be applied in either case as this will
depend on a complex combination of matters including the debt level of the funding body. The rate
applied in any case, be it utility WACC or the rate on state bonds, requires calculation by those fully
informed on the case in question and qualified to do so. However standardising the useful economic
lifetime of assets would be a far more achievable measure due to its dependence on technology
rather than financial status of a body.
b) Lifetime
The lifetime over which a cost-benefit analysis is conducted should reflect the projected useful life of
the smart grid investment or system. It represents the continuous period of time when the
components and system of the investment operate correctly and reliably to perform their designed
functionalities. The project coordinator should carefully document the basis for its determination of
the investment’s useful life and also the length of time over which reasonable customer and societal
benefits can be reliably estimated.
5.2. DESCRIPTION OF BENEFITS
The following benefits of Smart Grid implementation are those traditionally accepted by the energy
sector.
Optimization of System Operation

Improvement of power system supervision and control
The current state of Smart Grid technology enables the supervision and control of electricity network
elements under a totally new totally new and improved control paradigm. For instance, with such
technology, System Operators have the possibility to supervise the high voltage (HV) network as well
as distributed generation, and to perform remote operations over HV and MV elements – integrating
control, planning and operation of generation, customer equipment, and the network under the same
framework and directly over the distribution lines.
Likewise the use of “smart” components in the network will help to redirect energy flows, especially
active flows like variable impedance transformers, angle transformers or the use of Special Protection
Schemes, to deal with the emergency situations and avoid incidents that deeply penetrate the
network.

Optimal and efficient use of power generation and energy recourses
Planning for energy use/consumption includes not only the scheduling of generation plants to meet
demand, but also many ancillary services that must be planned, forecasted and dispatched in order to
ensure network security and quality of service.
The implementation of Smart Grid technology provides an improved control over conventional,
distributed, and RES generation plants. This improved control then results in:
o
a higher accuracy and broader scope in the supervision of the power system, and;
o
the availability of more and accurate data with which to calculate a wider range of
fault scenarios for the security analysis, and reduce the margins of generation
capacity needed to provide operational reserves.
Essentially, the additional information and improvement of remote control operations can achieve
significant energy resource optimization – up to heretofore‐infeasible levels without the use of new
Smart Grid technology.

Intelligent diagnostic and corrections
The availability of more accurate information has given rise to advanced network analysis functions
such as “self‐healing” of automated transmission networks. This self‐healing scenario means that with
Smart Grid technology, the grid is able to autonomously identify, localize, manage, and restore
service due to an unexpected disturbance or interruption.

Enhanced fault management
Remote control and improved monitoring of the HV and MV grid achievable with Smart Grid
technology change the paradigm of fault management; including in the detection of faults,
manoeuvres and reconfiguration of the network during the service interruption, restoration of the
supply after a shortage, communication with the affected customers and further analysis of the
incident. This enhanced management capability also allows for an optimization of network‐related and
energy resources.
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
Improved options for power markets
With the corresponding market rules or guidelines, the implementation of Smart Grid technology
provides HV and MV network agents the opportunity to actively contribute to efficiency in power
markets, by creating more options for and more knowledgeable generators and consumers.

o
Real‐time information gathered at the transmission level can improve generators’ bids
in the market.
o
Demand control via electronic meters with two‐way (bidirectional) communications
enables consumers to offer their flexibility as a service to the market, or can
incentivize consumers to seek more advantageous electricity service contracts from
willing suppliers interested to make use of this supply flexibility.
Distributed management of power system operation
Some sub‐networks can be coordinated through Smart Grid technology without compromising the
advantages of centralised power system operation. Smart Grid technology allows for a hierarchically
subordinate, sub‐network configuration of the overall network that boosts the local and central
operation. This sub‐network coordination is referred to as a “distributed management” paradigm
(rather than “decentralized”) and is characterised by task automation, and the delegation of control
from the main control centre to regional control centres.

Real‐time, adaptive system operation
The availability of information in real‐time allows for real‐time supervision of power system
performance. The network or system operator can quickly act to adjust operations (if needed) for
deviations from forecasted scenarios, as well as more accurately track evolving fault risks and act to
prevent them.
Network Planning Optimization

Reduced need for reserve capacity in the network
The increase in the accuracy and granularity of system control means that the same level of
shortterm safety and security can be met with lower capacity reserve margins and network
redundancies; while in the medium and long‐term reduce the need for investment in transformers
and the network.

Reduced need for investment in transmission network
The main objective of the transmission network is to transfer energy in bulk from large generation
zones to the consumers; the two of which have historically been far from one another. The recent
increase in installed, increasingly modular distributed generation has reduced long distance transfer
needs by placing generation and consumers in the same (or closer) geographical zones. Since
distributed generation can be managed by Smart Grid technologies on non‐HV networks, it is an
additional advantage over more remotely‐placed, larger generation requiring transmission
infrastructure. The economic efficiency benefits of smart‐grid controlled, distributed generation are
thus expected to reduce the needs for transmission infrastructures.

Improved analysis of ancillary services
The implementation of Smart Grid functions increases the efficient provision of ancillary services in
technical, economic and environmental terms.

Electricity Market Transparency
Transparency in electricity pricing can be supported by data collected through the smart grid and the
automation of the billing process. Furthermore, providing customers with access to data that they can
use to participate in demand management is expected to eventually bring about lower electricity
prices across the system.
Facilitating RES Integration

Improved management of renewable energy generation
Even with the amazing progress of wind and solar generation technology in recent year, some
technical issues (absent in conventional generation) such as generation intermittence, non
manageable production, voltage fluctuation sensitivity and others, continue to present an additional
challenges for system operation whenever the plants are connected to the grid. However,
implementing generation control and supervision functions of Smart Grid technology can reduce the
uncertainty caused by wind and solar energy use, in a way that was unimaginable ten years ago.
Today Smart Grid technology is inseparable from reliable power systems that integrate RES
generation.

Improved use of indigenous and local energy resources
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The use of Smart Grid technology can help maximize the use of energy resources near load centres,
thus providing some benefits to the overall system operation. For example, Smart Grid technology
implementation facilitates the use of distributed generation and efficient cogeneration, reduces
transmission and distribution losses, reduces transmission infrastructure needs, improves the security
of operation, adds supervision and control elements to the system enhancing quality of service and
continuity of supply, etc.

Increased energy independence
The total number of large, viable power plants based on endogenous resources in any given country
is finite. In other words, sooner or later no additional large big hydropower plants, or thermal plants
based on domestic fossil fuels, can be built and/or operated. Traditionally the solution to the scarce
indigenous resources was only to import either fuel or electricity (through cross border
interconnections), resulting in a certain level of energy dependence on other countries for power
supply.
The use of Smart Grids supports non‐import solutions by enabling improved integration of distributed
RES plants to the grid. With each additional RES plant that comes on‐line, the level of dependence on
non‐domestic resources falls somewhat. Furthermore, if the demand can be “stored” or “delayed”,
and served local resources are available, the need to import energy decreases. Similarly, if peak load
can be reduced, the needs to import expensive energy during the peak hours decrease. This concept
supports demand side management programs. Lastly, in support of optimizing available generation
plants, more accurate management of system reserves lowers the need for Ancillary Services,
including reserves.

Lowering the impact of price uncertainty in fuel supply contracts
In general terms, fuel price uncertainty has a greater impact on systems that have fewer alternatives
to the fuel supply. The management of fuel price uncertainty is mainly based in the characteristics of
the fuel supply contracts4. The most important concept is that, the fewer options to the
contract‐based fuel supply that the buyer has, the more incentive the seller has to capitalize on the
buyer’s limitation and incorporate contractual clauses that link the long term fuel price to the world
spot market prices.
The application of Smart Grid technology in resource optimization improves fuel purchasers’ /
generators’ options for fuel management, and improves the flexibility and negotiation position of the
buyer so as to achieve more amenable fuel supply contract terms with the seller.
As an indirect result, the lower uncertainty of fuel prices for power supply also results in a lower
electricity price, thus benefiting the development of the economy as a whole.

Facilitating integrated RES self‐generation
As the environmental conscience of the citizens grows, very often preferences shift toward more
environmentally friendly (and costly) power supply options. Smart Grid technologies provide
consumers with greater freedom of supply choice and the technical support needed to install wind and
solar self‐generation equipment, while remaining connected to the distribution grid and enjoying the
same service quality as any other distribution customer.

Allowing New Economical Land Use
Among the benefits of the Smart Grids technologies and the integrated RES that accompany it, is
emergence of new uses for land. Areas where RES are viable are usually not suitable for real estate,
industrial or farming purposes because the favourable conditions for RES production (high wind or
sun intensity) are usually too extreme for other activities. The possibility of installing RES plants on
otherwise less desirable land is a windfall to the country’s overall productivity and economy.
Energy Efficiency

Reduced global peak demand
Peak demand periods are very resource intensive and costly when compared to the off‐peak demand.
By mean of feasible programs of demand side management the peak demand can be reduced almost
without impact on the energy needs of the customers.

Lower technical and non‐technical losses
The extensive use of bi‐directional flow information (electronic meters and/or other monitoring
equipment in the grid) allows different operators to determine the size of the system losses, either
technical or nontechnical, and the areas where they occur. From this knowledge, corrective measures
can be implemented to reduce the losses, such as: flows reduction, voltage levels adjustment, and
others.
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The implementation of the Smart Grid technology supports the reduction of the technical losses in
many ways, largely due to the increase of the optimal operation of the power system. The main ways
to reduce the technical losses are:
o
Integrating distributed generation to reduce the transmission and distribution losses;
o
Optimizing generators’ operational margins allowing them to run more closely to their
optimal efficiency levels, and;
o
Reducing spare operational capacity and redundancies in the lines and transformers.
Likewise, Smart Grid Technologies facilitate the control of the energy flow and hence the low level
balance among the energy supplied and the energy billed to customers. The analysis of that
information and the implementation of the corresponding activities lead to significant reductions in
non‐technical losses.

Consumer contribution to efficient power system operation
By employing the control features of electronic metering equipment the customer can actively
participate in the Demand Side Management, thereby connecting or disconnecting demand blocks.

Intelligent management of electric car (large battery) charging
The use of Smart Grids facilitates the introduction and growth of the electric car market in Europe. At
the same time, smart grid control applications support commercial, publicly available sites and
home‐based battery recharging as a part of domestic DSM.
An additional application under discussion is the possibility use smart grid technology to remotely
control large numbers of batteries distributed among residential consumers to store electricity and
release/dispatch as needed by regional or local power system control centres.

Customized client consumption patterns
Smart Grid technology is able to support the customer‐level automation of power consumption
according to the real‐time power system operational conditions. The benefit of this customization
would be to meet energy use criteria defined by the consumer, such as by energy price, environment
impact, or others.

Improved consumer options for lowering the carbon footprint
As the participation of consumers in the electricity market becomes more dynamic, providers and
suppliers must work harder to satisfy the their expectations. In this sense, providing consumers with
the ability to participate in the electricity market by selecting providers promotes the installation and
use of RES energy due to a growing demand for “green” energy. Consumers can know how much (or
how little) their energy choices contribute to reducing CO2 emissions, for instance, and allows them
to choose energy suppliers with associated low‐carbon primary energy sources.
Climate Change

Social demands facing climate change implications
The last two decades have shown an increase in the social sensitivity to the environmental impact of
human activity and its contribution to “climate change”. It is a trend that has proven stable and
unlikely to change. The increased of use of more environmentally friendly generation technologies is a
practical approach to satisfying the demand for consumer social responsibility. Additional, yet
lesser‐known options are also available through smart grid technologies, such as the optimal use of
the existing generation facilities, lowering needs for expansion, use of more efficient generation
process, among others.

Lowering carbon emissions
While the main way in which the Smart Grid technology helps to lower the carbon emissions is to
maximize the injection of “green energy” in the system, it is not the only way. As Smart Grid
technology allows a more flexible operation of the power system, significant additional ways to reduce
the carbon emissions appear. For example, the management of demand allows demand to be delayed
until it can be served by less polluting resources or processes. Also, the reduction of losses
intrinsically reduces overall system emissions, and so on.

Support to the political targets of RES plants
The political and institutional targets of integrating a significant level of renewable energy plants in
Europe by 2020 requires the technical support of Smart Grid functions that can feasibly adapt the
wind and solar plant generation idiosyncrasies to the system quality and security of supply standards.
Business and Economic Growth
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
New business and research opportunities for power sector stakeholders in both
technical and commercial products & services
Smart Grids also provide new business and research opportunities in the economy. The
implementation of Smart Grid technology improves and creates business opportunities in technology
and financial research fields for a range of stakeholders, particularly for those active in the power
sector: utilities, generators, customers, service providers, and manufacturers of control and
communication equipment, financiers, insurances firms, and many others, in both technical and
commercial areas of the electricity market.
5.2.1.
a)
QUANTITATIVE
EU Approach
Likewise, the benefits are defined in order to provide transparent calculation criteria. The concepts
are now followed by a calculation formula so that the evaluation is consistent across the countries’
assessments.
The table below lists the standard aspects that must be evaluated as potential benefits through this
methodology. (Additional benefits may also be considered by member states at their discretion.). Full
details of the calculations indicated by the methodology can be found in Annex 9.1 to this paper.
b)
Additional Benefits (additional work possibilities)
Under development
5.2.2.
QUALITATIVE
The overall analysis should also consider externalities that are not quantifiable in monetary terms.
This includes the cost and benefits derived from broader social impacts like security of supply,
consumer participation and improvements to market functioning.
To this end, it is necessary to identify project impacts and externalities and assess them in physical
terms or through a qualitative description, in order to give decision-makers the whole range of
elements for non-monetary appraisal.
Assessment should also address non‐quantifiable issues, including:

Performance Assessment or the impact of public policy measures expected from smart
meter program rollout according to specific KPI.

Externalities and Social impacts, essentially “spill over” effects of smart meter roll out that
cannot be monetized, but that impact society, such as the expected development of future
related products & services.
5.3. COST – BENEFIT BALANCE FOR EACH PROGRAM
Under development
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6. IMPLEMENTATION ROAD MAP
6.1. DETAILED PHASING
As mentioned above, the implementation of the program shall include three phases, namely:



Initial Phase
Emerging Phase
Mature Phase
All technological and social improvements shall be included therefore in these three phases.
6.1.1.
STAGE 1: INITIAL PHASE (2012-2016)
This phase shall include as follows:
1. Improvement of power network operation program:
1.1. Complete the SCADA/EMS project for National Load Dispatch Center, Regional Load Dispatch
Centers. Install completely the devices to collect operation data from substations/power
plants connected to 110kV grid and above.
1.2. Implement the applications to enhance reliability and to optimize operation of transmission,
distribution grids; reduce losses; especially the applications to protect safety of 500kV
operation, such as fault recorder system, wide-area protection.
1.3. Check and review the implementation of regulation on mandatory data collection system in
power plants, substations connected to 110kV grid and above.
1.4. Initially equip SCADA/DMS system for distribution power corporations, provincial power
companies. This includes the software, hardware and Communications for Control Centers at
PC’s headquarters and automation of selected 110kV-MV/MV substations
1.5. Training and enhancing the smart grid implementation capacity of National Power
Transmission Corporation, National Load Dispatch Center, distribution power corporations,
power companies.
1.6. Complete the programs, technical assistance project, load research; deploy the demand side
management programs.
1.7. Development and implementation of advanced operation tools for the integration of large
amount of non-manageable renewable power in the system.
1.8. Pilot project for integration of renewable generation in Center Power Corporation: apply for
renewable generation of the capacity from 5MW.
2. Development of Smart Metering Program:
2.1. Pilot project for advanced metering infrastructure (AMI) applied to selected big customer in
Ho Chi Minh City Power Corporation and in Center Power Corporation.
2.2. Disemination of lessons learnt
2.3. Pilot Extension to the remaining Power Corporations. Implement the pilot project which
allows customer to trade on the competitive power market (whole sales competitive power
market and pilot retail power market).
2.4. Implementation of advanced metering infrastructure (AMI) applied to selected big customer
in Vietnam.
2.5. Pilot project of residential metering infrastructure in Hanoi Power Corporation.
3. Building of regulatory framework:
3.1. Complete load research procedure; develop the mechanism for demand side management.
3.2. Through out the assessment of implemented programs for TOU meter, installation of
electronic meter, complete regulatory framework, propose mechanism to enhance efficiency
and to extend these programs for the next stages.
3.3. Research and propose financial mechanism for smart grid development.
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3.4. Base on researching result and accessing of programs efficiency, issue or review regulatory
documents in order to deploying of infrastructure and implementing of smart grid
applications.
3.5. Develop technical regulations: Researching, issuing of technical standards for Smart Grid,
such as: advanced metering infrastructure, integrated renewable generation and distributed
generation standards; structure of distribution smart grid, etc.
4. Development of Social Support
4.1. Preparation of Communication program for the Smart Grids.
4.2. Full dissemination of the program
Corporations, Large Customers
for:
Institutions,
Generation
Companies,
Power
4.3. Preliminary dissemination of the program for residential customers.
6.1.2.
STAGE 2: EMERGING PHASE (2017-2022)
This phase shall include as follows:
1. Continue to implement the program Enhance the network operation efficiency, focusing on the
distribution grids; equipped the Information Communication Technology (ICT) infrastructure to
the distribution grids:
1.1. Deploy SCADA/DMS system for the distribution power corporations, including all 110kVMV/MV substations and some selected MV/LV substations.
1.2. Continue to build the Smart Grid implementation capacities for the distribution power
corporation.
1.3. Integrate distributed generations, new energy generations, and renewable generations into
the network at medium and low voltage.
1.4. Development of pilots for advanced Energy management in the Transmission Grid.
2. Development of Smart Metering:
2.1. Deploy to install the advanced metering infrastructure (AMI) to residential customers of 5
distribution power corporations.
2.2. Develop step-by-step the electricity transport system, test and evaluate economic efficiency
of others smart grid technologies as electricity transport system, energy storage technology.
2.3. Continue to implement the demand side management programs (DSM) to rural areas.
2.4. Development of pilot projects for Smart Homes.
2.5. Creation of a pilot Smart City
3. Building the regulatory framework:
3.1. To research and recommend the authority to issue the mechanisms: encouraging smart grid
applications in developing renewable energy sources; encouraging smart grid applications in
zero energy house (non-consumed of energy from outside); encouraging smart grid
applications in energy trading between customers and power utilities.
3.2. Development of advanced tariff methodology that can profit the technological advantages of
Smart Grids.
3.3. Develop technical standards: research and recommend the authority to issue technical
standards for electricity transport system, energy storage technology.
4. Development of Social Support
4.1. Update of Communication program for the Smart Grids to include the new tariffs approach.
4.2. Full dissemination –in stages- of the program for residential customers.
6.1.3.
STAGE 3: MATURE PHASE (AFTER 2022)
This phase shall include as follows:
1. Continue the Information and Communication Infrastructure program for distribution grids:
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1.1. Deploy the SCADA/EMS system for all provincial/district power companies to reach efficient
number of MV/LV substations.
1.2. Extension of advanced energy management tools from transmission grid to distribution
network.
2. New applications
2.1. Develop Electric Vehicle Infrastructure.
2.2. Enhance Distribute Generation plants
2.3. Implement the smart grid applications which allow to electricity demand-supply balancing in
customer level (Smart Homes).
2.4. Use of renewable energy widely in distribution grid with the time-of-usage electricity price
mechanism associated with retail competitive power market.
2.5. Develop electricity transport system, energy storage system.
3. Build regulatory framework which allows to deploy smart grid applications base on existing
information technology infrastructure.
6.2. ROAD MAP
Pending for the workshop
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7. INSTITUTIONAL ROLES
The implementation of an intelligent network will require changes in the planning, operation,
maintenance and expansion of the transmission and distribution grids. This can further lead to a
shortening of investment cycles of grid operators due to the massive integration of ICT (Information
and Communication Technology) components. All actors will ultimately benefit from this development
as the increased smartness should result in potentially overall lower costs, higher quality of supply,
enhanced competition and more flexible tariff options compared to situation where no Smart Grids
deployment is made.
For the successful deployment of Smart Grid, a number of challenges that need to be resolved
include:

Technical issues, as the Smart Grid represents a technical challenge that goes beyond the
simple addition of an Information Technology infrastructure on top of an electrotechnical
infrastructure. Each device that is connected to a Smart Grid is, at the same time, an
electrotechnical device and an intelligent node.

Market design issues, where variable energy sources and active demand side management
are integrated into new market rules, incentivizing consumers and (small) producers to
actively participate in the energy market.

Necessary changes that allow grid operators, retailers, small generators and customers to
make use of state-of-the-art communication technologies to improve data transparency and
actively participate at the energy market.

Regulatory measures allowing the development of smarter grids and more active
participation of small players by e.g. giving proper incentives to grid and energy providers
and users to contribute to an efficient system.

Customer engagement with Smart Grid issues, especially focusing on public acceptance
of and engagement with Smart Metering and reassuring consumers on privacy and/or
security, and other issues that may arise. In order to build consumer trust there needs to be
a systematic review of consumer protections and a strategy to deliver tangible benefits to
consumers.

Social issues, such as acceptance and engagement with technological changes, ensuring
that all consumers including vulnerable and low income consumers can access the benefits of
Smart Grids.
7.1. MINISTRY OF INDUSTRY AND TRADE
Policy makers should ensure active support for market and competitive business activities –including
innovative approaches where these benefit their citizens. They must put in place the appropriate
regulatory framework to protect consumers and enable them to access the full benefits of Smart
Grids and Metering. At the same time, they should avoid interfering where this is not necessary to
preserve the competitive environment, ensuring, unless it is for fairness reasons and guaranteeing
proper functioning of all markets in a sustainable way to the benefit of all actors and society as a
whole.
Some of the areas to be addressed are:

Given that the marketplace will expand with new actors and services offered, the required
legal framework needs to exist and be enforced to ensure all relevant market rules and
regulations are in place between TSOs, DSOs and other market participants.
Policy makers will be required to create a framework and guidance for the Smart Metering rollout
especially to deal with issues relating to customer data privacy, data protection, tariffs, remote
management and disconnection.
7.2. ERAV
Regulator should ensure a long-term-predictable and stable regulatory framework, including adequate
incentives for investments. The payment of costs should remain fair according to the actual originator
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of these costs with a balanced and sustainable approach between the appropriate rate-of return for
the regulated grid operators and the respective requirements and benefits for the grid users.
Given that more actors will participate in the marketplace, Regulators will also need to further support
designing and implementing the direct regulatory measures and market rules required for the market
place of the future and for ensuring utilization of all the new services and opportunities to the benefit
of all actors. The use of consultation papers may be useful for this kind of activities.
Regulators should also be assigned the responsibility for systematically reviewing customer protection
to ensure that they are fit for purpose in a smart world. For example, new safeguards will need to be
put in place to protect customers from misuse of remote disconnection, remote switching, mis-selling
of complex new tariffs alongside new data protection and privacy rules. They have a particular
responsibility to protect the interests of low income and vulnerable consumers to ensure that all
customers are able to access the benefits of smart grids. In summary, ERAV must determine the
‘drivers for the change’ thereafter.
Finally, the regulator will be responsible to create and modify the new technological codes engaged to
Smart Grid implementation, the role and function of technical regulation will need to change to
respond to new factors.
7.3. NPDC AND NPT
The Transmission company (NPT) and the System Operator (NLDC) will have to provide more support
& communication of data to the DSOs, but will also require more specific information from the DSOs,
especially with more distributed generation coming from the distribution grids. In order to achieve
this, all of them need to ensure that the standards they implement for communication and data
exchange is compatible. It also follows that the System Operator will have to gradually redesign
power system control as well as market information management relating to forecasting the overall
system load in conjunction with the DSOs. At the same time, the DSOs will have to strengthen their
role in providing the required data relating to the distributed generation, local storage and electric
vehicles within the distribution grid.
All of them therefore should be able to execute their active role in Smart Grid management by
ensuring more sophisticated legal provisions for system security management under increased
uncertainty.
7.4. PCS AND LDUS
Growing distributed generation, active management of demand, local storage and electric vehicles
(EV) will impact the DSO infrastructure. Thus the DSO will have to be an active participant in all such
projects along with the actors implementing these projects as these projects will fundamentally
change today’s relatively static distribution system to a much more dynamic distribution system.
As more fluctuating distributed generation will feed into the distribution system, gathering
handling the data about the state of the distribution system will be one key issue for the DSO.
data collected will enable the DSOs to fulfil their duty in relation to the overall grid stability
operational security, given that more and more distributed generation will be connected to
distribution grid.
and
The
and
the
In order to resolve these challenges, the DSOs will have to continue upgrading their grid
infrastructure, control centres and educating their employees accordingly.
For the other hand, the DSOs will have to develop transparent and easy understandable rules for
Demand Side Response, such that they are accepted and trusted by all consumers. It is also
important that by collecting and communicating such data, all consumers will become more aware of
their overall consumption of energy and how they actually use that energy. To make Demand Side
Responsible possible, standard load profiles used by suppliers for customers will have to be replaced
by ‘dynamic’ load profiles in case of flexible energy prices and / or grid tariffs.
7.5. CIVIL ORGANIZATIONS
7.5.1.
CONSUMER ASSOCIATIONS
Consumers will become more engaged in Demand Side Response (DSR) and DSR will become
increasingly important to enhance the overall system efficiency and effectiveness and consumer
associations have the responsibility to inform consumers of the new technologies, applications,
benefits and responsibilities.
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The way forward is to inform grid users, especially households, which in turn is a responsibility for all
actors: regulators, suppliers, distribution networks and manufactures. At the same time, national
communication campaigns must acknowledge that it is not possible to engage all audiences on the
same level: consideration must be given on how best to segment and approach the respective
consumer groups. In addition, another key aspect is the position and needs of consumers which must
be addressed appropriately and contained in any strategy for overcoming the challenges above.
These include;

The national economic assessments must address the potential social benefits and risks;

Consumers must be protected from financial risks and from unfair, new and confusing tariffs;

Low income and/or vulnerable consumers must be protected.

Assist consumers to understand and value the environmental benefits related to the
deployment of Smart Grids.
7.5.2.
UNIVERSITIES AND SCIENTIFIC INSTITUTIONS
Universities and Scientific Institutions should be involved in the Smart Grids development, ensuring
the knowledge transfer of new smart technologies and systems to the future professionals. To enable
the training of these professionals, universities will have to launch courses with specific contents in
Smart Grids and carry related research projects.
7.5.3.
TRADE UNIONS
Electric Smart Grid equipment supplied to grid users will continue to evolve as suppliers innovate to
integrate more and more ‘smartness’ into their products and solutions. Further technology
developments in conjunction with advances in modern ICT will result in more sophisticated and
intelligent equipment being used in the Smart Grid.
All this technological development will carry out a wider knowledge of smart grid technologies, new
business models and service offerings will evolve as actors take advantage of the new data sources
available to them, potentiating Vietnamese companies to become solution providers taking a
leadership role in the market.
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8. CONCLUSIONS
Pending for the Workshop
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9. ANNEXES
9.1. BENEFITS CALCULATIONS DETAILS
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