ES 11015

Examensarbete 30 hpMaj 2011

Market concepts and regulatory bottlenecks for smart distribution grids in EU countries

Henrik OlssonYalin Huang

Teknisk- naturvetenskaplig fakultet UTH-enheten Besöksadress: Ångströmlaboratoriet Lägerhyddsvägen 1 Hus 4, Plan 0 Postadress: Box 536 751 21 Uppsala Telefon: 018 – 471 30 03 Telefax: 018 – 471 30 00 Hemsida: http://www.teknat.uu.se/student

Abstract

Market concepts and regulatory bottlenecks for smartdistribution grids in EU countries

Henrik Olsson

In the European Union, there is a driver for a change in the electricity system. Thetrend is to make the system more environmental friendly and improve the marketsfunctionality. This driver often refers to the development towards a smart grid. Inorder to accelerate innovation in smart grid and technology application, pilot projectsneed to be deployed. This master thesis has been done as a part of the StockholmRoyal Seaport urban development project that is a pilot project for smart grid ondistribution grid level. The aim of this report is to apply market concept and identify regulatory bottlenecksfor smart grid. This report has applied market concept and identified severalbottlenecks for two aspects of smart grid. The aspects are integration of distributedenergy resources in medium and low voltage level and a changing customer behavior.A changing customer behavior contains both demand response and theimplementation of electric vehicles. A state-of-art review on feasible solutions that improve the competition and demandside management of electricity market in smart grid and provide incentives toimplement smart grid functions has been performed. The emphasis in the marketaspect is on how that new actors like aggregators will enter the market and how thedynamic price can reach consumers. The emphasis in the regulatory aspect is on howregulations promote the application of smart grid supporting technologies for boththe DSO and the network users. A case study has been performed for EU countries with a deeper look at Sweden.The case study investigates how far that the current regulations have reached on theway to smart grids. A state-of-art review on conclusion papers of pilot projects hasbeen carried out. However, many pilot projects are still ongoing and not included inthe review. The result shows there is still a lack of regulatory incentive to promotesmart grid development and supporting market structures. Bottlenecks identified forsmart grid services in the Swedish electricity market and regulation are related tofour areas. These are the metering system, dynamic consumer price, activedistributed units with the possibility to provide services to the system and incentivesto the DSO to use new smart grid solutions in the work to enable fast and efficientconnection of distributed generation.

Key words: smart grid, distribution grid, electricity market, regulation, EU

Sponsor: Fortum Distribution ABISSN: 1650-8300, UPTEC ES 11015Examinator: Kjell PernestålÄmnesgranskare: Lennart SöderHandledare: Karin Alvehag

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Sammanfattning

Europeiska Unionen arbetar för att förändra och förbättra dagens energisystem. Två mål kan utskiljas

med arbetet; att göra elsystemet mer miljövänligt samt att förbättra marknadens funktionalitet.

Denna process refereras ofta till som utvecklandet av ett smart elnät. För att driva på denna

utveckling har ett antal utvecklingsprojekt på olika nivåer initierats. Denna rapport är en del av Norra

Djurgårdsstadsprojektet som är ett utvecklingsprojekt med fokus på urbana smarta

eldistributionsnät.

Rapportens syfte är att identifiera marknadslösningar för smarta elnät och att utreda hinder för

dessa lösningar i den reglering som idag existerar för distributionsnätsbolag i Europa. Rapporten har

avgränsats till att endast omfatta två aspekter av smarta distributionsnät. Dessa är integrationen av

distribuerad elproduktion i mellan- och lågspänningsnäten samt att möjliggöra ett förändrat

konsumentbeteende. Förändrat konsumentbeteende syftar till hur konsumenter skall få möjlighet att

mer aktivt delta i elmarknaden samt integreringen av elfordon i elsystemet.

Rapporten presenterar en state-of-art review av lämpliga åtgärder för att förbättra konkurrensen

samt möjliggöra för aktiva konsumenter att till en högre grad delta på elmarknaden. Vidare har

metoder för att förse marknadens aktörer med incitament för att utveckla smarta lösningar

identifierats. Fokuset kring marknadsaspekter för smarta nät har varit på vilka roller nya

funktioner/aktörer så som aggreatorer kan fylla i en framtida elmarknad samt hur marknaden ska

möjligöra att tidsdynamiska prisincitament når konsumenterna. De falskhalsar som har identifierats i

dagens elnätsreglering gäller hur regleringen ska kunna ge incitament till distributionsnätsbolagen att

implementera nya lösningar relaterade till smarta elnät.

Vidare har även en genomgång av regleringen i ett flertal EU-länder genomförts med en djupare

genomgång av svensk reglering. Hur långt de olika länderna har nått i arbetet att anpassa regleringen

till att främja teknikutvecklingen mot smarta elnät har undersökts. För att sammanfatta läget i EU-

ländernas reglering har en state-of-art review gjorts av pilotprojekt i EU kring smarta elnät.

Resultatet pekar på att det för tillfället finns ett stort behov av att utveckla regleringen för att främja

teknikutveckling och implementering av smarta elnät samt utveckla en marknadsstruktur som stödjer

användandet av dessa lösningar. I den svenska regleringen kunde fyra områden med speciella behov

av utveckling identifieras. Första området är elmätsystem och möjligheterna att utveckla nya smarta

tjänster kring dessa. Andra området är hinder för att tidsdynamiska elpriser ska nå konsumenterna.

Tredje området är möjligheten för distribuerad elproduktion och styrbara laster att tillhandahålla

systemtjänster. Fjärde området är risken att utformningen av den kommade svenska

förhandsregleringen inte främjar investeringar i ny teknik.

Sökord: smarta elnät, distributionsnät, elmarknad, reglering, EU

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Acknowledgements

This work has been carried out as a part of Yalin Huang’s master degree in Electrical engineering at

the Royal Institute of Technology in Stockholm and Henrik Olsson’s master degree in Energy Systems

Engineering at Uppsala University and SLU. The project is a part of the Stockholm Royal Seaport

developing project and has been performed at the department for Electric Power Systems at KTH in

collaboration with Fortum Distribution AB. In this work Yalin has been main responsible for Chapter 4

and 7 while Henrik has been main responsible for Chapter 5 and 8.

We would like to thank our supervisor Karin Alvehag at KTH and Olle Hansson at Fortum for their

guidelines and suggestions throughout the work. Furthermore, we also would like to thank Roland

Liljegren (Fortum Distribution) for his help with the Swedish regulation. At last we would like to thank

the reference group for the Royal Seaport project Work package 6 for their feedback.

Stockholm, March 2011

Yalin Huang and Henrik Olsson

iv

Contents

1. Introduction ......................................................................................................................................... 1

1.1 Objective........................................................................................................................................ 1

1.2 Background .................................................................................................................................... 1

1.3 Method .......................................................................................................................................... 3

1.4 Outline ........................................................................................................................................... 3

2. Electricity market structure and current regulatory framework ........................................................ 4

2.1 The electric power system ............................................................................................................ 4

2.2 Electricity market .......................................................................................................................... 4

2.3 Regulation ensures the proper network and market activities .................................................... 8

2.4 Methods of regulation ................................................................................................................. 12

3. Expectations on smart grid ................................................................................................................ 16

3.1 Integration of distributed energy resources in the medium and low voltage grid ..................... 16

3.2 A changing customer behavior .................................................................................................... 17

3.3 Integration of large scale renewable energy resources .............................................................. 17

3.4 Reduction of losses and increasing self healing characteristic ................................................... 17

3.5 The focus of the report ................................................................................................................ 17

4. Market related and regulatory issues concerning integration of distributed energy resources ...... 19

4.1 Market concept—new opportunities .......................................................................................... 19

4.2 Regulatory bottlenecks ................................................................................................................ 22

4.3 Solutions to regulatory bottlenecks ............................................................................................ 26

5. Market related and regulatory issues concerning a changing consumer behavior .......................... 37

5.1 Requirements and market solutions for demand response........................................................ 37

5.2 Bottlenecks for demand response .............................................................................................. 45

5.3 Introduction of electric vehicles .................................................................................................. 51

6. Summary on market concepts and regulatory bottlenecks for smart grids ..................................... 54

6.1 Distributed Energy Resources ..................................................................................................... 54

6.2 Demand response........................................................................................................................ 55

6.3 Questions concerning implementation of electric vehicles ........................................................ 56

7. Case study—EU countries ................................................................................................................. 58

7.1 Background of EU countries related to smart grid ...................................................................... 58

7.2 Investigation on 18 EU countries ................................................................................................ 64

7.3 Conclusion on the case study ...................................................................................................... 74

8. Swedish electricity market and regulation ........................................................................................ 75

v

8.1 Introduction ................................................................................................................................. 75

8.2 The Swedish ex-ante regulation and general obstacles for smart grids ..................................... 79

8.3 Distributed Energy Resources ..................................................................................................... 79

8.4 Integration of electric vehicles in Sweden .................................................................................. 82

8.5 Demand response and incentives for consumers to be active ................................................... 84

8.6 Hinders for new services related to demand response and DER ................................................ 90

8.7 Summary of bottlenecks in the Swedish regulation regarding smart grids ................................ 93

9. Conclusion ......................................................................................................................................... 95

Bibliography ........................................................................................................................................... 96

Appendix .................................................................................................................................................. 1

vi

List of tables Table 2.1 Comparison on regulatory price control methods ................................................................ 14

Table 4.1 Impacts of integration of DER ................................................................................................ 25

Table 4.2 A comparison of revenue regulation schemes ...................................................................... 29

Table 4.3 Summary of connection charging methods (40) ................................................................... 33

Table 4.4 Recommended performance indicators (2) .......................................................................... 36

Table 5.1 Different price models for the retail market ......................................................................... 39

Table 5.2 Different types of tariff models ............................................................................................. 41

Table 5.3 Effects on peak load by different pricing models (57 s. 43) .................................................. 43

Table 5.4 Power based component in grid tariff introduced in Sweden for consumers with a fuse

below 63 Amps (autumn 2010) ............................................................................................................. 44

Table 5.5 Important benefits of smart metering .................................................................................. 46

Table 5.6 Smart meter ownership ......................................................................................................... 47

Table 7.1 Unbundling situation in EU countries (94) ............................................................................ 59

Table 7.2 An overview of required functions for smart meters (96) .................................................... 61

Table 7.3 Smart meter communication standards in some countries (99) ........................................... 63

Table 7.4 Support mechanisms for DG in EU countries ........................................................................ 65

Table 7.5 Market access for DG in EU countries ................................................................................... 67

Table 7.6 Regulation system and efficiency requirements in EU countries .......................................... 67

Table 7.7 Incentive quality regulations for DG in EU countries ............................................................ 70

Table7.8 Connection charge for DG in EU countries ............................................................................. 71

Table7.9 Demand response in EU countries ......................................................................................... 73

Table 8.1 The level of unbundling in the Swedish market for electric vehicle charging services ......... 83

Table 8.2 Different possible business models for charging service providers identified by Svensk

Energi (122) ........................................................................................................................................... 84

Table 8.3 Hinders in the market and regulation structure for smart grid market solutions ................ 94

vii

List of figures Figure 2.1 Hierarchical structure of electric power system (7) ............................................................... 4

Figure 2.2 Physical and economical structures (9) .................................................................................. 5

Figure 2.3 Timeline of electricity market (17) ......................................................................................... 8

Figure 2.4 The scope of electricity system regulation (14) ..................................................................... 9

Figure 2.5 Possible levels of tariffs (14) ................................................................................................. 10

Figure 2.6 Overview of regulation methods (14) .................................................................................. 12

Figure 4.1 Interaction of actors in smart electricity market ................................................................. 20

Figure 4.2 Revenue and costs of a DSO (33) ..................................................................................... 22

Figure 4.3 Bi-direction UoS charging (42) .............................................................................................. 35

Figure 5.1 How different price models divide the risk from the spot market between consumers and

retailers (46) .......................................................................................................................................... 40

Figure 5.2 Different functions in the value chain for electric vehicle charging and how these functions

can be divided on different actors (84) ................................................................................................. 52

Figure 6.1 The summary on DER integration ........................................................................................ 54

Figure 6.2 The conclusion on demand response ................................................................................... 56

Figure 6.3 Hinders and solutions for introduction of electric vehicles ................................................. 57

Figure 7.1 DG’s share of installed generation capacity in EU-25 (2004) (31) ....................................... 58

Figure 7.2 Smart meter roll-out at the end of 2010 (97) ...................................................................... 60

Figure 7.3 Smart meter penetration and smart meter functions in EU countries ................................ 62

Figure 8.1 Overview of the Swedish regulatory model (modified from (102 s. 14))............................. 77

Figure 8.2 The components of the Swedish electricity price (modified from (126 s. 52)) .................... 87

Figure 8.3 The hour by hour average spot price at Nord Pool for Sweden during 2010 (Data from

(131)) ..................................................................................................................................................... 88

Figure 8.4 The three days with highest peak price during 2010 in the Swedish price area (Data from

(131)) ..................................................................................................................................................... 89

1

1. Introduction

1.1 Objective Smart grid development implies changes in roles and responsibilities on the electricity market, due to

new market opportunities and services. Therefore it is important to investigate new market and

regulatory solutions for smart grid technology.

The objective of this report is to identify market concepts and regulatory bottlenecks for

stakeholders and actors when deploying smart grid technologies. As this work is a part of the

Stockholm Royal Seaport project, the Swedish regulation will be studied in more detail.

1.2 Background

1.2.1 Introduction of smart grid

Smart grid refers to an electricity network where all actors take advantage of advanced information

and communication technologies (ICT), intelligent computing and control technologies to make the

whole energy produce-transmit-use process more efficient, sustainable and economic (1). It is not a

brand-new grid but a gradual evolution on the existing grid (2). This kind of smart grids can be

incorporated at all levels of electric power network. The challenges will be different for transmission

systems and distribution systems, and the changes in distribution systems will be more significant (2).

In the Stockholm Royal Seaport Project, mainly smart distribution system is considered, so smart

distribution systems will also be the focus in this report.

1.2.2 Drivers for smart grid

The ambition to meet the EU 20-20-20 targets is a macro driver for the development of smart grids

(2). These targets aim to reduce greenhouse gas emissions, increase the renewable share of the

energy production and reduce the total amount of primary energy that is used. The reduction of

greenhouse gases shall be at least 20% below the 1990 levels by 2020. The part of the energy

consumption that comes from renewable recourses shall be 20% by 2020 and the primary energy use

shall also be reduced by 20% until then (3). For achieving this goal, European legislation and policies

will show a preference for renewable energies development and promote necessary investments for

them (2). All this will put energy efficiency and integration of renewable energy sources (RES) on the

agenda.

Cost-efficiency for all actors is another major incentive to make the current grids smarter (2). As a

consequence of political bias, more investments are put on researching and developing relevant

smart grid technologies which makes it cheaper to implement and some subsides can lower the

prices of sustainable energies. The infrastructure of the existing grids is ageing, which will lead to a

decline in reliability (1). Nevertheless, during the smart grid proceeding, reliability will increase and

therefore reduce the maintenance expenditure (4). For customers, they can save expense on energy

consumption by using smart household appliances and electrical vehicles (1).

Effective government incentives and economical attractions are two main drivers for smart grid (2).

Besides the above two main drivers, some additional drivers are also important. One important

driver is that consumers’ attitudes are changing (2). Consumers are becoming sustainable energy

conscious and asking for environmental friendly energies even though they sometimes would cost a

2

bit more (1). For instance, the most noticeable behavior change would be a larger percentage of

electrical vehicles. Nevertheless, electricity generation will have to be more environmental friendly in

order to fulfill the environmental targets. Also consumers have higher demands on reliability and

quality of power; the economic losses caused by power failure are increasing (2). At the same time,

consumers will use smarter household appliances which may reduce the use of energy; however the

total amount of electricity consumption will probably increase (2).

1.2.3 Enablers for smart grid

Smart grid is not an end, but more a process (2). There are several factors that enable this evolution.

New smart components in the distribution system are major contributors. One noticeable change is

the developments of distributed generation (DG) technologies which are stimulated by energy

policies and government incentives (1). In general, distributed generation can be considered as

electric power generation within the distribution grids or on the customer side of the grid (5).

Moreover, there are technologies breakthroughs. First sensing and monitoring devices need to be

installed, for instance smart meters together with wide-area monitoring systems and measurements

that can be taken in very precise time. This information can then be used to analyse and monitor the

stability of the grid (6).

Additionally, some developments in electricity storage technologies and technology that enables the

consumers to be more active make it possible to shift the electricity consumption in the time domain

(4). This contributes as leverage on the local supply and demand, allowing more energy to be

transported without providing grid capacity for high load peaks which rarely appear.

Regulation is a key success factor to put smart grid into practice. Regulators will set regulations to

balance obligations for all market actors such as consumers and regulated companies. For example,

regulation should incentivize distribution system operators (DSOs) to invest in the most efficient way

for the network users and society as a whole to eliminate monopoly inefficiency.

1.2.4 Stockholm Royal Seaport

In order to promote technology development and to accelerate innovation in smart grid, pilot

projects need to be deployed. Stockholm Royal Seaport is an urban development project for a

planned expansion of housing and services that will take place in the district of Hjorthagen in

Stockholm. This project has been designated as one of 18 projects in the world supported by the

Climate Positive Development.

The Stockholm Royal Seaport project is initiated with the ambition to create an urban smart grid that

will meet the Swedish Governments target to transform the current energy system into a more

environmental friendly system. This transformation requires new technical solutions and a holistic

system approach in order to implement a more sophisticated power system, updated electricity

market and efficient regulations. The Stockholm Royal Seaport project aims to develop a smart grid

for integration of consumers and producers into the utility electrical grid. The Stockholm Royal

Seaport Smart Grid concept includes market interaction, load balancing and demand response

control in a smart grid that contains relatively large percentage renewable generation.

This thesis work will cover a part of the Stockholm Royal Seaport project with a description of market

concepts and regulatory bottlenecks for stakeholder and actors.

3

1.3 Method Based on the existing research and developments on smart grids, this report aims to present market

concepts applied on smart grids and regulatory bottlenecks in nowadays EU regulation for smart

grids. The report includes:

A description of the development for all market actors from current market framework to

smart grids

Identifying new requirements that smart distribution system put on the electricity market

A state-of-art review of the research that presents market and regulatory solutions to meet

these new requirements

A case study on regulatory bottlenecks in some EU countries with a deeper review of the

Swedish regulation

1.4 Outline In the second chapter, the current electricity market concept is described with clear definitions of

each market actor. Detailed responsibilities for the actors are distinguished. Furthermore, an

overview of the electricity market structure and network regulation is presented.

In the third chapter, expectations of what a smart grid can handle are identified and explained. The

main expectations that are considered in this report are the integration of distributed renewable

energy resources, the need for increased demand response among the consumers and the expected

introduction of electric vehicles.

The fourth chapter identifies market concepts and regulatory bottlenecks for the integration of

distributed renewable resources. The chapter also presents a state-of-art review on the solutions to

solve the regulatory bottlenecks.

The fifth chapter provides a state-of-art review of market concepts and regulatory issues regarding

demand response and integration of electric vehicles into the electric power system.

In the sixth chapter the conclusions for chapters one to five are presented. The discussion covers all

the aspects that will be reviewed in the following case studies of the EU and Swedish regulations

presented in chapters seven and eight.

In the seventh chapter, an investigation of 18 EU countries is performed.

In the eighth chapter, a deeper analysis into Swedish regulation is presented.

Chapter nine concludes the report and identifies needs for future studies.

4

2. Electricity market structure and current regulatory framework This chapter defines electric power system, electricity market along with all its actors and regulation.

2.1 The electric power system The electric power system in this report refers to a large system from generators to household users.

Such power systems have a hierarchical structure, as shown in figure 2.1. A power system is used for

transferring electricity from generators to consumers. The whole network can roughly be divided into

transmission system and distribution system according to nominal voltage levels. In the transmission

system, the range of voltage is from 1000 kV to 22 kV, and in the distribution system the voltage is

from 22 kV to 0.4 kV (7). As shown in figure 2.1, most large generators are connected to the

transmission system, however, a few power plants, for example, wind farms are connected directly

to the distribution system. The cross-border connections also appear on the transmission level.

When the network extends closer to consumers, the voltage will go down to distribution levels. Large

consumers like industries will connect to higher voltage distribution systems or transmission systems,

while the majority of consumers will connect to lower voltage distribution systems.

Figure 2.1 Hierarchical structure of electric power system (7)

2.2 Electricity market Figure 2.2 presents an overview of an electricity market structure with some important actors. On

the left side, the actors in the physical electric system are represented. These are producers,

5

Transmission System Operator (TSO) , Distribution Systems Operators (DSOs) and consumers. The

TSO and the DSO manage the operation of the transmission and distribution systems, respectively.

On the right hand side the financial view of the system is represented. The buyers that consume

electricity buy it from retailers who have bought the electricity through electricity trading on the

wholesale market (8). The electricity that is produced by the producers is sold on the wholesale

market by sellers. Wholesale market structures vary between countries. In all EU countries electricity

wholesale markets can be distinguished as centralised and bilateral electricity markets (7). In a

centralised electricity market, the sellers have to submit their sale bids to a central power pool,

which is managed by the system operator. At the same time, retailers also submit their purchase bids

to the power pool. In a bilateral electricity market, the tradings do not have to go through a power

pool, all players sell and purchase freely, but transactions must be reported to the system operator

(7).

The physical deviations in power system are compensated by automatic control systems and actions

of the system operator (7). It is presented as physical balance responsible party (BRP) in figure 2.2.

However, the finacial adjustment is done later by balance responsible party (BRP). MO stands for

market operator. A market operator is responsible for operating the electricity trading and the

physical BRP are responsible for ensuring that the frequency and voltage level in the grid is kept

constant. The finicial BRP is responsible for dividing the cost according to the physical balancing of

the system.

Producers

TSO

DSOs

Consumers Buyers

Retailers

Wholesale MO

(Power pool &/

Bilateral market)

Sellers

PhysicalBRP

FinicialBRP

Declare constraints to

Report schedule to

Ope

rate

Send

sch

edul

e &

prov

ide

bids

Control Send

schedule

MWh

€

MWh

MWh

€

€

Figure 2.2 Physical and economical structures (9)

6

2.2.1 The actors and their responsibilities

In this section the main actors and their roles are defined.

Producer:

Producer means a physical or legal person generating electricity and having contracts for the right to

produce electricity (10). It is the beginning of the power flow chain shown in figure 2.2.

Grid operators (GO)

The grid operators are responsible for operating, building, maintaining and planning the electric

power transmission and distribution grid (10). They ensure the availability of all necessary system

services. The grid operators can be separated into Transmission System Operators (TSO) and

Distribution System Operators (DSO) depending on voltage level of the grid they are operating.

1) TSO

A TSO is responsible for operating, ensuring the maintenance of and, if necessary, developing the

transmission system in a given area and for ensuring the long-term ability of the system to meet

reasonable demands for the transmission of electricity (10).

2) DSO

A DSO is responsible for operating, ensuring the maintenance of and, if necessary, developing the

distribution system in a given area and for ensuring the long-term ability of the system to meet

reasonable demands for the distribution of electricity (10).

Consumer: A physical or legal person that consumes electricity and contracts for the right to

consume (10).

Seller: A party that offers bids to power exchange.

Buyer: A party that purchases electricity from retailers.

Wholesale Market Operator (MO): Market operator is in charge of the actual delivery of energy and

receives the bids from all actors that have a contract to bid (10).

Retailer: Entity selling electrical energy to consumers – could also be a grid user who has a grid

connection and access contract with the TSO or DSO (11 p. 6).

Balance Responsible Party (BRP): Ensures that the supply of electricity corresponds to the anticipated

consumption of electricity during a given time period and financially regulates for any imbalance that

arises (11 p. 6). All actors who participate in the electricity trading do not have to be balance

responsible, since it is possible to transfer the responsibility to another actor (7).

Besides the definitions of the actors some other definitions are relevant for the continuation of this

report.

Supplier: The supplier has a grid connection and access contract with the TSO or DSO (12 s. 6). A

supplier in one context can be a buyer in the other context.

7

Ancillary service: Ancillary services are interconnected operations services identified as necessary to

support a transfer of electricity between purchasers and sellers (13 p. 4). There are generally three

types of ancillary services. The fist type is active reserve services also referred to frequency control

since active power has a strong relationship with frequency. The active reserve services are used to

balance supply and demand in the event of a sudden and unexpected disturbance of the system.

There are three levels of services based on the reaction time: primary control which reacts in 5-30

seconds; secondary control which is available in less than 5 minutes; and finally tertiary control which

is active after more than 15 minutes. The second type of ancillary service is the restoration service,

which is the so called black start capability. The generators that can offer this service are generators

which are able to start delivering power without assistance from the power system. The third and

last type of ancillary service is voltage control, or reactive power control since voltage on a node has

a strong link to the reactive power flow through that node. This service aims to maintain a specific

voltage level and to generate or absorb reactive power (14).

Regulator: Independent body responsible for the definition of framework (market rules), for setting

up system charges (tariffs), monitoring the functionality and performance of energy markets and

undertaking any necessary measures to ensure an effective and efficient market, non-discriminative

treatment of all actors and transparency and involvement of all affected stakeholders (11 p. 7).

Aggregator: An aggregator will be a new actor in the smart grid market model (15). An aggregator is

an organization that consolidates a number of individual customers and/or small generators /or small

energy entities into a coherent group of business actors (16).

2.2.2 The interaction between physical power flow and electricity market

Generators have four important characteristics that have an impact on the electricity networks:

capacity, controllability i.e. the response time with which they can react to changes in demand,

availability i.e. the frequency and duration of scheduled and unscheduled outages, and finally voltage

control (which is also called reactive power generation) (12). Producers can take advantage of these

properties by selling ancillary services to the grid operator. Since not only generators have the ability

to control reactive power flow and special storage equipment can store active power, some other

energy entities can also offer some ancillary services. As shown in figure 2.2, the TSO gathers

information from producers plus transmission line parameters to declare constraints to the

wholesale MO. In real-time, the TSO controls the physical balance responsible actors to ensure

power system balance.

2.2.3 Electricity trading

The electricity generation and consumption should always be instantaneously the same to ensure a

reliable power system, but the payment cannot be performed in real-time. The solution is to

introduce trading periods, the duration of which can be chosen arbitrarily (7). From the time domain,

power exchange can be illustrated as in figure 2.3.

8

Figure 2.3 Timeline of electricity market (17)

The electricity trading is divided into several steps, as the actors in the electricity market do not know

exactly how much electricity will be traded during a certain trading period. In the first step, called

forward market, the actors buy and sell as much as they think they need. The forward market takes

place from a few years ahead to a few days ahead. The next step, called spot market, contains three

different markets: the day-ahead market, the intra-day market and the real-time market. In the day-

ahead market, which is as the name says only one day ahead, the production schedule is determined.

During the day, there is an intra-day market to reschedule generation and consumption. The real-

time market takes place after the intra-day market. The energy balance between generation and

consumption is ensured and prices are set. Finally is the ex-post trading, during that the BRP is

responsible for the financial adjustment to ensure that the actors are paid for all the energy they

have supplied to the grid and are paying for all the energy which they have been extracted (18).

2.3 Regulation ensures the proper network and market activities Electricity network is not appropriate to have it in a competitive market; therefore it is a typical

natural monopoly. This means that the cost of building parallel grids would be significantly higher

than the possible price press that would be the result of competing grids (7). From this perspective,

regulation is needed to avoid market failures. One of the main intentions of regulation is to realign

the prices to marginal costs in order to make monopolist produce an output at the socially preferred

level (19). Hence, consumer interests are protected. Regulation is also needed to increase monopoly

efficiency, since there is no pressure from competitors for monopolist to innovate. Furthermore, the

wholesale market and retail market also need clear rules to maintain a competitive environment

(14). For example, regulator must ensure that there is non-discriminatory access to transmission and

distribution system for producers and suppliers. However, it is also important that the regulating

authority weighs the interest of the customer against the possibility of the regulated part to get a fair

return on invested capital (10). The benefits of the regulatory system have to be larger than the

administration costs.

As shown in figure 2.4 there are three main areas for electricity system regulation: to ensure

reasonable prices, high quality of supply and well-functioning markets.

9

Figure 2.4 The scope of electricity system regulation (20)

The price of services offered to customers and or the profit for the regulated company has to be

considered in the regulation (21). Regulators have to recognize the importance of regulated service

providers recovering sufficient levels of costs. Failure to include adequate costs as part of the

revenue requirements may discourage investments and deteriorate quality of supply (14).

Quality control has to define requirements for continuity of supply, technical quality and commercial

quality (14). The continuity of supply is handling the reliability of the electricity supply and can be

measured with performance indicators on number of interruptions and duration of interruptions.

The technical quality can be measured with parameters such as voltage or frequency variation. The

customer service is also an important parameter on how the monopoly actor performs (14).

The third area to be considered is that whether the market is functioning well. How to form the day-

ahead market and balancing market as well as issues around congestion management all need to be

regulated. The system planning and operation are under regulation to avoid monopoly misbehavior.

Other regulated areas mainly include the power system unbundling requirements and cross-border

issues on the transmission system level (14).

2.3.1 Price control

Revenue or price control can be done in some different ways depending on what effects the

regulator wants to achieve. Different sub areas in price control are setting revenue requirements,

price/revenue adjustments, efficiency assessments and tariff design.

Revenue requirements

Revenue requirements are usually calculated by the following formula (14):

Revenue requirements = OPEX+ Depreciation + (RAB * Rate of Return) (1)

The OPEX stands for operating expenditures, which can be divided as controllable and non

controllable. Only the controllable part is exposed to efficiency analysis (14).

Depreciation here means to systematically allocate the capital expenditures (CAPEX) over the period

in which the asset provides benefits to the regulated company. Depreciation can be calculated by

using straight-line method and accelerate-method based on CAPEX. Straight-line method that

allocates equal amounts of depreciation to each accounting period of the asset life is widely used

10

(21). The accelerated method allocates decreasing amounts of depreciation to each accounting

period of the asset life, and is more complicated to use than the straight-line method.

The RAB stands for regulatory asset base, which consists of the assets used to provide the regulated

services. Typically, the RAB is based on the depreciated value of fixed assets and may include

allowance for net working capital. Capital contributions from customers, government and third

parties are usually excluded from the real regulatory asset, but this differs between countries (14).

The rate of return is based on the weighted average cost of capital (WACC), and describes the return

on the regulatory asset base that the regulated company is permitted to earn.

Price/revenue adjustments

Price and revenue adjustments can be achieved by several methods such as price control formulas

and use of adjustment factors as, for instance, productivity increases or prices (14). The length of the

price control period also affects the strength of the incentive to cut costs (15).

Efficiency assessment

Efficiency can be assessed by using outputs over inputs plus some corrections. When applying

efficiency assessments, the performance of the company is compared to the performance of other

companies or models (14). The results will transfer into the price control formula. One option is to

implement the efficiency assessment as a linked cap regulation, for example a sliding scale scheme

(14). Another option is to implement it as unlinked cap or yardstick regulation, for example quantity

terms in the price control formula, explicit investment allowances or inefficiency caps (14).

Tariff design

Tariff design includes the design of tariff structures, for example, how to charge for using the

network, connection fee, energy transmission, etc. It also covers cost allocations such as how to

differentiate for voltage levels, location, time of use, etc (14). The possible levels of differentiation of

tariffs are showed in figure 2.5.

Figure 2.5 Possible levels of tariffs (22)

11

2.3.2 Quality of supply

Quality control ensures that the customers get deserved services and that they receive acceptable

quality. The acceptable quality includes the reliability of electricity supply and the physical properties

of electricity. The number and frequency of interruptions can be used as performance indicators for

the reliability of electricity supply; the voltage variation, flickers and so on are the performance

indicators for the physical properties of electricity.

2.3.3 Market functioning

The scope of market functioning covers the areas: market rules, system/network rules, market

monitoring and security of supply (14). To keep a functioning electricity market, the market rules

have to define how the trading shall be organized. This has to cover how the day-ahead market

works, how to balance the market and how to manage congestion. The system/network rules have to

cover things as the planning conditions, connection conditions, system operation and metering

requirements (14). Market monitoring covers factors as compliances and competition monitored

together with analysis on market behavior and performance. According to security of supply the

regulator, for example, has to control that there is adequate generation capacity so that the supply

and demand is balanced. The network development process and operation security are also

important issues (14).

12

2.4 Methods of regulation This section introduces the regulatory methods that are used for price control and quality of supply.

An overview on these methods is presented in figure 2.6.

Regulation methods

Price control Quality of supply

Rate-of-return

(revenue-/price-)Cap regulations

Yardstick

Sliding scale

Minimum performance

standards

Indirect quality controls

Incentive schemes

Cost-based regulation

Incentive regulation

Figure 2.6 Overview of regulation methods (14)

2.4.1 Price control

The regulator has to consider if the regulation should act ex-ante or ex-post (21). Ex-ante regulation

means that the regulator in advance decides what costs are to be accepted. Ex-post regulation is

when the cost are accepted or decided to be refunded to the consumers afterwards (21). For the

DSO the ex-ante regulation is preferable because it removes the uncertainty if the investment will be

accepted or not (15). But the ex-post approach is in some cases hard to totally avoid and this

approach is also suitable if there exist an asymmetry in the information between the regulated part

and the regulator (21). In practice, there is not a regulation approach that only uses either ex-ante or

ex-post regulation. There is more a mixture where some parts in the regulation are regulated ex-ante

and other parts ex-post (15).

Cost-based regulation

There are some different approaches to cost-based regulation such as rate-of-return regulation and

cost-plus regulation. The typical rate-of-return formula is:

(2)

represents allowed revenue in year t. is the operating costs in year t, depreciation in year t,

represents taxes in year t, represents the regulatory asset base in year t and is the

allowed rate-of-return in year t. In general, cost-based regulation aims to let the DSO charge the

customers for all expenses plus a rate of return. It is the regulator that decides the size of the rate of

return, and thereby also controls the revenue for the company (21).

By using cost-based regulation the regulator does not focus on the tariffs. Instead the focus is on that

the return of capital for the DSO is kept at a reasonable level. This method has drawbacks as it gives

13

no or low incentives for cost reduction. The reason for this is that in its basic form cost-based

regulation allows the DSO to transfer his costs to the consumer. There is also a risk for

overcapitalization with cost-based regulation (21).

Applying cost-based regulation is often done with short regulations periods (14). An advantage of

cost-based regulation is that it is easy to apply even if the regulated company has a large information

advantage against the regulator (21).

Incentive regulation

1) Cap regulations

Cap regulation is built on that an upper limit on price or revenue is decided for a period of 3-5 years.

The limit is in its most basic form, which is a function of the cost at a base year corrected for inflation

minus a productivity growth factor (also named X-factor) (14).

Price control or price cap regulation aims to set a price limit on each service that the company offers

the customers. This gives the DSO incentives to achieve cost reduction because it will increase the

profit. Cost reduction can sometimes be done by quality reduction and by that there is an indirect

incentive for quality reduction (21). A price cap regulation is usually formulated as:

(3)

where is the price cap for service i in year t, I is the inflation rate used to adjust for general price

inflation, and X is the efficiency factor represents productivity growth. The inflation rate can be

estimated as retail price index (RPI) or consumer price index (CPI).

Revenue cap regulation sets a cap on the allowed revenue instead of the price. This makes it possible

to refund revenue that are too high to the customer or recover more if the revenue was lower than

the system allows (21). With revenue cap regulation the customer prices can be changed during the

regulation period. A revenue cap regulation is usually formulated as:

(4)

where is the authorized revenue in year t, CGA represents customer growth adjustment factor

(currency unit/customer), is yearly variation in number of customers (23). I and X have the

same meaning as explained in formula (3). The product of shows that the changes in

customers are considered, however, in some documents this part is not included in the revenue cap

regulation formula.

Although the two cap regulation schemes create similar incentives to lower costs, price cap

encourages higher sales to increase the profits, which gives little incentive for them to encourage

customers to save energy. On the contrary, revenue cap regulation makes it possible for the DSO to

increase profits by decreasing output and increasing prices.

2) Yardstick regulation

In Yardstick regulation the limit on price or revenue is set by an average performance in the total

sector the DSO is operating in. The regulator can with the yardstick regulation create an artificial

competition between different DSOs even if they do not compete for the same customers (21). It

14

provides strong incentives to improve efficiency; however, there are few cases of practical

application (14).

3) Sliding scale

Sliding scale regulation compromises between cap and rate-of-return regulation, it makes sure the

profits and risks are shared between company and customer. It is formulated as:

(5)

Where is the sharing parameter, is the actual profit in the previous year and

is the “fair”

profit determined by regulator for previous year. and

can also represent other items like

investment costs (14).

This scheme can help overcome the informational advantage of the system operator over the

regulator, like in the case of linked caps where the regulator relies on the investment forecasts by the

system operator (14).

Regulatory price control methods comparison

Table 2.1 summaries the regulatory price control methods.

Table 2.1 Comparison on regulatory price control methods

Model Advantages Disadvantages

Rate-of-return

Effectively encourage investments Lower risk for the regulated company Easy to apply

No or low incentives for cost reduction Frequent regulatory reviews Customers carry the risk

General for cap regulation

Longer regulatory period Gives the DSO an incentive to reduce costs

Parameters are set in advance

Price cap Regulate the prices directly Incentives for quality reduction if the reduction can reduce costs Encourages higher sales to increase revenue

Revenue cap Can give incentive to energy efficiency on the consumer side

The price would change

Yardstick competition

Introduces an artificial competition between the DSOs and it provides strong incentives for efficiency

Too few practical experience in electricity sector

Sliding scale Helps to overcome information asymmetry

Too few practical experience in electricity sector

2.4.2 Quality control

Price control methods offer small or even in some cases negative incentives for quality

improvements. This makes it necessary to implement some other regulation that gives quality

incentives. These methods can be divided into Incentive Schemes, Minimum Performance Standards

and Indirect Quality Control.

Today quality regulation mainly focuses on the areas commercial quality, continuity of supply and

voltage control (24). To be able to measure the quality regulatory authority has to define quality

indicators. Common quality indicators in use today for continuity of supply are SAIDI, SAIFI and ENS

15

(25). European Regulators Group for Electricity & Gas (ERGEG) proposes that this approach can be

extended to include other areas that the regulators want to promote such as smart grid

functionalities (25). It is possible to use methods such as incentive schemes, minimum performance

standards and indirect quality control to promote desired performances that otherwise would be

disfavored in the regulatory model.

Minimum Performance Standards

This means that a minimum standard is set and for each time the company does not fulfill the

standard sanctions are taken (14). For example, the sanctions can be rebates on the tariff or

compensations that have to be paid directly to the affect customers. Other sanctions could be fines

(14).

Indirect quality control

Indirect quality control does not have a direct financial impact on the DSO. It could be measures such

as that the regulator put requirements on the DSO to provide sufficient information to the customers

and the public (14).

Incentive Schemes

Incentive schemes build on the regulators formulating quality targets for the quality indicators. If the

DSO performs better than the target the company will be rewarded in some way and if the DSO

performs worse than the targets they instead get a penalty. The reward could be that the DSO is

allowed to increase their revenue (14).

16

3. Expectations on smart grid There are many different definitions of smart grids available. In this report the European Energy

Regulators’ (ERGEG) definition presented in (2) is used. ERGEG defines smart grid as:

“Smart Grid is an electricity network that can cost efficiently integrate the behavior and actions of all

users connected to it – generators, consumers and those that do both – in order to ensure

economically efficient, sustainable power system with low losses and high levels of quality and

security of supply and safety.” (2 p. 18)

According to ERGEGs Position Paper on Smart Grid (2009) a smart grid is expected to facilitate (25):

I. Integration of distributed energy resources in the medium and low voltage grid

II. Changing customer behavior such as an active demand side

III. Integration of large scale renewable that are located on greater distances from load centers

and/ or strong grids

IV. Reduction of losses

V. Increasing self healing characteristic

These five requirements that a smart grid should be able to facilitate are described in more detail in

this section.

3.1 Integration of distributed energy resources in the medium and low

voltage grid Integration of Distributed Energy Resources (DERs) in the low and medium voltage distribution grids

puts new requirements on these grids. The DER is “a combination of distributed generation (DG),

storage of electrical and thermal energy and/or flexible loads. DER units are operated either

independently of the electrical grid or connected to the low or medium voltage distribution level of

the main network. They are located close to the point of consumption, irrespective of the technology,

but are smaller than 10 MW of electrical power” (16). The well-accepted definition of DG made by

Ackermann (2001) is used here “Distributed generation is an electric power source connected directly

to the distribution network or on the customer site of the meter” (19 s. 1). Since the type of

generation is not clearly defined, it can contain all types of generation technologies based on fossil

fuels and Renewable Energy Sources (RES) (16).

The distribution grid is traditionally built for distributing energy from the transmission grid down to

consumers. The balance between production and consumption is handled on transmission level. This

puts a limit on the amount of production that can be connected to the distribution grid. When

dealing with the DER it is very important to keep in mind that most of the DER has intermittent

nature. Ignoring this nature of DERs could lead to decreased stability and reliability of the system

(26).

To handle significant amount of generation in the distribution grid, local power balance will be

required. An alternative is to upgrade the grid for two way transmission of energy between the local

grid and superior grid. A local power balance need some form of a local balance responsible party

and tools such as demand response via price incentives, direct load and production control and

maybe local storage capacity.

17

3.2 A changing customer behavior There are expectations on that the consumption of electricity will increase in the future when new

areas such as personal transports and heating with heat pumps will consume more electricity. These

new products bring some new challenges to be handled in the sense that consumption increases and

consumption patterns may change.

An expected increase in electricity consumption brings a potential increase in peak load which gives

new challenges for the distribution system. One approach is to move some of the consumption from

peak time to periods with less demand. This would reduce the need for an increased capacity in the

distribution grid. Reduction in peak consumption can be achieved in different ways. Demand

response, where a price incentive is sent to the consumers to reduce their consumption during peak

time, plus active load control by the grid operator are two ways to cut peak demand (27). Integration

of energy storages to the system in some cases also can be used if the cost for storing energy is lower

than increasing the transmission capacity to the area. In some cases integration of distributed

generation can be a way to reduce the need for an increased transmission capacity. However, this

requires that the distributed generation production is available during peak time. The new types of

consumption also put other demands on the network. For example, there will be a need for charging

infrastructure around the electric vehicles.

3.3 Integration of large scale renewable energy resources The integration of large scale renewable energy resources puts some demands on the electricity grid

and the market. For large scale renewable energy resources (RES) such as wind farms, one problem is

that the production might be available in areas where the grid is too weak to handle it. There is a lack

of transmission capacity. Another problem with large scale renewable resources is that the

production is intermittent in time (28). To be able to handle this, the transmission capacity in parts of

the transmission grid and in some parts of the distribution grid has to be upgraded. There are also

requirements on the balance of the system, which results in a need for either energy storage or

balance capacity. The time intermittent production can be partly handled with demand response and

energy storage in the smart grid concept.

3.4 Reduction of losses and increasing self healing characteristic Reduction of losses requires better control and monitoring of the whole system. To be able to reduce

the losses in the system there is a need to integrate renewable energy resources near the consumers

to reduce the transmission distance. Both reactive power and voltage control can reduce the losses

in the system. Reactive power control has earlier mostly been applied in the transmission grid but

with the smart grid concept it is expected to be applied also on distribution level (29). Voltage control

is one other ability that smart grids is expected to provide. Instead of keeping the voltage at a high

constant level which is set to provide the consumer with an acceptable voltage level at peak load, the

voltage can be controlled in relation to the actual load (29) (30).

For self healing characteristics to work, control and monitoring of the system as well as new

components that can sectionalize the grid and redirect the transmission in case of a failure in some

parts of the grid are needed. Island operation is also a desired ability for a smart grid in order to

achieve supply security.

3.5 The focus of the report

18

Further on in this report the main focus will be on the first two requirements on smart grids:

integration of distributed energy resources in the medium and low voltage grid, and changing

customer behavior both related to active demand management and the integration of electric

vehicles. The report will look at market models for these areas and regulatory bottlenecks related to

them.

19

4. Market related and regulatory issues concerning integration of

distributed energy resources This chapter starts by presenting market concepts and regulatory bottlenecks related to the

integration of Distributed Energy Resources (DER). The chapter ends with a state-of-art review on

how to solve the identified regulatory bottlenecks.

4.1 Market concept—new opportunities With the aid of smart metering system and DER, many new actors will enter the electricity market.

Since consumers in distribution grids can produce electricity to the network, some consumers will

become “prosumers” which was firstly predicted in 1972 by Marshall McLuhan and Barrington Nevitt

in their book “Take Today”. Additionally, small-scale industrial and commercial producers and

residential customers will need a third party that can take advantage of their flexible characteristic so

that they can participate actively in the electricity trading with reasonable profits. An aggregator will

be a new actor in the smart grid market model (15). An aggregator is an organization that

consolidates a number of individual customers and/or small generators /or small energy entities into

a coherent group of business actors (16). The aggregator aggregates energy production from

different generators. However, note that the aggregator is not a supplier; he has a contract with a

supplier (11).

More actors have the ability to produce electricity, which means the traditional wholesale and retail

markets face competitors. And more actors have the ability to control consumption or production,

which means that the traditional way to get ancillary services requires changes. A new business

structure under smart grid is shown in figure 4.1, which is based on today’s electricity market

structure presented in Chapter 2. The arrows in the figure 4.1 represent the cash flows. Since an

aggregator would have enough capacity to enter the wholesale market and provide ancillary services,

there is a possibility that it becomes a new actor who is involved in the electricity trading. However,

there is hardly any support found in literature for this. Therefore it is a dashed line in figure 4.1

between the aggregator and wholesale market operator module.

In figure 4.1, it can be seen that the aggregator is the key mediator between the consumers and the

markets and other power system participants (31). The main functions of the aggregator are also

defined in project ADDRESS (31):

It gathers the flexibility capacity from its consumers

It aggregates the consumers’ loads and uses them to form active demand (AD) products

It collects the requests and signals for AD-based services coming from the markets and the

different power system participants.

Both the aggregator and the consumer have devices that display the price and volume signals as well

as some individual load consumption (31). These devices can be embedded into smart meters.

20

seller

Electricity trading

Retailers

Ancillary services

DER unitsConsumer

Prosumer

Aggregator

€

Figure 4.1 Interaction of actors in smart electricity market

The products offered by the aggregator are identified in (31 s. 6):

Scheduled Re-Profiling (SRP). The aggregator has an obligation to deliver the specified power

shape during the specified delivery period; this means that the product delivery is effectively

“scheduled”.

Conditional Re-Profiling (CRP). The power delivery associated with the product has to be

“triggered” by the buyer based on a pre-agreed power volume range to be delivered by the

aggregator. In other words, the buyer and the aggregator agree on an available capacity that

the buyer can choose to call or not when the time comes.

Bi-directional Conditional Re-Profiling (CRP-2). It is similar to the normal CRP, but it allows for

adjustments in terms of demand reduction or of demand increase. It can be argued that a

bidirectional flexibility product is simply the combination of two unidirectional ones with

their appropriate calling conditions. However, in order to reduce transaction costs, it may be

more reasonable and practical to allow for bidirectional flexibility.

4.1.1 Wholesale market

In most electricity markets, electricity is traded in a wholesale market which is regulated on the

transmission level. Transmission line congestion can result in local market areas which increase the

possibility of market power; however, distributed generation can reduce market power (32). It is

recommended in (33) that some form of congestion pricing should be implemented both at the

21

transmission and at the distribution level, preferably in the form of nodal spot price. According to

this recommendation, the wholesale market operator will need to update the pricing scheme.

There are some limitations for aggregators getting access to the wholesale market. One is that they

are not able to provide the minimum tradable volume, the other is the costs to access the market are

too high for their business. It also explains why there is no clear defined relation in figure 4.1

between the aggregator and wholesale market.

4.1.2 Retail market

Retailers can enlarge their service area by gathering the flexible production and consumption

capacity. At the same time aggregators who can provide similar services as retailers, the competition

in retail market would increase, which would lead to an increase in quality of services.

4.1.3 Ancillary services

Distributed energy resources are able to provide different ancillary services (AS) (34). As the level of

penetration increases, it is possible to procure ancillary services from the neighborhood regime

instead of centralized ancillary service markets at transmission level. An investigation in (35) shows

that controllable DER units and controllable loads can provide all types of ancillary services. And it

also shows that a large number of technologies are available to support network operation by using

the Virtual Power Plant (VPP) concept. Since distributed energy resources have the capability to offer

ancillary services, the owners of them or the operators of them (the service providers mentioned

before) have the ability to participate in ancillary service market once they obtain the accesses. In

contrary to conventional balance responsible parties which are on transmission level, DER operators

are on distribution voltage level. Moreover, instead of receiving all ancillary services from TSOs, DSOs

would also be active in the balancing system as mentioned in previous section. The actions of all

ancillary service suppliers will affect others, which require that all generators on different voltage

levels must cooperate well with each other in operation.

In Electricity Directive 2009/72, it is suggested that the demand side may provide necessary ancillary

services. In order to allow distributed energy resources to effectively participate in the ancillary

service markets, TSOs should extend its control to the distribution level (34). And DSOs should be

given the authority to purchase ancillary services in the market, which requires TSOs and DSOs to

share the responsibility for the provision of ancillary services (34).

22

4.2 Regulatory bottlenecks In this section the regulatory bottlenecks for integration of DER are investigated. The main focus is on

how to give incentives to both DSO and consumers for accelerating the DER integration, as well as

from the system’s perspective to integrate DER in an efficient way.

Regulatory arrangements are related to the revenues and costs of the DSO, which are shown in

figure 4.2.

Conncetioncharges

UoScharges

DSOrevenue

Innovation&Expansion &

Reinforcement

UoScharges

AScharges

Energylosses

O&Mcosts

Environmentcosts

CAPEX

OPEX

cost

€

€

€

€

€

€

€€

Figure 4.2 Revenue and costs of a DSO (36)

The costs for a DSO can be divided into two separate categories: operational expenditures (OPEX)

and capital expenditures (CAPEX). CAPEX includes investments in network assets for network

innovation investment, expansion and large-scale reinforcement. OPEX includes costs like use of

system (UoS) charges to TSO, ancillary services (AS) costs, energy losses, operational and

maintenance costs of assets. Only the costs that can be controlled by the DSO are displayed, some

costs such as consequential depreciation costs and remuneration of debt are not covered. In this

report, it is considered that environment standards put requirements on DSOs in order to incentivize

them to make environmental-friendly decisions. Figure 4.2 only displays the DER-related revenue for

DSO. As well as all network users, DER operators have to pay network tariffs to compensate DSOs for

the costs incurred as a result of their integration, which can be identified as connection charges and

UoS charges (36).

Electricity distribution system is a typical natural monopoly. Hence it is regulated in many ways. The

DER-related regulation includes the network tariff design, network innovation investment, electricity

quality such as continuity of supply, energy losses and environmental effect, and DSO’s revenue.

4.2.1 How to motivate the DSO to connect DER

23

Integrating DER into distribution system has a strong influence on DSO’s costs both CAPEX and OPEX.

Connecting DER to the distribution grid poses new challenges on network planning, operation and

control (34). DSOs are naturally risk averse to make investments on immature technologies (34).

Therefore, the DSO has a lack of incentives to conduct R&D in network innovation. At the same time,

the DER significantly changes the characteristic of the load, so network planning should be based on

a new network profile to optimize network expansion. DER result in that the power could transfer

from lower voltage to higher voltage network, sometimes the current grid is not fully capable to

handle. For example, the protection system is not designed to allow DERs. Nonetheless, the network

must be reinforced to handle a large integration of DER both on distribution and transmission level.

Therefore, CAPEX will increase.

Furthermore, the connection of DER affects distribution system energy losses (34). Whether this is a

negative or positive impact on the DSO’s OPEX generally depends on the DER penetration level (36).

For low DG penetration (below 20%) energy losses are reduced thanks to the fact that generation is

nearer to the load and electricity goes a shorter way to the consumer (36). Moreover, as the revenue

diminishes over time the reward for innovation may decrease, while the risk inherent in innovation

projects remains high (33). In (36), it was shown that increasing DG can either be favorable for DSOs

or not depending on other parameters, such as revenue regulation, environmental regulation and

load growth dynamics.

The two general types of price control regulations: cost-based and incentive regulations, which were

introduced in Chapter 2, both have weak effects on innovation. Theoretically, cost-based regulation

would enable DSOs to conduct R&D as their additional costs would be immediately reflected in

higher tariffs. However, it gives them no incentives to do so since any cost saving arising from R&D

would directly lead to lower tariffs (21). There are no additional profits arising for them. On the other

hand, incentive regulation shifts the focus from R&D inputs to innovation outputs, which may lead to

more effective and efficient R&D (34). However, this shifting also increases the risk for the DSO (37).

Moreover, a pure cap regulation may lead to underinvestment for DSO (34). It is still unknown to

what extent incentive regulation can promote innovation by itself (34). Hence, some specific

regulatory measures to explicitly compensate DSOs should be designed. The regulatory challenge is

to design a regulatory mechanism to take into account all these aspects.

4.2.2 How to motivate consumers to equip DER

As shown in figure 4.2, the two main incomes for the DSO from DER are connection fee and UoS

charges. The regulatory challenge is to make consumers willing to install DER, and the first

preliminary is that the DSO should integrate DERs in a non-discriminatory manner by appropriate

connection charges.

Connection charges are paid just once when a user requires network access to compensate for the

costs of connection. While UoS charges are periodically paid by network users, including consumers

and also generators in some EU Member States (34). UoS charge will be discussed in 4.2.3.

Connection charges can be computed from a shallow way to a deep way. Under deep charging all the

costs and benefits associated with the connection of a DER unit, including upstream network

reinforcements, are included. Deep charges require precise knowledge on the additional costs or

benefits of a connection to the network, as well as clear rules on sharing them among the users of

the system (34). While under shallow charging, only the direct costs of the connection from the plant

24

to the network are compensated by the DER owners (33). It is obvious that shallow charging would

attract more connection of DER. On the other hand, deep charging can provide incentives for more

optimal and cost-reflective localization of DERs. However, in contrast to shallow charges, deep

charges are more complicated to implement (34). In most cases in the EU, it is the DSOs that

determine the connection charges (34). Since there is still a lack of evidence that the advantages of

DERs exceed the disadvantages, a trade-off exists between DSOs and DER owners. Also, deep

charging implies different charges for different DERs as they have different impact on the system,

which would lead to discrimination among DER owners (38).

4.2.3 Promote the connection from system’s perspective

As mentioned earlier, the current power grid is designed for one direction power flow which is from

upper voltage levels down to consumers along the transmission and distribution lines. With the

increasing integration of DER, it will have considerable impact on operation, control, protection and

reliability of the existing power systems. Several potential problems for larger integrating DER have

been reported in literature (voltage control, rapid voltage changes, thermal limits of branches, short

circuit currents, protection tripping etc) (39). To promote an efficient integration of DER while

minimizing its potential problems, a new quality regulation can be adopted. The quality regulation

aims to assure that an adequate quality is maintained when DER connection increases.

UoS charges come from cost incurred to provide the network user with the network transport and

system services. The design of it would affect the DERs behaviors. Properly designed economic

signals can lead to a more efficient operation of DERs and the whole system, therefore the

integration is facilitated (34). Currently, consumers pay for this part of charges, but there is no clear

rules for DER owners. Some DSOs charge for DG, such as Finish and Romanian DSOs (34).

Integrating DER in the distribution system has a large influence on network planning which includes

network expansion and necessary reinforcements. DER are able to replace network investments. This

is due to the fact that DER are connected close to consumers or even on their side of the meter, thus

reducing the net power flow in the grids (34). This also explains the possibility that integration of DER

reduces the energy losses in the system. In countries where CAPEX is a passed through cost, network

expansion and DG connection efficiencies should be regulated. But it is difficult to design a regulatory

mechanism to take into account this possibility, which facilitates the integration from both DSO’s and

DER’s perspectives. A new economic regulation for DER’s access will be prepared in the EU regulation

(34).

25

Summary for regulatory bottlenecks for integrating DER

The parts in the regulations that have an impact on DER integration are summarized in table 4.1.

Table 4.1 Impacts of integration of DER

Impacts Comments

DSO

Increase CAPEX It may make the DSO hesitate to connect more DER depending on how CAPEX is treated in regulation

Energy losses It can increase the OPEX, which may make the DSO hesitate to connect more DER depending on how OPEX is treated in regulation

Decrease environment costs The impact depends on the regulation regards environment issues

Consumers Connection charge The charging method effects consumers’ motivation to become prosumers

The system New quality indicators Accelerate the development while assuring the quality

UoS charge It affects network efficiency

Reduce network investments This value is hard to be recognized by DSOs, it has impact both on the DSO and DER

Reduce energy losses at certain penetration level

This value is hard to be recognized by DSOs, it has impact both on the DSO and DER

26

4.3 Solutions to regulatory bottlenecks This section presents state-of-art solutions of the regulatory bottlenecks identified in the previous

section.

4.3.1 Price-regulation/revenue-regulation

Implementing incentive based regulation for DSOs costs is strongly recommended (34). Otherwise,

the incentives for an efficient integration of DERs would be weakened. But incentive regulation by

itself is insufficient to ensure an adequate integration of DER, further steps ought to be taken (34). A

possible scheme for cost regulation is formulated in (33). In the scheme the investment budgets for

each DSO are allocated at the very beginning of a regulatory period. At the end of the regulatory

period, the DSO should inform the regulator on the carried out network investments and other

expenditures. This scheme belongs to ex-ante regulation since the remuneration is agreed before the

costs really happen. It leaves all system optimizing decisions completely up to DSOs. Efficiency gains

on appropriate investments, for instance, investment in DER integration in order to postpone

network expansion or reinforcements, will be recognized to the DSO as an allowed profit in that

period. This scheme can limit the risk that grid users need to pay too much because of DSO’s

inefficiency. In practice it can be very expensive to regulate ex-ante the total costs as regulators have

to assess the efficiency of implemented actions (34).

As explained earlier, high levels of DER penetration can have a negative impact on CAPEX and OPEX.

But the added value of DERs with respect to deferral of grid investments is significantly positive (36).

Although there is no ‘one size fits all ’ solution for neutralizing the negative impact of DER

penetration on DSO’s revenue, an alternative regulatory arrangement based on a combination of the

impact on operation expenditures and capital expenditures is suggested in (36). According to (36) the

most successful regulatory improvement is formulated as1:

(6)

where the first component of the equation is the same as the first component in the tradition cap-

regulation formula, y is the RAB allowance, which is the share (in percent) of eligible DER related

investments in distribution network assets, is the total eligible DER related investments in

distribution network assets in year t, and F is the allowance based on the electricity supply of DER.

The product of y compensates for the negative impact of DER penetration on RAB, and the

product of shows a direct revenue driver for integrating more energy production from

DER. However, y should be less than 100% so that an economic incentive remains to limit these

investments (36). The value of y should be designed according to the specific system. Case studies in

(40) shows that when DER penetration is very high, there will be an overall negative impact on the

DSO. In order to avoid unnecessary allowances, a gradual compensation rule on RAB allowances

should be implemented. This gradual compensation means that the value of y will decrease as the

DER penetration increases. Furthermore, F is a direct revenue driver on energy production or

connecting capacity. This part remunerates the negative impact on OPEX. However, a minor

‘overcompensating’ in DSOs’ favor might happen (36). This overcompensation may effectively act as

an explicit incentive to facilitate additional DER connections to the network (36).

1 Joode, Jansen, van der Welle and Scheepers. 2009. Increasing penetration of renewable and distributed

electricity generation and the need for different network regulation.

27

The most sophisticated revenue driver seems to be a driver that accounts for all connected kW of

DER capacity as well as for all kWh of DER electricity fed into the grid (36). It is recommended in (41)

that DSOs are compensated for those incremental costs by an upgraded revenue cap regulation2:

(7)

where the first component of the equation is the same as the first component in the tradition cap-

regulation formula , and are the unit increments of DSO revenues due to the connection of DER

capacity and DER energy injection, respectively.

The numerical experiments carried out in (40) justify that should be stable, while should

increase with the DER penetration level. Obtained numerical values are in the range of 1-3€/kW for

and 0-3.5€/MWh for (41). However, since the impact of DER depends greatly on the overall

level of penetration, the specific values for revenue drivers should be determined under each

country regulatory framework.

In (38) five approaches of how to take the costs of DERs into account in the network regulation are

suggested. These five different approaches are presented below:

1) Full cost-pass through

This mechanism is based on incentive regulation by adding an adjustment factor z. z is an indicator

that is outside the incentive regulation scope, and is used to allocate risk between the DSO and the

customers (38). It is formulated as following3:

(8)

where z represents the costs of DER connections. If z is 100% of the costs, the risk is fully passed over

to the customers. The z-factor can be identified according to a forecast made at the beginning of

each regulatory period and corrected at the end. An alternative is to set the z-factor ex-post on an

annual basis which means it is determined at the moment the cost incurs or at the following

regulatory review.

The drawback of this mechanism is that if DSOs can simply pass through any DER-related costs they

incur, they do not carry any risk. As a result, this approach gives poor incentive for efficient

connection. The z-factor and the reported costs of connection should be supervised by regulators.

2) Volume-related revenue driver

Instead of adding the actual costs declared by DSOs into the calculation introduced previous, a fixed

volume-related driver is set. In (38) only a variable related to the amount of connected power is

investigated. This can be changed to other variables that regulators want to control. The formula for

volume-related revenue driver is4:

(9)

2 Frías, Gómez and Rivier. 2008. Integration of Distributed Generation in Distribution Networks: regulatory

challenges. 3 Bauknecht and Brunekreeft. 2008. Chapter 13 Distributed Generation and the Regulation of Electricity

Networks 4 Ibid

28

where y is an average compensation for each kW connected DERs set by the regulator.

The greater costs of DER connection under the revenue setting level, the higher are the additional

profit of DERs for the DSO. Therefore, the DER connection is motivated. Furthermore, DSOs will try to

reduce the connection costs for a larger extra profit. Under such scheme, the DSO will try to improve

coordination with DER operators, like labeling the network costs at various connection points (38). In

other words, this scheme can provide location signal and make the connection charge more

transparent.

However, it is difficult to establish an appropriate value for y. With a too low y value, it will not be

sufficient for the DSOs to encourage DER connection; in the contrary, with a too high y value, there

will be lack of incentive for the DSOs to reduce the connection costs. Additionally, y can be designed

in order to differentiate among DER types, sizes and location. This scheme may prevent some DER

projects with above-average connection costs, which could make an overall benefit for the system

(38). This would be negative when the overall benefit exceeds its costs.

3) A combination of a partial pass-through and a supplementary per kW revenue driver

This approach is just a combination of the pass-through and volume-related revenue drive methods.

Since DER costs are very case sensitive and very few experiences exist, it is even harder to decide

both variables. The UK has been using this hybrid incentive.

4) A combination of cap regulation and benchmarking

With this approach additional costs of DERs which are not included in the cap regulation are

controlled by comparative efficiency analysis. Because it is difficult to classify what drives the

network-related costs, hardly any country has implemented this way yet.

5) A combination of cap regulation with a menu of sliding scales

A well-known theory on information asymmetry is an incentive compatible mechanism. An incentive compatible mechanism triggers the agent to reveal the costs truthfully. Such a self-selection incentive scheme is very suitable in regulating DSOs, as the regulator does not know the real costs of network investments. It can be applied to DSOs revenue control and is formulated as5:

(10)

where y is the average revenue for installed DER-capacity (€/kW), Q is the quantity of connected

DERs, b (0<b<1) is a parameter which determines the sliding scale, z is not only the costs of DER but

does also include the benefits with an opposite sign. In contrast to the formulas in equations 6 to 9,

equation 10 does only apply to the revenue due to DERs. It can be seen that is the revenue cap

and z would be negative since the benefits of DERs would exceed the related costs. It is obvious that

if b=0, the regulation is full cost pass-through while if b=1, it is a full price-cap. To make this incentive

compatible mechanism work, b should be chosen by the DSO and y should be set by the regulator as

an increasing function of b. An appropriate choice of y(b) should fulfill the incentive compatibility

constraint and does not necessarily bear a relation with costs. DSOs who know the DER connection

costs will optimize revenue by themselves and thereby reveal their real costs. DSO reveals its real

5 Bauknecht and Brunekreeft. 2008. Chapter 13 Distributed Generation and the Regulation of Electricity

Networks

29

cost is the aim of the incentive compatible mechanism. The DSO who selects a low b reveals that the

DER connections caused relatively high costs and thereby the DSO prefers a low cap and high-cost

pass-through, vice versa.

The results of the above seven approaches are proportional to the length of regulatory period and

also dependent on the adjustment from one period to the next period (15). Six of them which have

been implemented in practice are displayed in the table 4.2.

Table 4.2 A comparison of revenue regulation schemes

Formula and parameters Advantages Disadvantages

1)

y is the share of eligible DERs related investments in distribution network assets;

is the total eligible DERs related

investments in distribution network assets in year t;

F is the allowance based on the electricity supply of DERs

Less risk for the DSO to connect more DER;

F provides a direct revenue driver on energy production

A minor ‘overcompensating’ in DSOs’ favor might happen which means some other actors will pay for this.

2)

and are the unit increments of DSO revenues due to the connection of DER capacity and DER energy injection, respectively

It provides the DSO drivers both for connected capacity and electricity generation

A minor ‘overcompensating’ in DSOs’ favor might happen which means some other actors will pay for this.

3)

z represents a share of the costs of DER connections. If z is 100% of the costs, the risk is fully passed over to the customers

The DSO and DER share the risk of connection

It gives poor incentive for efficient connection which costs lower than average level.

4)

y is an average compensation for each kW connected DERs

DER connection is motivated to increase the DSO profit;

Improve the efficiency of connection;

Improve coordination with DER operators

It is difficult to establish an appropriate value for y;

DSO would be shortsighted.

5) It overcomes the problems of simple cost

It is even harder to decide z

30

z represents the partial costs of DER connections;

y is an average compensation for each kW connected DER

pass-through while balancing various objectives and incentives.

and y.

6)

y is the average revenue for a kW-connected DERs ; y should be an increasing function of b

Q is the quantity of connected DERs;

b (0<b<1) is a parameter which determines the sliding scale;

z is not only the costs of DERs but does also include the benefits with an opposite sign

It overcomes the information asymmetry between regulators and DSO

It is hard to decide an appropriate choice of y(b), which should fulfill the incentive compatibility constraint and does not necessarily bear a relation with costs

Summary of the six revenue regulation schemes

The first five formulas have the similar structure that combines a revenue cap regulation with a DER

incentive component. There are two ways to put the capacity incentive into the revenue cap

calculation; one way is to add an allowance parameter multiply by the quantity, such as .

The other way is to add a share to the related investment, such as z and . The way to increase

the generation from connected DER is to add a direct revenue driver like . The last

formula limits the attention to DER only. The DSO can decide how much cost it wants to pass through

and how high the revenue cap will be, so it reduces the risk for the DSO and is incentive compatible.

Which method to choose depends on the system situation and the energy policies. Incentives for DER

can be performed by other means than to change the revenue cap regulation formula. For example,

it can be done by adding quality regulation, or by adding incentives when calculating the revenue

requirement.

4.3.2 Tariff design

It is recommended in (33) that shallow connection charges can provide efficient long-term incentives

and localized incentives should be reflected through those charges. However, it should be mentioned

that this is not only the charges that influence the localization of a DER unit; there are many other

local factors that are affecting the choice of location.

In (34) it is recommend that negotiation between DSOs and DER owners or operators ought to be

avoided to prevent conflicts. It is proposed that UoS charges should be implemented for DERs. These

should be considered as an instrument to send efficient economic signals to DERs. Efficient UoS

charges ought to include differentiation per location (voltage level, electricity consumption trend)

and time of use in order to better reflect the actual value for the system. The value of DERs for the

system can be negative or positive, which implies that UoS charges also can be negative and positive.

For example DERs can save costs when producing at local peak demand time since the transmission

31

losses decrease and voltage can be kept under standards; on the other hand, DERs can cause

additional losses due to their intermittent nature.

It is also suggested in (34) that UoS tariffs must be unanimous with the whole regulatory framework

in each country. The design of UoS tariffs should take into account other factors, such as government

support mechanisms and connection charges. The interaction with the support mechanisms is

crucial. For instance, feed-in tariffs or premiums can be used as a complement or a substitute to

obtain the same results in countries where generators do not pay network tariffs by law. In most

countries DG does not pay UoS charges, only consumers pay those (34). Implementing UoS charges

for DG is not advisable unless conventional generators pay them too (34). Properly structure of UoS

charges must take into account the particular features of distribution networks, such as different

voltage levels, areas of distribution, metering devices capabilities, planning criteria and quality of

service requirement (42).

Shallow connection charging

In (43), shallow charging refers to cases where the DER operators simply pay for the cost of the

equipment to make the physical connection to the grid at the chosen connection voltage. Hence, DER

operators pay no contribution towards any upstream related network reinforcement. The related

network reinforcement costs can be covered by other tariffs. Therefore, a fair and transparent

mechanism for the tariff system to recover those costs is needed. One advantage of this method is

cost transparency and consistency for DERs regardless of location. Nevertheless, this gives poor

location signals to the DSO which is unfavorable for the DSO’s network planning and operation.

Deep connection charging

Deep charging relates to the cases where DER operators bear the full cost of connection and network

upgrades elsewhere in the distribution network (36). Using this charging method, there is no need

for DERs to pay UoS tariff. But the connection costs can be prohibitive due to the possibility of

discrimination to DERs and the upstream network may involve transmission lines (43).

Mixed connection charging

A mixed charging method is that the DER owner bears the cost of the physical connection to the grid

plus a share of upstream network reinforcement costs (43). This method requires fair dictate to

decide the share caused by that DERs. By mixing shallow and deep in different percentages, there are

a number of charging options. The European Local Electricity Production (ELEP) Project Team (43)

has following recommendations for the EU Member States:

1) Fully transparent interconnection procedures, connection charging mechanisms and

connection costs. Annual connection charges shall be published and subject to regulatory

approval.

2) Connection charging for DERs should follow a shallow charging philosophy.

3) DSOs are required to submit binding connection quotations to DER operators, including cost

apportionment proposals for reinforcement works, within 60 days of application.

4) Prospective DER operators have the access to relative network technical parameters in order

to facilitate the optimal placement.

5) Regulatory bodies within Member States are given the responsibility for arbitration, in

conjunction with the power to impose changes to connection charging costs and practices

where necessary.

32

6) If grid network reinforcement is necessary following the connection of a new DER scheme,

and in case where pure shallow connection charging is not considered acceptable, it is

suggested that:

i) The DER operator is required to make a percentage financial contribution towards

upgrade costs, which is derived from new power capacity relative to the capacity of the

local grid network following reinforcement. And the costs shall be limited to those

incurred at the voltage level of connection point.

ii) The proportion of the reinforcement costs that is not paid by the DER operator is

covered by DSOs, and DSOs are allowed to pass it to customers through tariff system.

iii) The calculation method used by DSOs should be the cheapest technically acceptable

solution and should be made public.

iv) Pure shallow charging shall apply for very small DER operators.

v) If the upstream network has been reinforced by the previous DERs, a new DER should be

charged in the same apportionment methods described above.

33

The three tariff design methods are compared in the table 4.3.

Table 4.3 Summary of connection charging methods (43)

Charging

method

Brief description Advantages Disadvantages

Shallow Generator pays only for the cost of

equipment needed to make the

physical connection to the grid.

Any upstream costs of the grid

reinforcement resulting from the

connection of the generator are

the responsibility of the DSO (often

recovered through UoS tariffs).

Lowest cost approach

for DER owners;

Cost transparency and

consistency regardless

of connection point

Poor location signals;

May cause project

delay since the

reinforcements may

be needed before

connection;

DER plants likely to be

subject to UoS

charges

Deep The generator pays for all costs

associated with its connection.

This includes the cost of the

physical connection to the grid

along with the costs of any

upstream network

reinforcement work arising from

the connection of the generator.

Generally there is no

requirement for DER

owners to pay ongoing

UoS charges;

Provides strong

location signals

(arguably)

Network

reinforcement costs

are often uncertain

(lack of transparency);

A single generator can

end up paying for

reinforcements

caused by other

generators

Mixed A hybrid of the shallow and deep

charging methods. The generator

generally bears the cost of the

physical connection to the grid

network (the shallow costs) plus a

proportion of any upstream

network reinforcement costs. The

proportion of these costs paid by

the generator is usually based on

an assessment of the proportional

use of any new infrastructure by

the generator.

The generator’s

network reinforcement

costs are a function of

the generator’s usage

of the new connection

assets;

Provides some location

signals to generators

The rules to calculate

the “proportion of

costs” must be clear;

May cause project

delay since the

reinforcements may

be needed before

connection;

DER owners may have

to pay UoS charges

34

Use of system (UoS) charging

It is proposed to implement UoS charges for DER, because UoS charges can send DER operators

efficient economic signals (34). In order to better reflect the actual cost or benefits for the system, a

new method for UoS charging based on marginal investment pricing concepts is proposed in (44). It is

important to note that the fundamental assumption with this charging method is that the optimal

capacity of network components is driven by demand. This may not always be the case as there are

other drivers such as losses (44). It is also very important to keep in mind that UoS tariffs must be

consistent with the whole regulatory framework in each case (34). For example, if the connection

charge method already considers the location signal, UoS tariff design does not have to consider it

again. The interaction with the support mechanisms should also be taken into account. There are

many details that should be considered to properly design distribution UoS tariffs, such as different

voltage levels, level of penetration, areas of distribution, metering devices capabilities, planning

criteria and quality of service requirements (34). The details can be found in (42). Only the general

charging method is presented in this report.

Since generators and demand have opposite effects on the system, both positive and negative

charges are considered at the same time in the method. It is recommended by (45) that generation

and consumption from the same site are treated independently, because their footprints are

different and often complementary. The method can be explained generally by figure 4.3. The

illustrated system is a part of a radial medium voltage (MV) distribution network to which several

distribution transformers are connected. The distributed generators connected to the first low

voltage (LV) feeder are assumed to be micro-CHP plants and those connected to the second LV are

PV. The metering feeders (MF) are annually read. The power flow in MF1 shows the time of year

when the maximum flow occurs with an orange bar. The charges for the use of the MF1 will be

defined by the contribution of each of its connected customers and generators to that flow. In this

example, the customer contributes to the critical flow by consuming 1.6 kW, so it will be charged for

the use of the feeder. On the other hand, the micro-CHP reduces the critical flow by 1 kW, this

generator will be paid. Moreover, the charging method can also take the location into account. An

illustration of how this method is working in practice when considering location and time of use is

given in (44).

35

Figure 4.3 Bi-direction UoS charging (45)

36

4.3.3 Recommended performance indicators

After integrating DER into the grid, the power quality faces challenges. At the same time the

efficiency of the system is expected to improve, so some changes should be made in performance

indicators. Regulation should not only think about the current grid, it should consider for the further

development. For example how much the potential is to connect more DER. In order to motivate the

DSOs to plan the grid in favor for a smart future, ERGEG has proposed a list of performance

indicators in 2009 considering the improving efficiency and power quality as well as the further

development. And in “Position Paper on Smart Grids- An ERGEG Conclusions Paper” (2) the revised

list of effects and benefits and potential performance indicators for each benefit in smart grid is

presented. Here some of the performance indicators relevant to DG connection are shown in table

4.4.

Table 4.4 Recommended performance indicators (2)

Effects/benefits Potential performance indicators

Adequate capacity of transmission and

distribution grids for integration

Hosting capacity6 for DER in distribution grids;

Allowable maximum injection of power without

congestion risks in transmission networks;

Energy not withdrawn from renewable sources due to

congestion and/or security risks.

Enhanced efficiency and better service

in electricity supply and grid operation

Level of losses in transmission and in distribution

networks;

Ratio between minimum and maximum electricity

demand within a defined time period;

Percentage utilization of electricity grid elements;

Availability of network components and its impact on

network performances;

Actual availability of network capacity with respect to its

standard value(e.g.net transfer capacity in transmission

grids, DER hosting capacity in distribution grids)

6 Hosting capacity describes how much dispersed generation can be connected to a power system without

resulting in unacceptable reliability or voltage quality for other customers (39)

37

5. Market related and regulatory issues concerning a changing

consumer behavior This chapter focuses on two effects of a changing customer behavior; demand response and

implementation of electric vehicles.

5.1 Requirements and market solutions for demand response Demand response is connected to the expectation that the consumers react to price incentives from

the market (46). Expected benefits with demand response are a reduced need for standby capacity

for peak electricity demand (47) and a possibility to reduce peak power load in the distribution grid

(46) (48).

The consumer has different types of loads depending on the activities behind it. One type of load is

time dependent such as the load due to lighting and cooking while other types of load is more easily

shifted in time such as washing machines and charging of electric vehicles (49). There are three ways

for the consumer to control the consumption:

Reduce the load during peak time by avoiding using electricity, e.g. switching off the light

Apply energy efficiency measures such as changing to low energy lamps

Time shift the consumption e.g. running the dishwasher during off peak time

It is possible to communicate price incentives to the consumer through the electricity bill (indirect

control) and by contracts between the consumer and an actor (direct control). In contracts the

consumer can offer the actor a specific energy use pattern or the ability to remote control some of

the customers’ load directly.

5.1.1 Drivers and markets for demand response

Markets for demand response products can be spot market and ancillary service markets. Actors that

can use demand response services are the DSO, retailer and BRP. The electricity price that faces the

consumer consists of taxes, the electricity price and the distribution fee (tariff).

The electricity price is an agreement between the retailer and the consumer. The retailer buys the

electricity on the spot market or in a bilateral agreement and this puts a limit of what price the

retailer can offer the consumer. The price that the retailer has to pay for the electricity depends on

the demand and supply. In most of the European electricity markets the price is set on an hourly

basis but the price the retailer offers the consumer is by technical reasons mostly on monthly basis or

for even longer time periods (50). This disconnects the price incentives in the wholesale market from

the retail electricity market. Thus, the price incentives for shorter price periods than monthly

averages never reach the consumers who are the ones capable to react to them (50). The unbundling

between the retail market and the spot market makes the retailers demand curve on the spot market

insensitive to high peak prices (50).

The grid owner has an incentive to stimulate a reduction in the peak power use by consumers. The

reason for this incentive is that the DSO often has to pay a fee for peak power use to the TSO (47). So

a reduction of the peak power use in the grid will reduce this cost. At the same time a reduction in

peak power use in the grid can reduce the need to strengthen the grid (47) as the peak power puts

38

the requirement on the grid capacity. The distribution losses also increase with the load on the grid

(46).

5.1.2 Market solutions to achieve demand response

With smart metering functions in place, market models that can couple the wholesale market and

the retail market must be developed. These models have to consider the different actors’ needs such

as the retailers’ need for more price sensitive demand side and the need for some consumers to have

stable prices. Also the DSO can sometimes need an active demand side. In the long run there might

even be a demand for smaller consumers to participate on the ancillary service markets, for example

through an aggregator described in Chapter 4.

This section provides a review of market models for active demand side at the consumer side

followed by a review on how they have been set into practice.

Retail price models for demand response

Different price models exist that include different levels of price incentives to the consumers. Five of

the price models are: the Fixed price, Time Of Use/Seasonal price, Two part Real Time Pricing, Spot

price with a cap and direct spot price (50).

The first price model, Fixed price, is where the consumer and the retailer agree on a fixed price for a

certain time period. With the second price model, Time Of Use (TOU) or Seasonal contract, the

consumer and retailer agree on different price for different time periods (51), e.g. one price for night

time and one price for day time. This contract gives some price incentives to the consumer to adjust

his consumption according to the retailers cost situation which should reflect the supply and demand

situation on the spot market (51). This price model encourages the consumer to do load shifting and

schedule their consumption out of the expected market patterns that occurs (52). TOU pricing can

also be used in combination with Critical Peak Pricing (CPP) that implies that the retailer can increase

the price during short periods when the spot price peaks (50). This gives a more dynamic pricing and

even higher incentive to the consumer to adjust the consumption to the supply.

The third price model is the two-part real-time pricing (RTP). In the RTP concept, the consumer

subscribes for a fixed consumption and deviations from that consumption is paid by the spot price

(50). The subscripted consumption can be based on consumption profile estimated for the consumer

(53). This model both gives the consumer a good protection from high risks according to price peaks

and at the same time it passes price incentives from the market to the consumer (46).

In the last two price models the retailer and the consumer agree on a contract by which the price is

set to be the spot price with a price cap at some level or to be a spot price without price cap (50).

This price model gives the consumer the whole risk and also an opportunity to optimize his

consumption to the price fluctuations. The model also requires that the consumer is active and

follows the price variations and is mostly suitable for consumers with high amount of controllable

loads (52). Table 5.1 presents a summary of the five price models.

39

Table 5.1 Different price models for the retail market

Model Function Comments

Fixed price The consumer gets a fixed price per kWh

This price model is the traditionally dominating one. It offers the consumer a contract with a known electricity price. At the same time the retailer is exposed to a high risk

TOU/Seasonal The consumer gets different price for different time periods

This price model offers the retailer a possibility to send a price incentive to the consumer when the retailer wants the consumption to decrease. But the retailer is still the one that bears the risk for fluctuations in the price

Two-part RTP The consumer has an agreement implying a fixed price for a certain energy use profile and that deviations from this profile is paid by the spot price

This model gives the consumer a security for the base consumption and has at the same time incentives to reduce the consumption when the price is high

Spot+cap The consumer gets a price that varies with the spot price but there is an agreement of some kind of cap that protect the consumer from too high costs

This model reveals the price fluctuations for the consumer but still the retailer covers some of the risk

Spot The price follows the spot price on the day ahead market

In this price model the whole risk is taken by the consumer. This model suits consumers with high consumption flexibility

CPP The retailer have an agreement with the consumer that the price is allowed to be increased during short time periods a few times per year

This agreement is often used in combination with one of the first three price models above and offers the retailer a possibility to use the consumer’s flexibility during critical peak load

In the first five price models mentioned in table 5.1 there are different levels of price risk exposure

for the consumer and the retailer. For example, in the fixed price the retailer takes most of the

financial risk for a fluctuating electricity price. For doing this, the retailer will probably require a risk

premium that is included in the price. On the other hand there is the direct spot price where all the

risk is put on the consumer. A direct spot price may be favorable for consumers that have a lot of

controllable loads. Figure 5.1 shows how the risk is divided between consumer and retailer for the

described price models.

40

Figure 5.1 How different price models divide the risk from the spot market between consumers and retailers (50)

There is also another way to achieve demand response; the retailer or the DSO can offer the

consumer a contract where the consumer let them control some of his load against a payment (50).

Tariff design for consumers in a smart grid

The market models for grid tariffs that this report focuses on aim to reduce the peak load in the

distribution system. There are some different tariffs in use or tested such as Fuse based tariff, Time

based tariff, Dynamic time tariff and Power based tariff.

Fuse based tariff is a common used tariff that has three price components. One component is based

on the installed fuse capacity that set a limit on peak power capacity available. The second

component is commonly a static fee that that is the same for all users. The third component is a fee

based on consumed energy (54). This tariff form does not offer any incentives to reduce electricity

use during periods of peak load.

Time based tariff is similar to TOU price. The energy component of the tariff is set for different time

periods (54). This has been a common tariff in the past for households with electric heating. The tariff

was then lower during off peak period such as night and higher during daytime (48).

Dynamic time tariff can be described as CPP where the energy component in the tariff can be raised

during period of high peaks (54). This tariff type can be combined with other tariff models.

Another tariff is Power-based tariff where the consumer has to pay a price component based on his

peak power demand (48). Using this tariff structure the consumer gets an incentive to reduce the

peak power use and thereby a reduction of the overall peak power use in the system can be

achieved. This tariff structure does, however, not give any possibility for the DSO to send incentives

during critical load situations (54).

To reduce peak load on the distribution grid also a direct control of load at the consumer side can be

adopted (54). This gives the DSO a possibility to reduce the load during peak time and can be

combined with the retailer’s demand of reducing electricity use during peak prices. Table 5.2

presents a summary of the different tariff models.

41

Table 5.2 Different types of tariff models

Tariffs Function Comments

Fuse based tariff The tariff has three components. One fixed price, one price component based on the quantity transmitted energy and one installed fuse size

This tariff does not offer any incentives to reduce electricity use during periods of peak load.

Time based tariff Often same as for Fuse based tariff with the exception that the energy volume price could be set to different level for different time periods

A common tariff in the past for households with electric heating. Give the DSO a possibility to show the consumer when the cost is expected to be high

Power based tariff The consumer has to pay a price component based on the peak power demand

The consumer get an incentive to reduce the peak power use

Dynamic time

tariff

The energy volume component in the tariff can be increased during period of high peaks. As for CPP this model is used in combination with another model

This tariff gives the DSO the possibility to give the consumer incentives to reduce the power use when it is most effective

Direct load control services

Micro grid and active house are concepts where automatic control, information and communication

technology is used. The concept covers houses where the technology is used to optimize the

consumption to a time intermittent production unit and the electricity price so the consumer can

optimize the use of the facility. The concept also covers big clusters where consumption, storage and

production are optimized out of different incentives such as in the virtual power plant earlier

mentioned.

This concept is expected to provide the possibility of different services. An active house can provide

services as automated response to price signals, possibility for island mode, load shedding (55),

optimizing consumption to local production units and controlling the production and storages after

demand (56). These houses can be clustered together to provide services such as participating in a

balance responsible party’s portfolio to act as a controllable load and production unit that can be

used to reduce the risk related to time intermittent RES (57). These clusters can also offers services

to handle local congestions for a DSO as they provide the opportunity of peak load reduction and

control of controllable DG as CHP (57). Other services that can be offered with these concepts are

voltage control and load shedding (31). These services can be aggregated by a third party (an

aggregator) to make them more available and the volume higher. But there is also vision that these

clusters can be used to optimize energy use within a local area between different prosumers where

they trades energy and services between each other on the grid (58).

Services as mentioned above that are aggregated can also be offered in already existing markets as

day ahead, intraday market, real-time market and ancillary service markets. The product will then

build on that the aggregator can provide a controlled deviation from the forecasted level of demand

(31).

42

Ancillary service markets as primary regulation has characteristics that make it attractive for

controllable loads. Characteristics such as that the economical payment is high for these services, the

duration time is short (10-30 minutes) and the signal for activation is already provided through the

frequency in the grid, make primary regulation interesting for actors with controllable loads and

production (52). The problem for aggregated units to enter these markets is related to the costs for

metering and verifying the deliverance of the service (59).

Usually regulation power is purchased by the TSO from BRP. However, there are other ways to

deliver these services. In a smart grid with active houses and other flexible components with

controllable loads, production and storages it is possible that these components can be programmed

to react on the actual frequency in the grid (59). The problem for these loads to enter the market is

to find a business model where the service can be sold to the TSO in an efficient manner. There is

research on this area in Denmark (59) (60) and one proposed solution is that the TSO would accept

bids or contracts based on the aggregated capacity and statistical availability of the components. In

New Zealand, water heaters are used for this purpose and the capacity is aggregated by the DSO and

bidden to the TSO for the behalf of the consumers (52). These types of services can also be

interesting for a DSO during controlled island mode (59).

5.1.3 Case studies of demand response

There have been many different tests and demonstration projects concerning demand response in

the world. In this section some findings in the more recent studies are presented. Case studies on the

impact of price models are presented and direct load control field test are reviewed. Finally, there

are some conclusions about the importance of communicating information to the consumers.

The effect of different pricing models and enabling technology

Farqui and Sergici (61) have summarized 15 field experiments in the US that were carried out within

the time period of 1997 to 2007 (except for one program that is still running). They investigated the

impact that TOU, CPP and PTR7 have on the peak electricity consumption. Table 5.3 presents the

result of this study. As shown in table 5.3, TOU pricing gave a consumption reduction of 4 % during

peak periods while CPP gave a reduction of 17 % in average. There can also be seen that different

enabling technologies, such as two-way programmable communicating thermostat equipment that

allow consumers to have remote control of their load give an even higher reduction. CPP with

enabling technologies gave a reduction in peak demand between 27-44 %.

The reduction in peak demand depends on the price difference between peak and off peak period

that faces the consumer. The California's Statewide Pricing Pilot found that a peak to off peak price in

the range of 2:1 gave a peak demand reduction in the range of 5 % and a ratio between 5:1 and 10:1

gave a reduction between 8-15 % (62). The study also concluded that factors like climate zone,

season, air conditioner ownership and other user characteristics affected the demand response of

the consumer.

7Peak Time Rebate (PTR) is a pricing where the consumer gets a compensation for all reduction the

consumer do during peak time compared to a baseline.

43

Table 5.3 Effects on peak load by different pricing models (61 s. 43)

Rate Design Number of

Observations

Mean 95 % Lower

Bound

95 % Upper

Bound

Min Max

TOU 5 4 % 3 % 6 % 2 % 6 %

TOU w/Tech. 4 26 % 21 % 30 % 21 % 32 %

PTR 3 13 % 8 % 18 % 9 % 18 %

CPP 8 17 % 13 % 20 % 12 % 25 %

CPP w/Tech. 8 36 % 27 % 44 % 16 % 51 %

In a recently finished program named PowerCentDC (63) three dynamic price models were compared

between July 2008 and October 2009. The price models in the program were CPP pricing, a sort of

PTR and one type of hourly spot prices based on the day-ahead market. In this program the peak

price to off peak price ratio was nearly 7:1 and the peak reduction for CPP was 34 % during summer.

For the PTR scheme the reduction was around 13 % and for the spot price the reduction was 4 %. The

CPP and the PTR resulted in the same reduction size as the results presented in table 5.3. However,

the reduction with a spot price model was lower than what was expected in the project. This is partly

because that the project was running during the recession and the price was constantly decreasing

during the test period.

Herter et al (64) performed a project with remote control of Air Conditions and CPP for 78 small

commercial customers during the summer 2008. The group consisted of restaurants, offices and

retail shops with a peak to off peak ratio of 7:1. The project had also an energy saving education

program and resulted in a peak demand reduction of 14 % (20 % excluding the Restaurants) and an

energy saving of 20 %. Herter came to the conclusion that small offices and retail shops appeared to

be good candidates for energy efficiency and demand response programs.

For the moment there is a running program with spot pricing in Illinois (US) that was initialized as an

incentive by the Illinois legislature by a law that requires Ameren Illinois and ComEd to offer

residential consumers hourly price (65). This is done under the Power Smart Pricing program.

According to (66) the real time pricing program in Illinois and Gulf Power's CPP program is probably

the two longest and still running programs with dynamic pricing in the US. The Illinois program has

been running in different forms since 2003 and both of the programs is still running and offers a

broad range of dynamic pricing to the consumers. Gulf Power offers all consumers that fulfill some

requirements a CPP rate with a peak to off peak ratio of 16:1 (67). CNTenergy is publishing

evaluations and information about the Illinois dynamic pricing program on their homepage (68).

In Sweden the grid company Göteborg Energi and the retailer Din El have conducted a field study

between winter 2007- and spring 2009 (54). In this field study both direct remote control of electric

heating and heat pumps were tested as well as indirect control by electricity pricing. The price model

that was used in the field study was called “fixed price with right to return” which is a two-part RTP

price model. The grid tariff that was used was a fixed price grid tariff. Both the direct remote

controlled consumers and the indirect controlled consumers had the same grid tariff and electricity

44

price model and thus had incentives to adjust their consumption patterns. The consumers that were

remote controlled also received an allowance of 500 SEK for the service they provided. All consumers

had access to a web portal where the electricity price was presented. This study concluded that it is

possible to remote control heating system during peak periods without causing discomfort for the

consumers. Furthermore, the study concluded that the consumers that were indirect controlled were

more active to change their consumption patterns compared with the ones that were remote

controlled. One other finding was that the consumers also wanted an easier system to get the price

information than to log on to a web portal.

The power-based tariff model is the grid tariff design model that differs the most from the other

price models presented. This one is in use by the Swedish companies Sollentuna Energi and Sala Heby

Energi for private consumers in Sweden. They have a power-based tariff where one part of the tariff

builds on an average of the three days with highest peak power use during the month (48). The

power component at Sala Heby Energi is 89 SEK/kW winter months and 24 SEK/kW summer months

(69). Sollentuna Energi has a power component of 80 SEK/kW winter and 40 SEK/kW for summer

month (70). To get the price for this component, the average peak power use is multiplied with the

price per kW. As can be seen in table 5.4 the biggest different between the two companies is the

summer power component.

Table 5.4 Power based component in grid tariff introduced in Sweden for consumers with a fuse below 63 Amps (autumn 2010)

DSOs in Sweden with power component in grid tariff

Winter power component Summer power component

Sala Heby Energi 89 SEK/kW 24 SEK/kW

Sollentuna Energi 80 SEK/kW 40 SEK/kW

According to Pyrko (71), Sollentuna Energi 2004 estimated that the power-based tariff had reduced

the need for new investments with 5 %. But experience from this project is that the consumers find it

difficult to understand the tariff (71). Furthermore, Pyrko draws the conclusions that the

implementation of power based tariff and together with remote reading systems can be beneficial

for the grid company. He also points out that it is important that the consumers get information on

the system and how it works.

Power-based tariffs have also been applied for commercial customers by some grid companies such

as Malungs Elnät AB (72) and is planned to be adapted by Fortum in Sweden and Finland (73). The

company Göteborg Energi is planning to introduce power-based tariffs for all customers from 2012

(73).

Italy is one of the first European countries that have rolled out smart meters. In Italy all DSOs have to

offer the consumers a grid tariff with the possibility to subscribe for 1.5, 3.0, 4.5, 6.0, 10 or 15 kW.

The installed meters are constructed with the feature to cut the supply to the consumer if the

consumption exceeds the subscription (74).

The Italian metering system is built to handle time differentiated tariffs with a minimum of 4 price

levels. The meters should also support the possibility that the retailer and the DSO have different

45

time interval settings. This feature is for the moment in use for all consumers connected to the

regulated electricity market (74).

Direct load control

The main areas for direct load control have been air conditioning systems and heating systems. There

are other electrical appliances that are of interest for control such as residential water heaters (75),

ventilation in commercial buildings (54) and charging of electrical vehicles (48).

Different possible markets for services connected to load control exist. In France, for example, there

has been a project with aggregators running. In this project the aggregator aggregated loads to an

accumulated size of 10 MW or more and by that was allowed to put bids on the ancillary service

market (76). The project raised a problem with aggregators. The problem occurs when an aggregator

had consumers that belonged to different BRPs and concerned how to compensate the BRP (48).

Another market is, as mentioned earlier, the possibility for the DSO to use remote controlled loads in

order to control the peak load. The DSO would thereby reduce its losses and also the size of power

transmission capacity it has to subscribe (54).

The participation of the users

In many case studies the users are often offered a web based interface where they can get

information about their historical use and the electricity price. But the users are often requesting

more readily available information than that (54). Other communication interfaces that have been

used are energy lamp (50), displays on smart devices, SMS, email and smart phone applications. The

energy lamp is a lamp that displays different color depending on the electricity price.

In many of the programs using CPP or spot prices the consumers would receive warnings at high

price events. It was in these programs concluded that it is important that the numbers of event days

a year are not too many. The consumers also often wanted to set up routines for how to act and then

stick to them even if the price does not give high incentives for the decided behavior every day (54).

One other parameter is education of the consumers. This education can, if it is promoted in the right

way and done properly, promote the consumers to participate in a program as payment or lower

fixed charges (64).

Concluding this section, factors affecting the way the consumer react to dynamic pricing are:

Level of risk exposure in the pricing model

Magnitude of the price fluctuation

Education level

Arability of consumption and price information

Available control equipment

5.2 Bottlenecks for demand response As described above there are some preconditions for demand response. A metering system, which

can provide the necessary information for economical settlements between the consumer and the

actors that are using the consumer’s services, is needed. Then there also is a need for price

incentives that make it favorable for the consumer to participate in the process. These price

incentives consist of a price difference between peak and off peak time and depends both on the

46

electricity price, transmission cost and taxes. One more precondition for an active demand side is

enabling technologies as visualization equipment and different load control technologies. These

technologies can, as earlier described, also provide new services to the system. However, there are

some potential hinders for these services to access the market.

The following sections discuss questions regarding metering system, market access for new services

and hinders for fluctuating prices to reach the consumer.

5.2.1 Deployment of smart metering system

The metering system is one of the key factors for demand response. To achieve demand response

the electricity price must be communicated to the consumers and consumption must be measured

with a sample rate sufficient for the purpose (48) (50). ERGEG has recommended that the sample

rate for smart metering system should be of minimum hourly basis. ERGEG also concluded that for

energy efficiency services and peak load management services an even higher sample rate would be

required (77). In the same report ERGEG also conclude that time of use registers8 can be used if there

is a need of reducing the transmitted information. For time of use registers ERGEG recommends a

minimum of three levels registered on daily basis. According to Andersen (52), TOU pricing with two

to three price levels a day is sufficient for small users without significant share of controllable load.

Benefits for different actors

Since various market participants can profit from smart metering, but the costs are only incurred by

the meter owner, they all have limited incentives to invest in smart meters. In (78), the potential

benefits of smart metering system for consumers, retailers and DSOs have been described in detail

and parts of the findings in (78) are listed in table 5.5.

Table 5.5 Important benefits of smart metering

Benefits

Consumers Potential for energy saving More accurate meter reading and billing Improved conditions for vulnerable customers Easier to change retailers

Retailers Pricing options Fewer bill complaints Better portfolio management

DSOs Better system monitoring Better network asset management

Ownership of the meter

There is also an issue around who should own the meter. If the meter belongs to the customer, they

may be unwilling to upgrade the existing meter (78). If the meter belongs to retailers or metering

service suppliers, this would become a barrier for customers to switch retailers/suppliers. Here it is

important to point out that the EU energy markets are now fully liberalized and all consumers are

free to choose their retailers (78). Thus, there is a reason to regulate the deployment of smart

meters.

8 Time of use registers refers to a system that can register energy use during different time periods. E.g. the

meter is capable of collecting three types of consumption as off peak, peak and critical peak consumption by aggregating those values in different registers

47

Possible smart meter ownerships are compared in table 5.6.

Table 5.6 Smart meter ownership

Actor that owns the meter

Benefits Drawbacks

Private metering company

No need for regulation on interface between regulated and non regulated market

Can be difficult to socialize the costs

DSO The consumer is already bound to the actor Possible to socialize the cost through common tariff

The border between services related to the naturally monopoly and other services is not clear

Retailer Have incentives to improve the demand response

Can be a hinder when consumers shall change retailer

Consumer No problem with information privacy Difficult to socialize the costs Low interest of upgrading the system

If the meters belongs to the grid operator and by that is included in the regulated monopoly some

other questions arises. One question is where to put the border between services and functions that

should be a part of the regulated market and other markets. For example, if load control and

visualization of real time consumption should be a part of the regulated market or a service that is

provided by free market actors. According to this problem, the information exchange between the

regulated actor and the other actors that would provide services must be specified. This is especially

true if the information transfer between the two actors require that one of the actors have to

connect to the other actor’s physical system. One way proposed to handle this is to define two levels

of smartness in the metering system (79). A basic level of metering applied by the DSO can be

developed, where the metering system complies with a standard for an open interface where other

actors can plug in more advance features and also get sufficient information from the system (80).

Identified benefits with an open home interface are:

This approach would not give the DSO a privileged position compared to other service providers (77)

Facilitate delivery of data directly to the consumer (77) and incentivize development of home

automation that increases the possibility for the demand side to be active (80)

Incentivize a competing development of real time consumption information applications that

enable direct feedback of consumption (80)

Direct feedback on energy consumption has given energy savings of 5-15 % compared to 0-

10 % for indirect feedback (81)

Will provide high quality consumption information instead of low cost power meter systems

in use today for home automation (80) and by that enable development of new services

Other ways to handle this problem is to remove the metering service from the monopoly and put it

on a market actor (78) (79).

The deployment of smart metering systems is one important issue. According to Directive

2009/72/EC three aspects around smart meters will be investigated by the 3rd September 2012.

These aspects are:

48

An economic assessment of all the long-term costs and benefits to the market and the individual consumers

Which form of intelligent metering is economically reasonable and cost-effective

Which timeframe is feasible for the distribution of smart meters Nevertheless, despite the high cost challenges created by smart metering, EURELECTRIC believes that

full retail market opening and a greater emphasis on energy efficiency renders the introduction of

smart meters as a positive and inevitable step in the medium term (82).

Deployment

Basically there are two deployment strategies. One is a mandatory roll-out, which means all meters

are to be replaced by smart meters in a given timeframe by the DSO and thereby paid by the

consumers though regulated metering tariffs or as part of the grid tariffs (78). The second is a

voluntary roll-out, which means that consumers can decide for themselves which kind of meter to

use. In this case, market penetration is uncertain and metering services can be carried out by an

unregulated third party (78). If the voluntary roll-out is carried out by the DSO questions arises how

the cost recovery should be done. Smart metering systems with a sample rate that enables dynamic

pricing contributes to a functioning market (50) which actors that do not have these meters also

benefits from (83). How to allocate the cost between the individual consumer and the collective is a

question that the regulatory authority has to handle.

No matter which strategy is used, regulatory framework needs to be properly amended in order to

encourage smart metering deployment in order to provide a certain level of standardization and

interoperability. In principle, regulatory authorities are able to take similar decision in mandatory

roll-out (78). In (78), the following approaches are suggested:

1) Remove legal or regulatory barriers to smart metering.

2) Mandate the introduction of smart metering functionalities.

The following polices are recommended in (84), which can either be introduced individually or in

combination with other policies.

1) Require the regulated meter service responsible party to install and operate smart meters

within their monopoly area.

2) Require an authority defined timeframe within which smart meter penetration should be

100%.

Recommendations for voluntary roll-out have not been found in the literature review.

Information security is also an important issue to consider. After updating the distribution system to

a smart level, metering is an activity that can obtain a lot of valuable information. Since in most

European countries except for UK, Germany and the Netherlands DSOs are in charge of metering,

DSOs should be regulated in how to use the information (15).

ERGEG has done a report “Final guidelines of good practice on regulatory aspects of smart metering

of electricity and gas” (77) in February 2011. It recommends on data security and privacy, customer

services, cost benefit analysis and roll-out of smart meter aspects.

49

5.2.2 Barriers for new services to penetrate the market

Barriers for demand response services to penetrate the electricity market relate to market access to

existing markets, conflicting interest, regulatory structures that discourage use of demand response

services and lack of standards.

The first question is whether the possible services are allowed to participate in existing markets. If

they are permitted to participate, there can be other hinders related to minimum volume

requirements, activation time (31) and how long the provided service have to be active.

There are also potential hinders related to the balance responsibility and active demand services. The

actor that performs load control may be a different actor than the BRP, or one that has a contract

with a BPR for these connection points. This causes a problem since the load control in this case will

cause problems for the BPR to predict the consumption in the connection point (26).

By consuming demand response services, the DSO reduces the need of physical assets and by that

the size of the RAB. If the regulation provides the DSO with stronger incentives to reduce the OPEX

than the CAPEX, the DSO would be uninterested of using these services (26). According to Meeus et

al (15) there is often the case that OPEX is under stronger efficiency incentives than the CAPEX.

Implementing active demand solutions will likely generate costs for the DSO in form of investments

in the system. How these costs should be recovered and how they should be allocated is an

important question for the DSO and the regulatory authority to handle (85). How to measure the

delivery of active demand services is also a question that in some cases may have to be handled

through regulation (85).

Other bottlenecks can be related to the lack of standards for communication between different

systems. For example, in the ADDRESS project a potential aggregator is expected to use a smart

device that communicates information such as price and maybe direct load control to the consumer

and the active house system. In this case there is a need of compatibility between the equipment

that the aggregator provides and the home equipment and the metering system that the DSO

provides (85).

5.2.3 Barriers for fluctuating prices to reach the consumer

As mentioned earlier, the price incentive is important in order for the consumer to participate as an

active demand. These price incentives arise from two basic factors. The first is the fluctuating prices

that are created by the supply and demand on the electricity market. The other price driver is the

cost fluctuations related to peak load on the transmission grid.

The first hinder for a dynamic pricing is if the consumer electricity price is regulated or not. Many

countries have regulated consumer tariffs that do not send the price signals to the consumer (15). If

the retailer is not allowed to use dynamic pricing models, price incentives can’t be sent to the

consumers. Barriers for the cost related to peak demand and transmission of the energy to reach the

consumers can be that costs as losses and charges for superior grids can be considered as pass

through costs in the regulation (86).

Losses is varying quadratic with the load on the grid and the cost for them is varying with the spot

price (at least the value of the energy used to cover those) (52). Losses in electricity system are in the

size of 7 % of the energy use (87). The quadratic relationship between load and losses results in

50

marginal losses that can be twice the average losses (52). An introduction of DER in the system will

also affect the losses. During periods when the production in the distribution grid exceeds the

consumption, the consumption would contribute to reduce the losses (52). This situation would

make the cost for losses vary between negative and positive values for the individual consumer.

Another hinder is if there is a fixed tax for energy used. This tax dilutes the price fluctuation that

reaches the consumer by reducing the percentage fluctuation in the price that faces the consumer

(52).

Other costs can be related to the design of the market where functions as congestions is handled

beside the market instead of market splitting. This hinders the possibility for the cost to reach the

consumer as a price incentive to adjust their consumption at the specific time (57).

It is recommended that the regulating authorities using output regulation to give the actors incentive

to design more dynamic tariffs (15). ERGEG has proposed some quality parameters that can be used

to measure and promote demand response (2 p. 28):

Demand side participation in electricity markets and in energy efficiency measures

Percentage of consumers on (volunteer) time-of-use / critical peak / real time dynamic pricing

Measured modifications of electricity consumption patterns after new (volunteer) pricing schemes.

Percentage of users available to behave as interruptible load.

Percentage of load demand participating in market-like schemes for demand flexibility.

Percentage participation of users connected to lower voltage levels to ancillary services

The proposed quality parameters are to be included in the quality regulation. They can be used as

minimum performance standards in reward and penalty incentive schemes.

51

5.3 Introduction of electric vehicles An introduction of electric vehicles is expected to take place, which may have an impact on the

electricity consumption patterns. The main impact will be in the form of an increase in the electricity

consumption and a need for charging infrastructure (48).

5.3.1 Need for infrastructure

Electric vehicles demand new services. The main demand is a charging infrastructure for the vehicles.

Infrastructure in both residential and non–residential areas is needed. EURELECTRIC (88) divides the

areas for charging infrastructure into public areas on public property, public areas on private

property and private areas on private property. They also distinguish between fast charging and slow

charging.

A private car is parked for most of its lifetime and the two main parking areas are at the user’s

residence and at the user’s work place (89). Except for these areas, public charging infrastructure is

also needed. One problem is that the market is small due to the low number of vehicles in use today.

Findings show that the users mainly charge their vehicles at home and maybe at work where the

vehicles are parked for a longer time (89). Because the market is small, most of the existing public

charging infrastructure has been built in demonstration projects or by actors with other interests

than making money on it. Actors such as municipalities, DSOs and retailers are interested in publicity

and promoting the introduction of electric vehicles (89).

The market today for public charging facilities appears to be small. However this market needs to be

developed for a successful implementation of electric vehicles in the future. The infrastructure can

be located in different areas. EURELECTRIC (88) distinguishes between charging infrastructure

located on public property and private property because of the different characteristics related to

these ownership forms.

Public charging infrastructure on public areas would be affected by regulation such as rules of

concession and building permits. The infrastructure probably needs to be connected to the MV or LV

grid. This infrastructure would be important both for people living in apartments without private

charging facilities and electric vehicle owners who are doing a short stay.

For the situation with public charging infrastructure on public areas one new possible level of

unbundling arises. Except for the two classic levels where distribution and retail are unbundled it is

one more level in form of charging infrastructure. EURELECTRIC (88) raises some questions around

these roles. Which actors will offer these services and what are the potential consequences. Figure

5.2 gives an overview of how the three functions can be divided between different types of actors.

Four models are presented in figure 5.2. In the first model the charging stations are considered as a

part of the electricity distribution grid and thereby owned by the DSO. To this a separate retail

market is applied. In the second model the ownership of the charging station is separated from the

DSO and the retail of electricity. The third and fourth models build on that the same actor both

control the charging station and retail of electricity.

52

Figure 5.2 Different functions in the value chain for electric vehicle charging and how these functions can be divided on different actors (88)

Model 1 and 2 have the advantage of a possible free retail market for the consumers. The biggest

difference would be that in Model 1 the cost for the infrastructure would be included in some

transmission tariff and could by that be managed in several ways. In Model 2 the user pays for

financing the infrastructure. Model 3 builds on large specialized e-mobility providers that have their

own infrastructure where their customers can connect. Model 4, which has the same structure for

unbundling as Model 3, implies a market where electric charging is a small part of the concept that a

local actor provides together with services such as parking.

Which the dominating market model would be will probably depend on the existing and future

regulation and other characteristics for the region. Other important tasks are standardization of the

interface between charging station and the vehicle (48) (89). There can also be a concession question

rising for building public charging infrastructure because that the DSO has the monopoly to build

electricity distribution infrastructure in this area. On e.g. parking areas there is a need for an internal

grid that connects charging points. In some countries there is no exception from the rules of

concession for such infrastructure. Due to these circumstances, each charging point need one

connection point of its own to the distribution grid and by that there is a risk for increasing costs (88)

(89) (90).

With public areas on private property EURELECTRIC mean areas such as private own public parking in

e.g. shopping malls, private parking lots and in connection to workplaces. In these areas it is more

likely that the available electricity infrastructure belongs to the private owner and is connected to

the MV or LV grid at one single entry point. In this case there can be a question if the private owner is

allowed to re sell the electricity to a new consumer (48) (88) (89). This differs from country to

country (88).

5.3.2 Change in consumption patterns

Electric vehicles will increase the electricity consumption which can lead to increased peak loads;

therefore it can give rise to an uncertainty factor for the DSO in the planning process. For example,

the capacity of the battery in electric vehicles is often in the range of 16-53 kWh and with a charging

time of around 3-4 hours the needed power would be 6-16 kW (49). But there can be longer charging

53

periods depending on available connections. For example, the most common charging system in

Sweden today offers slow charging with one phase 230 V and 10 or 16 amperes. This gives a power

usage of 2.3 or 3 kW (91). To handle this load there is a need for demand response (48).

Electric vehicles can also contribute different ancillary services to the electricity market since they

have storage capacity (49). Electric vehicles adopted for vehicle to grid connection can offer a quick

response time for sending energy or down-regulating the charging of the battery (49). Electric

vehicles integrated to electric grids with high amount of wind power and thermal power can help to

reduce the carbon dioxide emissions by 4.7 % (92). However, the same study concludes that if

electric vehicles are not integrated with some kind of active integration strategy they can result in

significantly increased peak load in the evening. There are also studies on electric vehicles and

ancillary markets with help of different aggregator structures (93) (94).

5.3.3 Outlook for electric vehicles

In Portugal a project called MOBI.E is running with the purpose to build a pilot charging infrastructure

for testing different technologies. The concept builds on that the network for charging will be a

regulated business but the charging points will be open for a free market. The electricity market will

be a retail market separated from the charging station operation. This project was initiated by a new

law and is supposed to represent the business model that Portugal will have in the future (74) (95).

This model separates electricity distribution, charging infrastructure and retail market as in business

model 2 in figure 5.2.

In Spain, a law “Articulo 23. Habilitación legal del gestor de cargas” has defined a new actor “gestor

de cargas” (charging manager). This actor is a consumer that buys electricity and has legal right to

offer charging services and also store energy for better use in the system. This actor will offer the

services on a non regulated free market and control his own infrastructure. The actor cannot be

companies that offer transmission or distribution services (74). This makes Spain going for model 3

with a strong focus on energy storage and electric vehicle charging integrated.

In Denmark the EDISON project is running. This project develops system solutions for electric vehicles

integration for network issues, market solutions, and interaction between different energy

technologies (96).

54

6. Summary on market concepts and regulatory bottlenecks for smart

grids

6.1 Distributed Energy Resources With the aid of smart metering system and distributed energy resources (DER), the actors in the

electricity markets and the relations between them are changing. In a distribution system, the

network customers comprise ordinary electricity consumers, prosumers who equip DER in residential

houses and DER companies. They still take electricity from retailers, however, DER companies and

prosumers can also sell electricity or the ability to control the electrical machines to aggregators.

Furthermore, the aggregator will participate in providing ancillary service and sell electricity in

wholesale market. The new structure of smart electricity market is shown in figure 4.1.

Regulatory bottlenecks for DER implementation consist of how to implement incentives in DSO’s

revenue. To give adequate incentives and enough cost recovery for the DSO is a major challenge for

regulators. There are six recommended ways to design the required revenue for DSO’s in order to

encourage them to connect more DER. They are presented in table 4.1.

At the same time there are three ways to design the tariff to make sure the DER owners get enough

incentives. All the three methods are presented in table 4.2.

From the system’s perspective, DER behavior should follow market demand to increase the efficiency

of the whole system. Use of system tariff can be designed on marginal investment pricing principle,

which means the remuneration of DER depends on the real-time electricity supply and demand. The

regulation should also consider the future development of the system, measure the efficiency of the

developing system, and define some new quality indicators.

The identified hinders and solutions for DER integration are presented in figure 6.1.

How the electricity market will be adapted

to the new actors in smart grid such as DER

and prosumers

Hinders How to accelerate a larger percentage of integrated DER from system’s perspective

How to give incentives to DSO for connecting

more DER

How to give incentives to

consumers for a higher DER penetration

Solutions

Aggregator and changed market rules. New market stucture is identified in figure 4.1.

UoS tariffs and new quality regulation

New price/revenue regulation methods as

shown in table 4.1

Connection charging methods for DER as shown in table 4.2

Figure 6.1 The summary on DER integration

55

6.2 Demand response The final price for the consumer of delivered electricity is the sum of the electricity price paid to the

retailer, the transmission tariff paid to the DSO and taxes paid to the government. The drivers behind

demand response are related to demand and supply on the electricity market and to cost efficiently

handle and reduce effects of peak demand. To efficiently introduce an active demand side there are

three key points identified; the price incentive for the consumer, a metering system that has a

sufficient sample rate and technical solutions that help the consumer to react (see figure 6.2)

Different market models for sending the price incentives to the consumer are presented in the report

and concluded in table 4.1 for the retail market and table 4.2 for the DSO. Furthermore, there shows

that how well the consumers respond to dynamic pricing depends on factors as how exposed they

are for the price fluctuations, the price difference between peak and off peak time, how big part of

their load that can be shifted in time and what technical equipment they possess.

Different types of enabling technologies are under development. Enabling technologies include

everything between that the consumer uses a timer to start non time critical loads up to systems that

control the consumer’s home system and optimize the electricity consumption out of different

requirements. A potential that these systems might be able to provide new market services related

to load control on the consumer side have been identified.

The areas where potential regulatory bottlenecks related to demand response can appear have been

identified. The first area is the capacity of the metering system, which has to provide all actors with

consumption statistic with a sufficient sample rate9. Related to the metering system the questions

are regarding who should operate it, who benefits of it, is there a need for a mandatory roll out and

how should the operator recover the costs. Furthermore, there are potential hinders for new types

of demand response products to enter existing markets related to market rules. The third area is how

well the electricity market structure allows costs for peak load on the transmission system and

potential price fluctuation according to demand and supply to reach the consumer.

The identified hinders and solutions for demand response are presented in figure 6.2.

9 What to consider as a sufficient sample rate can vary, as earlier mentioned ERGEG recommends hourly

measurements, but they admit that a sample rate of three samples a day can be sufficient in some cases. Andersen et al (52) has also concluded that for small users without significant controllable loads ToU-price with two or three price levels a day may be a sufficient price model for demand response.

56

HindersThe Supporting

technology is not yet in use

Lack of transparancy to consumers

Solutions

1) Price models to reflect the price incentives according to demand and supply are presented in table 5.12) Tariff models to reflect DSOs cost related to peak load on the transmission system is presented in table 5.23) Other services related to demand response

1) Roll out of Smart metering system with sufficient sample rate2) Standards for communication between different actors 3) Standards for communication between technical appliances controlled by different actors4) Controllable loads5) Services as remote control of equipment

1) Visualization of consumption and real time price 2) Information and education of the benefits with demand response

Lack of price incentives for the consumer

Figure 6.2 The conclusion on demand response

6.3 Questions concerning implementation of electric vehicles An introduction of electric vehicles has also been investigated. This introduction will require new

infrastructure supporting the system and the electric vehicles will also be likely to cause a risk for

increased peak demand (see figure 6.3). Around the infrastructure there is a question regarding the

need of unbundling between the electricity distribution, charging infrastructure and the retailing of

electricity to the consumer. There are four different models presented for how the market can be

organized. Another question raised is about concession. The need for building local grids within

parking areas for the charging infrastructure to support electric vehicles can interfere with the laws

about concession for the DSO10. The need for building local distribution grids within parking areas for

the charging infrastructure to support electric vehicles can interfere with the laws about concession

for the DSO. A third question is whether an actor that provides a private parking area is allowed to

sell electricity to a third party that is using the parking facilities. Demand response to avoid an

increase in demand during peak time in the evenings when electric vehicle users arrive home to

charge their cars is also required.

The identified hinder and solutions for introduction of electric vehicles are presented in figure 6.3.

10

Some countries does not allow other actors than DSO to build local grids for charging infrastructure. In those countries every charging point need an own connection point. This is mentioned as a cost rising hinder for the roll out of charging infrastructure for electric vehicles.

57

Increased peak demand

Four models for unbundling between the

roles of distribution, charging infrastructure

provider and retailing of electricity are presented

in figure 5.2

Electric vehicles participate as a

controllable load for demand response and in the future provides

ancillary services

Hinders

Solutions

Need for infrastructure and market rules

Figure 6.3 Hinders and solutions for introduction of electric vehicles

58

7. Case study—EU countries For 9 European countries: Bulgaria, Cyprus, Estonia, Latvia, Lithuania, Luxembourg, Malta, Romania,

and Slovenia, there is little literature on smart grid. Therefore, the case study will only focus on the

other 18 EU countries.

7.1 Background of EU countries related to smart grid The background will investigate general unbundling levels and status quo of the implement smart

grid supporting technologies in different countries. Four levels of unbundling can be distinguished:

ownership unbundling, legal unbundling, functional unbundling, and unbundling of accounts. Legal

and functional unbundling are mandatory for all DSOs in the EU countries, but they can apply an

exception rules for small DSOs, which have less than 100,000 customers (97). Detailed unbundling

information will be presented for each country in appendix.

7.1.1 The unbundling level of the DSO

In most countries the DSOs are unbundled from power production, and they are not allowed to

produce any electricity. Table 7.1 shows the unbundling situation for the EU countries. The

information is based on a status review of DSO unbundling conducted by ERGEG.

7.1.2 DG production

In practice, distributed energy storage is not common. Therefore, only distributed generators are

investigated in the case study. However, the statistics available in open literature are not always

consistent due to differences in the definitions and classification of DG. The approximate status of

DG integration relative to the overall capacity in EU countries is shown in figure7.1. The DG definition

used in the statistics shown in figure 7.1 is a generator that connected to distribution system

provides (at least) active power and with a lower than 50 MW rated capacity (34).

Figure 7.1 DG’s share of installed generation capacity in EU-25 (2004) (34)

59

Table 7.1 Unbundling situation in EU countries (98)

DSO can be owner of the

supplier

Number of DSOs

Austria No 130

Belgium (Walloon region) No 13

Belgium (Flemish region) No 16

Czech Republic No 3

Denmark Not found Not found

Finland Yes 88

France Yes 148

Germany No 862

Greece Not found Not found

Hungary No 6

Ireland No 1

Italy Yes 149

Netherlands No 8

Poland No 20

Portugal No* 13

Slovakia Yes 159

Spain No 329

Sweden No 170**

United Kingdom No 14

* The rule that DSOs are not allowed to be the owner of the supplier only applies to market suppliers

but not to suppliers of last resort (which are regulated).

** Source: (99)

7.1.3 Smart meter penetration

No international standard definition for smart meter or intelligent meter exists. For example, the

definition from Austria is “a smart meter is an electronic, remotely read, digital electricity meter,

60

which measures the electrical work and its time of usage without measuring the electric power of the

customer.” (100). In Denmark, the term intelligent meter covers all meters from one-way automatic

reading meters to technologically advanced meter, which e.g. can be connected to the consumer’s

own computer either by a cable or a wireless transmission (100).

In this report, we are aware that the smart metering technologies are constantly developing, so the

data in figure 7.2 is using a generic concept (101). Figure7.2 shows the approximate data of smart

meter penetration in some countries in Europe. Italy and Sweden have the highest penetration of

smart meters, while Finland and Denmark also have high penetration of smart meters. A Degree of

the Council of State in Finland requires that by the end of 2013 at least 80% of the consumption

places per each DSO should be equipped with a smart meter capable for registering hourly metering

and remote reading (102).

Figure 7.2 Smart meter roll-out at the end of 2010 (101)

In some countries national regulators and governments have imposed strict timelines for full

deployment of smart meters: 2016 in France, 2012 in Ireland, 2018 in Spain and 2010 in the UK (103)

(104). In other countries, such as Austria, Cyprus, Czech Republic, and Hungary, smart meters are

only installed in pilot projects (104). Belgium plans to install smart meters for four million customers

at a cost of € 1.3 million, funded through increased distribution tariffs (104). In contrast to

mandatory roll-out scheme, Netherlands and Poland have done the deployment on a voluntary basis

(103) (104). In those inactive countries, budget constraints have discouraged the launching even of

small pilot projects (103).

The smart meter roll-out plans in countries that have less than 5% penetration plus United Kingdom,

Ireland and Hungary are under discussion (100). But in Bulgaria and Greece there is still no smart

meter roll-out plan.

The definition of minimum requirements for functions, interfaces and standards is a key element for

an efficient smart metering system (100). ERGEG has done a status review of smart metering, and

Table 7.2 is based on its result. The first column shows the specifications that ERGEG requires smart

metering to at least partly fulfill.

Smart meter communication standards which are still under developing are very important for

implementing the functions. If different meter manufacturers and utilities are using different

communication solutions, it creates a risk that utilities will be locked into suboptimal technologies

and limited economies of scale in sourcing (103). That may directly affect a customer’s choice.

Fortunately major utilities and key equipment makers in this area in the EU have launched the Open

61

Meter project and the PRIME Alliance with the aim of defining these standards by 2010 or 2011

(103). McKinsey interviewed some EU countries and the result shows in table 7.3 (103).

Table 7.2 An overview of required functions for smart meters (100)

CZ DK FI FR DE HU IT NL PL PT ES SE UK

Metering interval X X X X X X X X X X

Communication

ways X X X X X X X X

Communication

technology X X X X X

Communication

protocol X X X X

Data security X X X X X

Storage capability X X X X X X

Remote control X X X X X X X X X

Local

communication

interface

X X X X X X X X X X X

Different tariffs

recorded X X X X X X

Bi-directionality X X X X X X X X X X

Sum of the

functions 2 2 5 10 10 4 9 8 7 2 8 4 3

62

Figure 7.3 Smart meter penetration and smart meter functions in EU countries

Figure 7.3 shows that most countries except Italy have high requirements on smart meters also have

low smart meter penetration. High requirements would stand in the way to roll out smart metering

system. Sweden has the highest smart meter penetration, but the functions of smart meters are less

than Italy.

0

2

4

6

8

10

12

0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100%

The

nu

mb

er

of

req

uir

ed

sm

art

me

ter

fun

ctio

ns

Smart meter penetration

CZ

DK

FI

FR

DE

HU

IT

NL

PL

PT

ES

SE

UK

63

Table 7.3 Smart meter communication standards in some countries (103)

Countries Smart meter communication standards

DE Mix of PLC (power line communication) and GPRS (general packet radio service)

in pilots will continue be put into full rollouts. PLC is preferred due to lower cost

but bandwidth is a concern.

FR PLC is currently being tested in pilots, but other solutions are being analyzed for

full rollouts.

NL The regulation authority also prefers PLC for lower cost, reliability and easy to

control.

Have defined the DLMS (device language message specification) companion

standard (79).

ES Major players in electricity industry have identified PLC as the preferred

technology.

SE, DK and FI Mix of PLC and GPRS are being tested, but PLC is preferred due to lower cost;

however there is a pressure to improve PLC outage management features.

UK GPRS is used during pilots. Either GPRS or RF (radio frequency) will be used for

full rollouts.

7.1.4 Electric vehicle penetration

Electric vehicle is still under development, although there are many pilot projects, hardly any

countries have started to popularize electric vehicles so far.

64

7.2 Investigation on 18 EU countries

This section presents the finding in the case study for the 18 investigated EU countries. Because of

language barriers some countries have been harder than others to find information out.

7.2.1 Structure of investigation

The question list in this investigation is based on the partial conclusion in chapter 6. And the

investigation is done literately. The investigated questions in the case study are:

1. What are the support mechanisms for DG?

This question investigates the policies for DG and the treatment of DG incremental costs. This

information is interested for investors, such as venture capital companies or risk-love consumers, to

invest in DG.

2. Does the aggregator exist?

The existence of the aggregator and what it can do in the electricity market are also very interesting

for investors.

3. Does the DG/aggregator have access to wholesale market?

4. Does the DG/aggregator have access to ancillary market?

Not all countries have accepted the aggregator concept, and the aggregator is important for DG to

get the accesses. These two questions reflect how far the country has been on the way to apply

market concepts for smart grids.

5. What are the applied price control regulation system and efficiency requirement?

Efficiency requirements are connected to if a rate-of-return or a performance based regulation is

applied. The efficiency requirements should also been updated since the efficiency will improve in a

smart grid. However, it should be decided carefully, since in the beginning period of the smart grid

the efficiency may not improve.

6. What incentive schemes are put on quality of supply?

Although most EU countries are using incentive regulation for price control, to promote smart grids

some special incentives related to the quality of supply are needed. This question only investigates

incentives to larger penetration of distributed generation. Quality of supply should be assured and

even improved on the way of smart grid evolution. Some important performance indicators are

energy losses and quality of power.

7. What is the current connection charge method?

This question is investigated to show how much the consumers are motivated to equip DERs.

8. Do use-of-system tariffs exist?

The UoS tariffs show how the system manages the distributed energy resources.

65

9. What is the applied smart meter roll-out scheme?

Smart meter roll-out scheme can influence the speed to implement smart meters, which gives the

prerequisite for demand side management.

10. Are price incentives applied in demand side management?

The price incentives can reflect how active the consumers are or what level the demand side

management is.

7.2.2 Case study result

This section summarizes the findings for the EU countries presented in the Appendix. All the

information references for this section can be found in the Appendix.

Support mechanisms for DG

In most countries, supporting policies are in place for renewable generators, which show their efforts

to achieve the 20-20-20 goal. Feed-in tariff scheme is the most popular one among these countries,

priority rules for renewable production and green certificates are also widely used. Only Denmark

and United Kingdom have included DG related CAPEX and OPEX into their price control incentive

regulation. Netherlands and Italy have included the CAPEX. Germany and France treat them by an

additional rate of return. However, there is no direct link between the treatment of DG incremental

costs and DG integration. Even under the same treatment of the incremental costs, the DG share

varies significantly.

Table 7.4 Support mechanisms for DG in EU countries

Country Supporting Policy Treatment of DG incremental cost DG share

DK Regulated price for CHP; Subsidy

and market price for wind power

DG related incremental CAPEX and

OPEX are considered in the

regulation

46%

SE Green certificates;

some founding for different micro

producers

Not found 19%

DE Feed in tariff

Fixed price for RES, market price

plus subside for CHP

Rate of return;

18%

NL Feed-in tariff

market price plus subsidy on

production and tax exemption

DG(<10MW) related incremental

CAPEX are considered in the

regulation;

17%

AT Green certificates in case of

renewable energy source are

available since 2003.

DG related incremental costs are

not considered in the regulation

14%

66

It is the weighted market price

paid for CHP plants. And

calculation shall assume a

baseload share of 95% and

peakload share of 5%

HU Feed-in tariff DG related incremental CAPEX and

OPEX are considered in the

regulation

10%

SK Priority rule and feed-in tariff DG related incremental costs are

not considered in the regulation

9%

CZ Producers can switch between

the green premium and feed in

tariff regimes once a year .

DG related incremental CAPEX and

OPEX are considered in the

regulation

8%

FI Investment grants for RES and tax

reimbursement for CHP and RES

Not found 8%

IT Priority rule, regulated price and

market based green certificates

Rate of return regulation on DG

related incremental CAPEX

6%

PL Priority rule DG related incremental costs are

not considered in the regulation

5%

UK Quota to buy RES DG related incremental CAPEX and

OPEX are considered in the

regulation

5%

IE Technical difficulties on DG

connection, there are restrictions

on eligibility of market access

Not found 4%

FR No direct incentives for DSO to

buy electricity from DG, but legal

obligation to do that

Rate of return;

3%

The existence of the aggregator

Very little information has been found about aggregators in the EU countries. The ongoing ADDRESS

project11 which will be finished in 2012 will provide information on how the aggregator can enable

active participation of consumers and prosumers in the power system market.

Market access for DG/aggregator

11

ADDRESS webpage is http://www.addressfp7.org/

67

The answers show that the market access for DG is still under developing. The reasons for that would

be the penetration of DG is still very low and the production is low, at the same time the aggregating

concept is not overall recognized.

Table 7.5 Market access for DG in EU countries

Country Access to wholesale market Access to provide ancillary services

CZ Yes Yes

FI The minimum bid for one hour in

Nord Pool is 0.1 MW, and the

trading fees are too high for small

producers

The controllable DG has direct access to

the balance market. The available

capacity must be at least 10 MW

DE No regulated network access In practice no

HU Yes Yes

IT Yes No

NL Yes No

PL Practically no Yes in theory

SK Yes No

ES Yes Not found

SE The minimum bid for one hour in

Nord Pool is 0.1 MW, and the

trading fees are too high for small

producers

Not found

Regulation system (regulation period) and efficiency requirements

Many different regulation systems are applied in the EU countries. The regulation design shows the

country’s desire to innovate to intelligent technologies and move towards smart grids. In Denmark,

for example, the smart meters are considered as extra ordinary costs which are not included in the

benchmarking. This can incentivize the DSO to roll out smart meters without worrying about their

efficiency, since the efficiency may decrease at the beginning of smart meter implementation.

Table 7.6 Regulation system and efficiency requirements in EU countries

Country Regulation system Regulation period

(year)

Efficiency requirements

AT Revenue CAP

regulation

4 Additional costs for SG are not considered

in the structure-parameters

68

CZ Hybrid revenue cap

and return on

invested capital

5 Efficiency is defined through OPEX only; No

DEA or SFA methods used due to small

number of distribution companies; Sector

efficiency factor was set by negotiations of

NRA with DSOs.

DK Hybrid revenue cap

and rate of return

regulation

1 Smart meters are considered extra

ordinary costs which is not included in the

benchmarking. It has not been clarified

how other smart grid investments will be

evaluated.

FI Hybrid revenue cap

and rate of return

regulation

4 Both individual and general efficiency

requirement only applying to OPEX;

All controllable operational costs and

capital costs are included in the efficiency

requirement, also all costs for R&D and

pilots regarding smart grids.

FR Revenue cap

regulation with

target values for

investments

4 OPEX allowances are based on

negotiations.

DE Revenue cap

regulation

5 Efficiency requirement is relevant for

adjustment of total costs.

IT Price cap regulation

on OPEX, rate of

return regulation

on CAPEX

1 Efficiency requirements for OPEX;

Additional costs for smart grids do not

have in the actual regulatory period

specific impact on efficiency requirements.

NL Yardstick

regulation. In case

of a significant and

exceptional

investment a rate

of return is applied

3 to 5 years, now

3 years is chosen

Costs for smart grid pilots are treated as

ordinary cost.

PL Hybrid revenue cap

and return on

invested capital

1 year; 3 years for

OPEX

Efficiency requirement is applied for OPEX

only; Model for OPEX for net regulatory

period (2011-2013) is unknown.

PT Hybrid revenue cap 3 The efficiency requirement is applied to

69

and return on

invested capital

the OPEX, additional costs for smart grids

like pilot projects, were included in

allowed revenue for the current regulatory

period.

SK Revenue cap

regulation with

target values for

investments

3 years, ending in

2011

Efficiency requirement is 5% annually, but

PRI-X cannot be lower than zero, so in

practice it is leading to flat prices across

the period.

ES Hybrid revenue cap

and rate of return

regulation

4 No general efficiency requirement;

OPEX allowances are based on standards

cost and negotiations on the efficiency

requirement.

SE Revenue cap

regulation planned

for 2012; currently

light handed

regulation

4 Only general efficiency requirements

which is 1% per year in real terms on costs

possible to influence;

The RAB via standard costs approved by

the regulator.

UK Revenue cap with

incentives/penalties

based on

performance

Now is 5 years,

from 2015 will be

8 years

Analyses based on OPEX and total network

costs;

If a DSO wants to spend additional costs on

smart grids it will need to justify them as

part of its business plan submission to the

NRA during price control review

discussions;

Expenditure using money from the LCNF

will not be included in any comparative

efficiency analysis.

Incentive quality regulation

DK, HU, NL and UK provide more incentive regulations on quality. That is one of the reasons DK has

the highest DG share, and other countries have high DG shares. Generally there are two ways to treat

the energy losses among these countries. One way is to have regulated incentives to reduce losses

below some pre-determined levels in a penalty scheme. This is the case in Denmark and Spain. The

other way is to compensate energy losses by contracting that from generators. Therefore, DSOs that

reduce their losses have to purchase less energy. This is the case in Netherland and Italy. Quality of

service here mainly focuses on continuity of supply. Most countries have considered the impacts of

70

DG on continuity of supply in a reward and penalty scheme. Specific incentives for innovation are not

common in these countries, except Poland, Hungary and UK.

Table 7.7 Incentive quality regulations for DG in EU countries

Country Incentive quality regulation (energy losses, quality of service,

incentive for innovation)

DG share

DK Incentives and penalties plus regulated values to reduce losses;

Regulated targets to improve quality of service;

Implicit incentives given by regulation for innovation

46%

ES Incentives and penalties plus regulated values to reduce losses;

Regulated targets to improve quality of service

18%

DE None 18%

NL Regulated targets to improve quality of service;

Losses are bought at the market

Implicit incentives given by regulation for innovation

17%

AT None 14%

HU Incentives and penalties plus regulated values to reduce losses;

Regulated targets to improve quality of service

Specific incentives given by regulation for innovation: DSOs are allowed

to spend 0.3% of their annual revenues on innovation instead of paying

that amount in taxes.

10%

SK Non-regulated targets(contracts) for quality of supply;

Incentives and penalties plus regulated values to reduce losses

9%

CZ Incentives and penalties plus regulated values to reduce losses;

Implicit incentives given by regulation for innovation

8%

IT Regulated targets to improve quality of service;

Losses are bought at the market

6%

71

Implicit incentives given by regulation for innovation

PL Incentives and penalties plus regulated values to reduce losses;

Specific incentives given by regulation for innovation: the expenditures in

energy efficiency projects may be included in the tariffs.

5%

UK Regulated targets to improve quality of service;

Incentives and penalties plus regulated values to reduce losses;

Specific incentives given by regulation for innovation: the Innovation

Funding Incentive (IFI) permits DSOs to spend up to 0.5% of its revenues

on eligible IFI projects related with any distribution system asset

management aspect; the Registered Power Zones (RPZ) mechanism

focuses on the connection of DG to distribution systems by using

innovative and more cost effective ways

5%

FR Losses are bought at the market 3%

Connection charge for DG

Connection charge design should be high enough to recover the DSO’s cost, but still not be too high

to dilute the DG connection incentives. Half of the 18 countries are using deep connection charging

method. However, the mixed charging method, which is recommended by ELEP project (43), is used

in Portugal, France and UK. None of the countries that have DG share higher than 15% use deep

connection charging method. As analyzed in Chapter 4, deep connection charges can affect the DG

integration significantly. But Austria has high DG shares while using deep connection charges.

Table7.8 Connection charge for DG in EU countries

Country Connection charging method DG

share

DK Shallow generator connection policy, however there are different rules

depending on the particular generation technology

46%

SE Deep 19%

ES Deep plus a negotiation process 18%

DE Shallow, includes location signal 18%

NL A capacity less than 10 MVA is shallow charges

A capacity over 10 MVA is negotiated and follow a deep charging philosophy

17%

AT Deep, the generator pays for the connection and an additional entry charge

for the possible upgrade of the grid, and negotiation is an integral part of the

process. There are rules that limit the DSO’s income from “entry fee” to 30%

14%

72

of the average annual grid investment.

PT Deep or mixed 12%

HU Shallow 10%

SK Negotiated 9%

BE Shallow 8%

CZ Deep 8%

FI No standard approach, DSOs are responsible for determining policy in this

area, however, Energy Market Authority is evaluating the charge

8%

IT Deep 6%

PL Shallow 5%

UK Mixed 5%

IE Deep 4%

FR Mixed, costs of the physical connection plus any network reinforcements at

the connection voltage

3%

EL Deep, and negotiation is an integral part of the process 3%

Existence of UoS

Most of the EU countries have no UoS charge for generators, except Austria, Finland, Ireland, Poland,

Slovakia Italy and UK. In Austria, Slovakia and Italy, UoS charge only has a uniform rate regardless of

its location. The Finish distribution tariffs are discriminated by voltage level at the connection point

and by time of day/year.

Smart meter roll-out scheme

Only a few countries have rolled out smart meters. Most of them are using mandatory methods.

Some countries prefer voluntary roll-out, in Austria for example, voluntary roll-out pilot projects have

been performed.

In most countries, metering services are regulated. However, Germany, the Netherlands and UK

apply marked-based policy for metering services. In some sense, an open metering service obstructs

the smart meter roll-out.

Price incentive/demand response

In order to send out price incentive, smart metering system is one of the prerequisites. Since not

many countries have implemented the smart metering system, not many countries have demand

side management activities. However, demand side can also response in some sense without smart

metering system.

73

Table7.9 Demand response in EU countries

FI Peak-load management

The total price difference between low and high consumers is 60.3% ;

Green tariffs is account for 43% of all tariffs

FR Peak-load management

EL Industrial customers participate in a peak shaving scheme; irrigation

rescheduling

IT Utilities required to make TOU tariffs an option for all customers ;

A special customer power supply contracts for automatic load shedding in

emergency situations;

White certificate;

New legislation on smart meter visual display

SE Consumers with smart meters that provide hourly meter readings can choose

to have dynamic pricing contracts. There are also some DSOs that offer

different types of dynamic tariffs

74

7.3 Conclusion on the case study According to table 7.5 table 7.7, table 7.8 and table 7.9, not a single regulation can promote DG

integration significantly. Denmark has implemented almost all the regulation that are favored by DG

as well as incentive quality regulation for DSO, which explains it has a much higher DG penetration

than other countries. In the contrast to Hungry, where also has implemented most of the regulation

that are favored by DG as well as incentive quality regulation, but the penetration of DG is much

lower than DK. The main difference between the two countries’ regulation is “connection charges for

DG”. DK uses a shallow charging method while HU uses a deep charging method. There would be

other reasons for their DG penetration difference, for example discrimination, but the connection

charge method is an important aspect to improve for HU.

The regulatory differences related to DG between DK and UK are even less. UK uses a shallowish

connection charges while DK uses a shallow connection charges, and UK has specific innovation

incentives while DK has implicit incentives. The details of the incentive regulation in UK should be

studied to identify the reason. This comparison shows that the implemented regulation for DG does

not necessarily lead to a high DG penetration. More quantitative analysis is very important to lead to

a larger DG penetration.

Demand side management can be active in some sense even without smart meters. And it is mainly

about peak-load management. To active demand side further depends much on the technologies in

the system. All the arguments in smart metering slow the development down. Since the smart

meters penetration is very low in most of the EU countries, the regulations on demand response are

not implemented yet.

To conclude, the support mechanisms for renewable energy are implemented well, and the smart

grid supporting technologies are developing very fast. However, there are not many regulations

related to the smart grids that have been implemented. Furthermore, the electricity market is

constructed under relevant regulation, so the current electricity market cooperates poorly with

smart grids. Despite much discussion about smart grids, the development has been slower than

expected (103).

75

8. Swedish electricity market and regulation

8.1 Introduction In Sweden there are approximately 170 DSOs (99). The transmission network is managed by the

Swedish TSO Svenska Kraftnät (SvK). The Swedish Energy Markets Inspectorate (EI) is the authority

that regulates the transmission and distribution companies.

Sweden has an ex-post regulation for revenue framework but is in the process of changing to an ex-

ante regulation. The first regulation period for the new ex-ante regulation is 2012-2015 (105).

8.1.1 The power system and the wholesale market

The Swedish power system is a part of the Nordic power system with the power pool Nord Pool.

Nord Pool consists of the Day-ahead market Nord Pool Spot and the intraday market Elbas. The real

time market is handled by the TSOs in the Nordic region and consists of a balancing market and in

Sweden two markets for frequency control.

As TSO, SvK has the system responsibility for the Swedish transmission grid. This means SvK has to

ensure the access to the transmission grid for all actors and maintain the physical and economical

balance in the system (106). Another responsibility for SvK is to handle bottlenecks in the grid and

the overseas links.

To avoid overload on transmission congestions, either the market can be split into price areas, or

adjusted with counter-trade. In Sweden the current system for handling congestions at the nation

border is market splitting (106). The congestions in Sweden are handled by counter-trading and by

adjusting the allowed transmission capacity to neighboring countries (107). From the 1st of

November 2011 the congestions in Sweden will be handled by market splitting (107). Sweden will be

divided into four bidding zones that represent the transmission congestions in the Swedish

transmission system. The bidding zones will form price areas on Nord Pool if the transmission

demand between two areas is greater than the capacity (108).

Three levels of balance responsibility exist in Sweden. SvK is the overall balance responsible player.

By signing a Balance Obligation Agreement with SvK, a company becomes a balance provider (BRP)

and by that takes the economical responsibility for the physical balance in their trade. On the third

level there are other players with agreements with the BRPs. With these agreements the BRP takes

responsibility for the other actor’s economical balance (106).

To be able to maintain balance in the system SvK both purchases ancillary services from the actors

that are connected to the system and prescribes the actors to fulfill some requirements. Ancillary

services purchased by SvK are primary and secondary frequency regulation, disturbance reserve and

power reserve.

The primary regulation has two levels of automatic frequency regulation. There are the Frequency

Controlled Normal operation Reserve (FNR) for regulation in the interval of 49.9-50.1 Hz and

Frequency controlled Disturbance Reserve (FDR) for regulation in the interval of 49.5-49.9 Hz. The

primary reserve is procured by SvK from the BRPs (109). The delivered services are measured in MW

and have to be reported with a precision of minimum 5 minutes (109). The activation time has to be

within 30 seconds (110). The secondary regulation capacity is procured by SvK from the BRPs. The

76

smallest allowed bid is 10 MW and if the activation time is shorter than 15 minutes it should be

specified (111).

SvK also has the responsibility for maintaining the voltage in the power grid. SvK has agreements

with the other grid owners that are connected to the high voltage grid to keep the voltage and

amount of reactive power within certain levels (112).

8.1.2 Network regulation

Revenue control (Ex-ante regulation)

The allowed revenue for the DSO in the new regulation model will be set according to the OPEX and

CAPEX. The OPEX depends on controllable and non controllable costs where the controllable costs

will be put under an X-factor of 1 % (113). Non controllable costs are Subscriptions to the overlying

and adjacent network and Agency fees (114). In the first regulatory period Cost of energy purchased

to cover network losses, Cost of produced energy to cover network losses and Cost of subscription in

the input point will also be handled as non controllable (114). Controllable and non controllable

variable costs will be based on historical cost data from the period of 2006-2009 (114).

CAPEX is based on the Regulatory Asset Base (RAB) and should cover depreciations and a fair rate of

return on the RAB. What assets that belong to the RAB is defined in Regulation (2010:304) for

determining the revenue framework under the Electricity Act (1997:857), 3§.

The assets that are included in RAB are divided into three categories (48). Category 1 and 2 mainly

consist of distribution lines and transformer stations. Category 3 consists of system for operation or

monitoring facility for transmission of electricity and systems for calculating or reporting the

measurement of energy transmitted (48).

The depreciation rate is an important factor for the investment in technology. EI has proposed a

depreciation rate for assets belonging to category 1 and 2 of 40 years and for category 3 is the

depreciation period proposed to be 10 years (48). The rate of return on the RAB will be calculated

with the weighted average cost of capital (WACC) method and is then adjusted by the quality

regulation.

The process for deciding the revenue frame for the regulatory period is based on three stages. Firstly

the DSO hands in a proposal for the revenue frame to EI. Secondly EI makes its own calculation of the

revenue frame following the process scheme described in figure 8.1. Thirdly a decision whether or

not to accept the proposed revenue frame is taken based on the calculations made by EI and other

circumstances that the DSO has referred to (105).

77

Controllable costs Non controllablecosts

X-factor

Operating Expenditures (OPEX)

Regulatory asset base (RAB)

DepreciationWeigthed average

cost of capital(WACC)

Adjustmentacording to quality

regulation

Capital Expenditures (CAPEX)

Adjustment for earlier periods prediction error

Revenue frame

Figure 8.1 Overview of the Swedish regulatory model (modified from (105 s. 14))

Metering system and tariff design for consumers

In Sweden the DSO is responsible for providing the metering service in connection points. The

requirements on the service and the allowed cost compensation in revenue are regulated by the

authorities (83).

For connection points with a fuse up to 63 Amps the DSO has to measure the energy use every

month. Before the reform for monthly meter readings the DSO only had to meter the consumption

once every year. For consumption connection points with a fuse greater than 63 Amps the DSO has

to measure the energy use with a sample rate of one hour (83).

DSOs have in many cases installed meter systems with a higher capacity than the requirements. 86-

91 % of the meters have the ability to register hourly measurements (83). Regarding the whole

system including meters and infrastructure for gathering and analyzing the samples the capacity for

registering hourly measurements is 28-29 % (83).

In 2010 EI proposed that the metering system should be upgraded to handle hourly measurements

that are reported every month for all consumers with yearly consumption over 8000 kWh and a fuse

up to 63 Amps (83). EI motivates to only include these consumers since most of the benefits are

covered in this group and that there are threshold effects for the cost of implementing the system

(83).

The DSO has the right to design the distribution tariff. However the electricity act puts some

restrictions for the design. According to the electricity act “Network tariffs shall be objective and non-

discriminatory “(Chapter 4, 1 §) and “Area network tariffs may not be formulated having regard to

where a connection is located within the area” (Chapter 4, 3 §) (115).

78

Metering system and tariff design for producers

The DSO has to connect a small production unit to the grid. Exception can be done if the DSO has

special reasons, e.g. that the capacity in the grid do not allow the connection (115). The DSO is

allowed to take a connection fee that is reasonable for connecting the producer to the grid. EI can

decide if the connection fee is reasonable (116). The DSO is responsible for metering the

consumption and production in all connection points (116) (117). In all feed-in connection points the

DSO has to hourly measure the energy flow and report it to the producer, retailer, BRP and SvK.

Units that do not deliver energy to the electricity grid do not need to be reported to the DSO

according to the Swedish electricity law (116), but in the common rules between Svensk Energi and

Konsumentverket the consumer is not allowed to connect energy production to the electricity grid

without permission from the DSO (118).

The DSO has the right to recover the costs that the producer causes through the grid tariff and it is up

to the DSO to design the tariff. There are some exceptions, for example, producers with a production

below 1.5 MW do not need to pay for metering equipment and the installation of it. Prosumers with

a production below 43.5 kW with a fuse of maximum 63 Amps and that are a net consumer over a

year does not have to pay any tariff at all to the DSO (116).

The producers have the right to be compensated for the reduction of losses in the distribution grid

and reduction of costs for superior grid that they cause. The compensation for losses should reflect

when the feed in to the grid takes place and reflect the amount of energy that was injected (119).

The compensation for superior grid should be based on when the energy is injected and the amount

of power the facility is delivering to the grid (119). By this the DSO has the possibility to send

incentives to the producer to adjust the production based on the situation in the grid. However, the

possible magnitude of the incentives that the DSO can send to micro producers is limited to the cost

for losses and superior grid.

EI has proposed three changes that will incentivize prosumers in Sweden (116). The first change is

that it should be mandatory with hourly settlements for consumption in connection points that also

have production (116). This is because that today there is hourly settlements on the production in

this point and as long as the fuse is 63 Amps or less the consumption is measured monthly (116). The

second change is that the DSO should be forced to charge the grid tariff on monthly net consumption

for prosumers (116). EI also proposed an investigation if it is possible that the Swedish taxes can be

changed so that it will be allowed with net charges of the taxes on monthly basis (116).

The third change is that a retailer with an agreement with a consumer for a connection point also will

be forced to take balance responsibility for production in the same point if no other agreements are

taken (116). The retailer will not be forced to buy the electricity from the prosumer.

Quality regulation

No quality regulation promoting smart grids functionalities in Sweden exist today. However, EI does

not exclude that there will be an incentive based quality regulation promoting smart grids within the

second regulatory period starting 2016 (48). EI concludes that the framework for quality regulation

for reliability that will be implemented in the first regulatory period of the new ex-ante regulation

also can be used for smart grid functionalities (48).

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EI mentions some of the quality parameters, listed by ERGEG as possible to be included in the

Swedish quality regulation (48 s. 83):

Quantified reduction of carbon emission

Hosting capacity for distributed energy resources (‘DER hosting capacity’) in distribution grids. Allowable maximum injection of power without congestion risks in transmission networks

Energy not withdrawn from renewable sources due to congestion and/or security risks

Share of electrical energy produced by renewable sources

Level of losses in transmission and in distribution networks (absolute or percentage)

Ratio between minimum and maximum electricity demand within a defined time period (e.g. one day, one week)

Demand side participation in electricity markets and in energy efficiency measures,

Percentage of consumers on (volunteer) time‐of‐use / critical peak / real time dynamic pricing

Measured modifications of electricity consumption patterns after new (volunteer) pricing schemes

Percentage of users available to behave as interruptible load

Percentage of load demand participating in market‐like schemes for demand flexibility

Percentage participation of users connected to lower voltage levels to ancillary services

EI also concludes that these quality parameters have to be developed before implementation (48).

8.2 The Swedish ex-ante regulation and general obstacles for smart grids What kind of technique that can be included in the regulated business for a DSO and what cannot be

included is for the moment not clarified in the regulation (48). This may cause uncertainty in who

should invest in the technology and who should use it. EI raises this question in their smart grid

report (48) and points out situations where some new technologies can be used for multiple

purposes. For example, energy storages can be used to improve electricity quality and would be

allowed to include in the RAB. However, energy storages can also be used as production units and

would then not be allowed to be included into the DSO’s business (48).

One other general problem related to investment in new technology is that Sweden will evaluate the

RAB out of the replacement cost for the assets included in it. By that there is a hinder for investing in

new technology where the cost can be expected to be reduced in the future or that the economical

or technical life time can be shorter than expected (48). Italy has solved this problem by introducing

an incentive for investment in technology development projects. This incentive scheme gives best

practice projected selected by the regulatory authority an extra WACC by 2 % for a period of 12 years

(120). One of the requirements to get this allowance is that the information protocols are open and

that there is an interoperability and openness around the project (120). EI has come to the

conclusion that financing of demonstration projects should be done by governmental or private

funding and not through the grid tariff (48). The motivation is that these projects should reach all

stakeholders.

8.3 Distributed Energy Resources The regulation in Sweden reallocates most of the costs that prosumers cause the DSO to other grid

users and by that incentives prosumers. The regulatory bottlenecks that can be found relates to the

80

connection of DER and that there might be a lack of incentives for the DSO to use new technical

solutions for integrating DER in the grid.

8.3.1 Prosumers

The Swedish regulation promotes prosumers with a production to the grid below 43.5 kW. As

described in Section 8.1.2 the DSO is not allowed to charge the prosumer any tariff for the use of

system. At the same time does a producer hold the right of compensation for reduction of losses and

cost for superior grid. By that there is a possibility for the DSO to send price incentives to the

prosumer to contribute to the grid.

There is also a proposals for net charging of the grid tariff for consumption that, if it is accepted, will

increase the revenue for the prosumer even more. Furthermore, there is a work aiming to make it

possible for net charging of the taxes on monthly basis for the prosumers. Net charging of the taxes

would increase the revenue for the prosumer even more since the taxes stands for a significant part

of the electricity cost in Sweden (see figure 8.2).

Net charging of grid tariff can be questionable out of a smart grid perspective. It is a risk that such a

regulation would interfere with the possibility for the DSO to design a dynamic tariff that sends

incentives to the prosumer to adopt its consumption according to the needs of the grid.

Still the problem for prosumers today is the lack of economical benefits due to high cost not related

to the regulation. For a prosumer the most common solution is to size the DER unit to cover the own

consumption (121). This gives the prosumer highest payment since it excludes all fees for entering

markets, the cost for grid tariff on reduced consumption, tax and vat. Energy from production that

exceeds the own consumption the prosumers can sell to any interested actor. The most common

solutions are that either the DSO buys the energy to cover losses in the grid or a retailer buys the

energy from the prosumer. The price the prosumer gets is anything between zero and the spot price.

A prosumer can also get green certificates for the production if it complies with the requirements.

Either the prosumer takes certificates for the net production by using the metering values the DSO

provides or the prosumer can arrange with a meter that meters the total production, however, this

implies an extra cost. Today the costs to measure the production instead of the net production are

often too high for small prosumers. EI has proposed that the rules for green certificates should be

changed so a small prosumer do not have to measure the production with the same requirements as

a larger producer (116).

8.3.2 Tariff for distributed energy recourse

In Section 4.3.2 it is recommended that the connection charges if possible should be of a shallow

characteristic and if not possible the DER unit should only cover the percentage of the costs due to

new capacity it requires. Further it is recommended that the process for calculating the charges

should be transparent and that the DER operator should get information on connection cost within

reasonable time.

No regulation that controls if the connection charges for a producer should be shallow or deep exists.

The only regulation is that the connection fee should be considered as fair and that EI has the right to

decide if it can be considered fair (116).

According to the electricity act chapter 4, 13 § (115), the DSO should also publish the principles for

how costs for technical adoptions are allocated when a new connection to the grid takes place.

81

Furthermore, the DSO should publish information of the grid tariff and on request deliver a

connection plan for the DER unit.

To conclude, the Swedish regulation provides a transparency and also a possibility for the DER

operator to get a time plan for connection. The bottleneck would be that there is no shallow

connection fee by law.

8.3.3 Capacity to connect distributed energy resources

The integration of larger amount of production in the distribution grid will need an increase in the

hosting capacity of the grid. Capacity can be increased by traditional reinforcement and with

introduction of smart grid abilities such as demand response, components for voltage control, energy

storages and participation of new actors on ancillary service markets (48) (122). These smart grid

solutions contain new technology and new market structures for new service providers. Market

access for these potential services providers is discussed in Section 8.6. Since it is important with

investments to increase the hosting capacity this section will investigate what incentives the new ex-

ante regulation gives to the DSO related to investments in general and specially in new technology.

The new ex-ante regulation shall be capacity preservative. This is done through evaluating the RAB

without taking account for the age of assets or their historical cost. Only replacement cost, WACC

and depreciation time are considered when calculating the contribution from an asset to the revenue

frame. The benefits with this method are that the DSO’s gets incentive to use their assets as long as

possible and that the price that is revealed for the consumers reflects the today value of the service

(123). There is a conflict in using a capacity preservative method when connection of DER needs a

capacity expansion. The conflict can be found in how the regulatory model evaluates the RAB, the

length of depreciation time and design of the WACC.

General obstacles for investments

One hinder for investments is that the depreciation method that will be used gives the same revenue

allowance for already depreciated assets as for new assets. When new assets imply a higher real cost

related to depreciation and capital costs they reduce the profit for the DSO. This mechanism may

encourage the DSO to keep the reinvestment rate low and thus maximize the profit (48).

It is also mentioned that the introduction of DER will increase OPEX (15) and as the OPEX is put under

revenue cap in the Swedish regulation an increase in OPEX also will reduce the profit for the DSO12.

Another problem with the new ex-ante revenue regulation is the relationship between the

connection fee and the allowed revenue. The connection fee generates a high increase in revenue

year one when the connection take place. At the same time the revenue frame is only increased due

to depreciation and rate of return on capital. By that the DSO has to adjust the tariff for other users

to not exceed the revenue frame year one and to reach it the other years (123). Another possible

way is to handle this by accrual (123).

Obstacles for new technology

EI will evaluate the RAB out of the replacement cost and update the standard price list at the

beginning of every regulatory period. EI concludes that this method will put the DSO at risk as that

the replacement cost not always follows the inflation. Thus, the allowed depreciation will not always

12

It is possible for the DSO to apply for an increased OPEX allowance if there are special circumstances.

82

cover the real investment (123). This situation discourages investment in assets with potential for

future price reduction, such as new technology.

The depreciation model that will be used is based on real annuity and will not take the age of the

assets into account. Therefore all assets give right to the same depreciation (123). This model will

discourage replacement of old assets and also favor investment in assets with long proven lifetime.

This model can act as an obstacle for new technology to penetrate the market as there is both an

uncertainty in technical lifetime and economical lifetime for new technologies. One way for a non

regulated company to compensate for these uncertainties is to use a shorter depreciation time and

increased demand on rate of return on the asset. As the rate of return for investments is set by the

WACC in the regulation and the depreciation time also is set by the regulation, there exists an

obstacle for the DSO to invest in unproven technology13.

Need for quality regulation

By introducing an ex-ante regulation Sweden will remove the uncertainty for the DSO to know if an

investment will be rejected or accepted ex-post. The new ex-ante regulation will compensate for

investment by including those in the RAB (48). However, as the regulation is designed for capacity

preservation and the introduction of DER needs a capacity expansion during a period, it would be

desirable to introduce a quality regulation that encourages expansion investments and the use of

new technology.

8.4 Integration of electric vehicles in Sweden This section investigates the regulation around charging infrastructure and market in Sweden. It also

reviews the possibility for demand response from electric vehicles in Sweden.

8.4.1 Market models for charging of electric vehicles

In contrast to Portugal no initiatives to regulate the market for charging infrastructure has been

taken in Sweden. Table 8.1 presents an overview of the situation based on the market models

presented in Section 5.3.

Most of the efforts in Swedish regulation have been put on identifying hinders, and removing those

for the expansion of charging infrastructure. One hinder that has been identified is the costs for

building local charging infrastructure in an area with many charging points, e.g. parking areas (124).

Today the law prescribes that each of these charging points needs a separate connection point to the

electricity grid. There is also possible to build charging infrastructure where there today exists

internal grids with no need for concession and by that remove the need of one connection point for

each charging point. However, it is not allowed today to build an internal grid specially dedicated for

charging infrastructure. EI proposes to change this (90).

Another identified hinder in the literature is reservation of parking lots for electric vehicles (124).

Earlier it was not allowed to reserve parking lots with charging infrastructure for electric vehicles.

This has recently been changed (125).

13

It is possible for the DSO to apply for another depreciation time and rate of return for an investment. However, there is no general mechanism that compensates the DSO when investing in unproven technology.

83

Table 8.1 The level of unbundling in the Swedish market for electric vehicle charging services

Model

The integrated

infrastructure model

There are no hinders in the regulation for the DSO to own the charging

infrastructure. However, charging infrastructure for electric vehicles is

not included in the natural monopoly and by that not included in the

regulated revenue

The separated

infrastructure model

No legal unbundling between electricity distribution, operation of

charging infrastructure and retail of electricity has been found

The independent e-

mobility model

There are no regulatory hinders for this model

The spot operator

owned charging

station model

This model is expected to be a common solution now in the first stage of

building infrastructure

8.4.2 Demand response and electric vehicles

As concluded in Section 5.3.2 electric vehicles need to be integrated into the system as a smart load

to avoid increased system costs for peak load. For consumers with possibility to charge the vehicle

from their own connection point, the vehicle would be a possible controllable load among others14.

This part of the integration will depend on how the electricity market/system in general will develop

towards an active demand side.

For consumers that have to rely on public charging infrastructure there might be a slightly different

situation. The average cost for charging of electric vehicles through public charging infrastructure

with a fuse of 10 or 16 Amps is expected to be below 10 SEK/hour when the technology has matured

(126). The cost for electricity is 3-5 SEK/hour and the rest of the price is to cover the cost for

infrastructure. In addition to this there are the costs for parking itself that in many cases can be

significant higher than 10 SEK/hour. Hence, the price incentive for demand response when charging

at public infrastructure might be diluted.

What effects the fixed cost will have on the possibilities for demand response related to public

charging of electric vehicles are too early to say. It may depend on how the market models develop.

For example, if charging and parking fees would be separated. Otherwise, the cost for infrastructure

may be recovered through other sources of incomes such as advertisement. Table 8.2 presents some

different business models identified by Svensk Energi (124). Most of these models provide a

possibility to separate different costs. Therefore it is possible to design price models that can send

incentives for demand response to the consumer.

14

The storage capacity is mentioned to be used both for ancillary services and as a part of active houses and micro grids. For a general discussion of markets for these services in Sweden se Section 8.6

84

Table 8.2 Different possible business models for charging service providers identified by Svensk Energi (124)

Model Description

Advertisement on

the cover of the

charging point

This is a commonly mentioned opportunity to collect revenue for the

infrastructure. In the plan for charging infrastructure done by Västerås

municipality it is concluded that this solution may cover the whole cost for

the charging points at parking areas in urban areas (127)

Pay as you go The consumer pays for the electricity and a fee that covers the cost for the

infrastructure. There can be a fee for used kWh or for the parking time. This

is already common for ordinary parking spaces today and the consumers are

also used to pay different prices for different times in the day. It is also

possible that the charging infrastructure is operated by another actor than

the one that operates the parking area and the cost for charging can then be

separated from parking cost15

Rental of parking

space with possibility

for charging

This is a common solution today for ordinary parking places. The consumer

pays for the parking place and it is possible to take a fee for charging

capacity similar to what is done for engine heater capacity today

Charging opportunity

as an extra service

It is possible to offer free charging as an advertisement to attract consumers

to visit the market place. This model probably needs a higher penetration of

vehicles than today to have a significant impact on the roll out of

infrastructure. But there is already today an advertisement value to say that

the facility can provide charging capacity

Subscription to

charging

infrastructure

The consumer is offered a subscription for charging infrastructure provided

by the actor in a wider area, the consumer may pay an entrance fee and a

volume based fee for the use of the system.

8.5 Demand response and incentives for consumers to be active To achieve an active demand side there are three important factors to consider. Firstly there is a

need for a metering system that supports market clearing between the customer and retailer.

Secondly, the price incentive for the actors has to reflect the service desired by the system and be of

a size that the actors are interested in. Thirdly, technology is needed that helps the consumers to

control their consumption.

8.5.1 The metering system

Sample rate and cost allocation

Four main hinders related to Swedish regulation and meter system have been identified in this

report. The first hinder is that the minimum requirements for sample rate are not high enough to

cover the price fluctuations related to the spot market. The second hinder is poor cost allocation for

15

Fortum offers a solution similar to this one in Stockholm for the moment. The charging point is operated through text messages and there is also services as where to find available charging points through a smart phone application connected to it (174)

85

metering system with higher performance than minimum requirement. The third hinder is the lack of

incentives in the regulation for the DSO to provide more advance services than the minimum

requirements. The fourth hinder relates to the possibility for flexible use of the newly installed smart

metering systems.

2009 the metering requirements for consumers with a fuse below 63 Amps were changed from

yearly meter readings to monthly readings (83). These requirements are a hinder since the sample

rate is too low for basic demand response on the retail market. Monthly meter readings only offer

the consumers the possibility to participate through energy efficiency activities. There is also a

suggestion that the requirement should be changed to hourly meter readings reported monthly for

all consumers with a consumption above 8 000 kWh/year. This would improve the flexibility on the

demand side on the electricity market and by that reducing the costs for the consumers. EI has

concluded that the costs for mandatory hourly meter reading for all consumers would be too high

compared to the benefits it can provide given the existing infrastructure (83).

The second hinder relates to the possibility of cost allocation for metering systems providing services

that exceed the minimum requirements. No regulation that promotes cost allocation for voluntary

roll out of smarter metering system than the minimum requirement has been found. According to

the electricity law, the consumer that wants another type of metering procedure than the law

prescribes has to bear the cost for it (115). If the DSO decides to do a roll out of smarter meters that

exceeding the minimum requirements the cost has to be recovered by the DSO.

The issue of cost allocation is important since EI has concluded that the effects from an increased

demand response from a group gives benefits for all consumers in form of a more dynamic electricity

market (83). Badano et al concludes that it is important that the costs for new metering system to

some extent are allocated based on the benefits they create for other actors (86). Cost allocation

would still be an important question even if the minimum requirements are changed according to

the proposal of hourly metering. A smart grid is expected to provide more services than just a well

functioning retail market and these functions will certainly put new requirements on the metering

system. These new services can be expected to give benefits to more than just the consumer using

the service. For example, if the demand side is entering the ancillary service markets there might be

a possible cost reduction for ancillary services due to an improved competition on these markets.

The third hinder relates to the lack of incentives for the DSO to install a system that provides the

consumers with the best possible services. In an unregulated market would a metering system that

enables the customer to save money be an advantage. This incentive does not exist in a regulated

monopoly. To compensate for this the regulation can provide incentive to the DSO by output

regulation. ERGEG has proposed performance indicators that can be used in the quality regulation to

promote the use of the system and that can give the DSO incentives to develop the system in a way

that encourage market development (2 p. 28):

Percentage of consumers on (volunteer) time-of-use / critical peak / real time dynamic pricing

Measured modifications of electricity consumption patterns after new (volunteer) pricing

schemes.

Percentage of users available to behave as interruptible load.

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Percentage of load demand participating in market-like schemes for demand flexibility.

Percentage participation of users connected to lower voltage levels to ancillary services

With an effective cost allocation and incentive based regulation there might be of interest for the

DSO to offer consumers with a yearly consumption below 8 000 kWh the possibility of dynamic

pricing. These consumers might not have a significant controllable load available, but they would still

be able to react to CPP. According to Andersen et al (52), a ToU-pricing system is suitable for

consumers with small amount of controllable loads. ToU and CPP put lower requirements on the

sample rate than hourly meter readings. This raises the fourth hinder. Maybe some of the installed

system would be able to deliver meter readings with a lower sample rate than hourly but still

sufficient for dynamic retail pricing. However, this would probably require a change in the clearing

procedures that today either use estimations based on monthly sample rate or the actual hourly

values. If the system would allow the DSO to estimate the consumption out of the best available

metering information it would be possible to use the system in an even more flexible and cost

efficient way than today.

Interface between regulated and unregulated functions and possibility for load control

Enabling technology such as load control equipment and real time information is important factors

that improve the response from the demand side. Many of these services can be provided through

some of the installed metering systems. Regulatory questions related to these services are; where

the border between regulated and unregulated services should be defined and how to enable a fair

competition for these services.

A significant share (43-60%) of the connection points is prepared for direct load control through a

relay output on the meter (83) (86). It is also around 31 % of the meters that are prepared for some

type of HAN access capability (83). No hinders for the DSO to provide load control services in the

regulation have been found. This raises the need of a regulation that reduces the risk for imperfect

competition between the DSO and other stakeholders that want to provide services such as load

control. One way to increase competition is to provide an open interface from the meter. Then the

DSO has no information advantage. ERGEG recommends an open interface that provides all

stakeholders with real time access to the information (77)16. Today there is no regulation prescribing

installed metering system to have an open interface that can provide a home area network with real

time information. An open interface is also recommended for the development of standalone

services to the consumer and other actors (79) (80).

8.5.2 Fluctuating price

If the demand side should have incentive to contribute to the system as an active part in the

electricity market they have to be exposed for prices that reveal the needs of the system. These

incentives also have to be of a magnitude that makes them interesting for the consumer to react

upon.

The electricity price for the consumer is the sum of the grid tariff, electricity price, taxes and VAT.

Figure 8.2 shows an approximation of the size of the components in the Swedish electricity price for

smaller consumers.

16

In Italy there is work on incentive mechanisms for development project with open interface information structures. See reference (120)

87

Figure 8.2 The components of the Swedish electricity price (modified from (128 s. 52))

This section will handle hinders for time dynamic prices to reach the consumer and mainly focus on

three areas: tax and VAT, retail price and the grid tariff. The design of the tariffs and electricity prices

is reflecting costs that originate from underlying factors. The electricity price originates from the

demand and supply of electric energy available in the system. The grid tariff origin from the cost

related to the transmission of the electricity to the consumer.

Tax and VAT

The tax and VAT are a bit different than the electricity price and the tariff. The VAT is often a

percentage of the cost (Sweden 25 %) on a product (129). The VAT is thus not diluting the price

incentives created by the retail electricity price or the tariff.

The energy tax in Sweden for 2011 is 0.283 SEK/kWh for most of the consumers (130) and stands for

a significant part of the consumer’s total electricity cost. Because the energy tax in Sweden is fixed to

SEK/kWh it dilutes the incentives that reach the consumer. The dilution of the price incentive is not

the same as removing the price incentive for the consumer, but it has been mentioned as a hinder

for demand response (52) (131). It has also been recommended that these taxes could be redesigned

to increase the dynamic of the electricity market and reflect environmental benefits related to

demand response (52). For example, the energy tax could reflect the impact of marginal energy

demand on the environment.

Retail and market price related to demand and supply

The retail price reflects the cost of demand and supply. Two hinders for the retail price to reach the

consumer have been identified in the literature. The first is if the regulation hinders the retail price to

reveal peak prices (15). The second one is if market structure hinders the power pool to handle costs

related to peak demand (57).

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As the Swedish congestion management changes from counter-trade to market splitting (132) the

congestion cost will be transfer from the transmission tariff to the spot price. This will enable the

cost to be reflected dynamically in time.

No major hinders related to the possibility for the cost related to demand and supply to reach the

retailer in the Swedish market structure has been identified.

The question is rather if the price fluctuation on the spot market would be of the magnitude to

incentivize the consumers to be active. Figure 8.3 shows the average price on Nord Pool hour by hour

for the period April to November aggregated and also January to March aggregated together with

December. There can be seen that during the winter months, the price was about 0.3 SEK/kWh

higher during the morning peak than the night price. Assuming that a consumer shift 2000 kWh

during this period it would have resulted in a saving of 600 SEK. With VAT included the saving would

be 750 SEK. If the energy tax would have been a percentage of the retail price the saving would

instead have been approximately 1200 SEK17.

Figure 8.3 The hour by hour average spot price at Nord Pool for Sweden during 2010 (Data from (133))

17

The energy tax and VAT stands for approximately the same total cost as the spot price for a consumer with electric heating.

0

20

40

60

80

100

1 5 9 13 17 21

€/M

Wh

Hour

89

Figure 8.4 The three days with highest peak price during 2010 in the Swedish price area (Data from (133))

Figure 8.4 shows the three days with the highest spot price during 2010. These three days had a ratio

between lowest and highest price in the range between 22 and 7. The following five days with high

price had a high to low price ratio average of 3.418. The three highest price peaks can be compared to

the CPP system in California that had peak to off peak ratios between 5:1 and 10:1. In the California

case a peak load reduction of 8-15 % was achieved (see section 5.1.3).

Costs related to transmission and distribution of electricity

Grid tariff is the fourth largest component of the electricity price. The grid tariff is covering costs

depending on how the consumer using the grid. The costs from transmission and distribution are

related to transport of electricity and some other costs as metering and authority cost for inspection.

The transport of energy includes losses, network investment and capital costs (52).

The grid tariff is one component that has a potential to give the demand side price incentives to be

active. Load dependent costs as losses can have a correlation with high retail prices and by that

increase the incentives for the consumer to be active (52).

Time dynamic costs and peak load costs appear on transmission and distribution level. If these costs

should be revealed to the consumers it is important that the tariff structure is dynamic on all voltage

levels. Cost related to peak load is today handled by a power based component in the transmission

tariff (106). This component has also started to appear on distribution level (48) and by that revealing

these costs to the end consumers.

Volume related cost on transmission level is today recovered through a volume based component.

This component is linearly depending on the latitude of the connection point to reflect the costs for

transmission losses related to distance (106). It does not reflect factors such as losses that do not

linearly vary with the load. These types of marginal costs are heavily dependent on the time

resolution. If the cost for losses is allowed to vary with real time or at least with an hourly resolution

large variations can appear (52). The real time variations on the costs for losses both depend on the

load in the grid and the spot price for which the energy to cover the losses need to be bought (52). It

18

It should be mentioned that 2010 was one of the years with highest electricity price on Nord Pool

0

200

400

600

800

1000

1200

1400

1600

1 5 9 13 17 21

€/M

Wh

Hour

90

is a correlation between high load on the system and high market prices for electricity (52). The real

transmission distance can also vary depending on the load on the system. For example, hydro power

is used in the Nordic system to compensate the difference between daytime and nighttime demand.

The main part of the hydropower is located in the north of the region and the consumption and the

thermal base load production is located in the south. Thus, there is a potential for higher losses

during daytime when the average transmission distance is longer. Messing and Lindahl (134)

identified a small correlation between the transmission through congestion cut two in the Swedish

transmission system and the electricity price. If the price is high the transmission of energy from

north to south increases (134). The size of the losses in Sweden is around 7.3 % of the consumption

and divided into (year 2009) (48 s. 31):

2.8 TWh Transmission grid

2.3 TWh Region grid

3.9 TWh Local grid

Transmission and regional grid stand for more than half of the total amount of the losses. This can be

considered as a hinder for the DSO to form a time dynamic tariff as only a small part of the time

dynamic costs are created in the distribution grid. There are different ways of allocating the dynamic

costs related to losses (135) (136) (137) (138) (139). Some propose that the tariff should be formed

time dynamically out of the position of the connection point since different areas in a grid can have

different load situations. This is probably not possible in the Swedish distribution grids since the

electricity law does not allowed the tariff to be designed based on geographical position in the grid

(115). Dynamic allocation of the cost for losses has also been mentioned as a possibility for DG to

gain higher revenue (135).

To conclude, a non time dynamic tariff for the transmission and region grid is a hinder for the DSO to

form a time dynamic tariff to the consumer. Furthermore, there is also a lack of incentive for the DSO

to form time dynamic tariffs since the cost for losses and superior grid is a pass through costs in the

regulation.

8.6 Hinders for new services related to demand response and DER This section investigates the possibility for controllable and smart loads as active houses, electric

vehicles and consumers with load control possibility to enter different markets. Investigated areas

are the ancillary service markets, potential services to DSO and services to BRP and retailers.

8.6.1 Ancillary services markets

Balance services as primary and secondary regulation are mentioned as possible markets for

aggregated demand services (52). The hinders for controllable loads, prosumers and DER units enter

these market are often related to allowance and volume. Rules that are adapted to larger units

where the cost for metering system can be spread on a large volume can also be a hinder.

The minimum bid of 10 MW to enter the market for secondary reserves should not be a primary

hinder, there have been tests with aggregated loads that entered this type of markets at a level of 10

MW in France (74). It is possible to bid for load reduction to these markets (140) and it is also

possible for actors that cannot reach the minimum bid requirement to aggregate their capacity (141).

91

Hinders for entering this markets would rather be related to the cost for metering the delivered

service and the cost for aggregating the loads for the service.

One possible solution would be to provide the DSO with an incentive to provide metering system

that enables the demand side to participate in these markets. ERGEG has for example proposed

some quality parameters for incentivizing low voltage users participating in the ancillary service

markets. Examples of quality parameters are (2 p. 28):

Percentage participation of users connected to lower voltage levels to ancillary services

Percentage of load demand participating in market-like schemes for demand flexibility.

The power reserve market is already open for aggregated demand. But this market is supposed to be

phased out until 2020 (142). AV Reserveffekt AB (143) is the only actor that today acts as an

aggregator on the market for power reserve in Sweden. AV Reserveffekt AB is aggregating smaller

consumption units with backup power generation capacity or load reduction capacity in the range

between 0.336-17.7 MW (year 2011). Another way proposed in the literature for providing this type

of service is introducing a CPP component in the electricity price and by that force the demand to

adapt to the situation (52). However, this requires a flexible demand side that can deliver the needed

service, since a failure would result in load shedding or even a black out.

8.6.2 Services to DSOs

Congestion management, peak load reduction, voltage control and load shedding are some services

that can be expected to be offered to the DSOs by aggregators (31) (57). Possibility of island mode

for local areas is also mentioned as a possible service (55).

In general, functions as congestion management and voltage control have been handled with

investment in physical assets such as building a stronger grid and or investing in static VAR-

compensators. Thus, the services will cause an increase in OPEX for the DSO and reduce the need of

investing in physical assets. This can be a problem if the regulation treats OPEX and CAPEX in

different ways. In Sweden the OPEX will be based on historical data (114) and by that there is a risk

that new costs contributing to OPEX decrease the revenue for the DSO. For the RAB, that affects

CAPEX, the DSO is allowed to make an investment plan. In the investment plan the DSO is allowed to

include the traditional physical assets they need to ensure an acceptable service to the consumers.

By this the DSO can include the assets in the RAB and get cost recovery through depreciation and a

fair rate of return related to the capital cost as long as they complies to the quality requirements.

Some of these services the DSO may finance through the grid tariff. For example, the DSO can offer a

general rebate on the tariff for units providing services. There are some restrictions concerning the

grid tariff. The tariff has to be objective and non discriminatory and it is not allowed to design the

tariff regarding to where in the distribution grid the users are located (115). Thus, it is probably not

possible to handle local problems as congestion management in the distribution grid through the

tariff.

8.6.3 Services to retailer and BRP

The BRP has costs related to unbalance. This cost depends on the cost for regulating power on the

market and the size of the imbalance the BRP has in the portfolio (144).

92

The Swedish balance system builds on three steps (144):

Balance planning

The physical balancing

Economical balance settlement

The balance planning is done in advance by trade on Nord Pool and Elbas with the purpose to ensure

that production and consumption plans agree. After closure time on Elbas, SvK takes the

responsibility for the real time physical balance of the system by primary and secondary regulation.

After the physical delivery of energy there is the economical balance settlement for production

balance and consumption balance.

The economical balance settlement builds on that the BRP has to cover the costs for the physical

imbalance caused in the system. This is done separately for consumption and production. For

production the BRP is charged for the deviation between real production and planned production

(144). For consumption the BRP is charged for the deviation between real time consumption,

planned production and trade (144).

This separation between consumption and production balance is an obstacle for market concepts

such as virtual power plant. In the virtual power plant concept is time intermittent production

aggregated with controllable loads to create an object with lower risk for imbalance. With the

separation between consumption and production balance there is not possible to create a virtual

power plant with both consumption and production.

It is still possible for a retailer to balance its consumption prognosis and real time energy demand

with help of demand response. However, that requires access to information on real time

consumption for the time intermittent consumption and this information the BRP today have no

access to.

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8.7 Summary of bottlenecks in the Swedish regulation regarding smart

grids In the case study of Swedish regulation, four areas with a need of improved regulation have been

identified. First area is the integration of DER in the distribution system and the second two areas

relate to creating an active demand side. The fourth area relates to market access for new

distributed service providers. Table 8.1 summarizes the main hinders for these four areas.

1) Integration of distributed energy recourses

As the regulation is designed for capacity preservation and the introduction of DER need a capacity

expansion during a period it would be desirable to introduce a quality regulation that encourage

expansion investments and the use of new technology.

2) Metering system

Regarding the metering system three main bottlenecks have been found. Firstly, the regulation has

to develop around cost allocation for new metering services exceeding the regulated minimum

requirements. Secondly, incentives for DSO’s to develop new metering services that enables smart

grid services has to be provided. Thirdly, regulation has to promote an open interface to the

metering system that can reduce the information advantage the DSO might get compared to other

new service providers. This interface is also an important component in the work of developing new

services for the system.

3) Electricity price for the consumer

The third area investigated covers hinders for the electricity price to be dynamic. To enables dynamic

price incentives to reach the consumers the energy tax has to be reconstructed to not dilute dynamic

price incentives. SvK and DSOs have to be incentivized to introduce time dynamic components in

their tariffs.

4) Market access for new distributed service providers

Two main bottlenecks have been identified for Market access for new services in smart grids. Firstly,

the possibility of adopting the market models in use for new distributed service providers has to be

investigated. To some extent there also has to be new models developed for purchasing ancillary

services from these providers. Secondly, it is important to monitor if the new ex-ante regulation has

the effect that it gives the DSO stronger incentives for investing in physical assets rather than

purchases services that can reduce the need of these.

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Table 8.3 Hinders in the market and regulation structure for smart grid market solutions

Area Type of hinder Description

Distributed energy recourses

Hosting capacity for DG

There is no incentives in the regulation for the DSO to provide hosting capacity for DG

Metering system

Cost allocation for metering system

There is no regulation for cost allocation related to introduction of new system with higher performance than minimum requirements

No open interface to the meter

Today there is no regulation prescribing an open interface or incentivizing regulation for developing open interface to the metering system

Incentives for the DSO to develop new metering services

There is a lack of incentive based regulation that gives the DSO incentives to develop metering services adopted after market requirements

Electricity price

Energy tax The energy tax is a non time dynamic fixed component of the electricity price that dilutes the incentives for the consumer to react to price fluctuations due to retail price and grid tariff

No time dynamic component in the transmission tariff

There is no time dynamic component in the transmission tariff. This hinders a significant share of the time dynamic costs to be revealed for the consumer

No incentives for the DSO to implement time dynamic tariffs

There is no incentive for the DSO to implement a time dynamic tariff for losses, since these costs is treated as pass through costs in the regulation

Services from smart grids

Need of new market models for ancillary services

There is a need of investigating new market models for how to purchase ancillary services considering distributed service providers

The regulation has different ways of valuing CAPEX and OPEX

A hinder for the DSO to purchase services that reduces the need for investment in physical assets is if the regulation puts stronger efficiency requirements on OPEX than CAPEX. The Swedish regulation will treat OPEX and CAPEX in different ways. How the effect will be is still unknown.

95

9. Conclusion This report focuses on two aspects that a smart grid shall enable: integration of distributed

generation and a changing customer behavior. For these two aspects the report investigates market

concepts and regulatory bottlenecks for stakeholders and actors when deploying smart grid

technologies. Furthermore, the report contains a case study of the regulatory situation concerning

smart grids in 18 EU countries with a deeper analysis for the Swedish regulation.

The review of market solutions and regulatory bottlenecks for smart grids concludes that the

electricity market structure should be adjusted to smart grids considering new actors and new

technologies. For example, distributed energy resources operators will be one new actor in the

market and smart metering technique has impact on pricing method. It also concludes that the

regulation should incentivize the application of smart grid technologies and services. Small

production and controllable consumption should have access to the electricity market in the smart

grid, for example, by help of aggregators. The obstacles for a more dynamic price to reach customers

should be removed. Moreover, an incentive regulation for DSOs, proper tariff designs for all network

users and new incentive quality regulations should be implemented in order to be smarter. The

unbundling on the charging infrastructure for electric vehicles is also discussed.

The EU case study concludes that there are some countries that have reached further than others in

adopting the market concept and incentive regulation for smart grids. Although smart grid

supporting technologies are developing very fast in EU countries, there is still a lack of implemented

new market structure and regulation for the smart grid. For example, small production and

controllable consumption are not contributing to the electricity market; and most consumers are

reluctant to react on the electricity price. The obstacles for dynamic price to reach consumers in each

country are different, but they are not discussed in the case study. Therefore, more pilot projects

need to be performed to test new market structure and regulations. Barriers for dynamic price to

reach consumers need also to be identified.

The Swedish case study concludes that Sweden has reached far in the work of introducing a metering

system that in many ways can be considered smart. The focus for the moment is to connect the retail

market with the spot market as well as promoting distributed generation through different incentive

schemes. For Sweden it is important to adopt the regulation to encourage the metering system to

provide new services. It is also important to adopt the market structures for ancillary markets on

both transmission and distribution level to allow distributed resources such as controllable

consumption and DER to participate. In the future, the focus has to be put on finding market models

for new services that the smart grid implies and create an incentive regulation that promotes

integration of distributed energy resources and demand response.

To accelerate the speed towards smart grids, the technology standards should be agreed widely and

published. An important challenge for regulators is to design proper parameters in revenue

regulation, such as efficiency requirements. Efficiency requirements may need an update since smart

grids are expected to increase the efficiency of the grid. Another challenge is to design proper tariffs

which send enough incentives to DER owners while the power quality is kept. Implementation of

dynamic tariffs for both consumers and producers need be paid more attention in the near future.

96

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166. Leonardo, M and Marcelo, S. Smart regulation for smart grids. www.eui.eu/RSCAS/Publications.

[Online] 2010.

167. Energy regulatory office (Poland). National Report to the European Commission. s.l. :

Commission for Energy Regulation, 2010. www.ure.gov.pl/download.php?s=2&id=77.

168. Energy Services Regulatory Authority, Portugal. Annual Report to the European Commission.

Lisboa : ERGEG, 2010.

169. Ackermann, T. Grid Issues for Electricity Production Based on Renewable Energy Sources in

Spain, Portugal, Germany, and United Kingdom. Stockholm : Statens ofentliga utredningar, 2008.

SOU 2008:13.

170. Regulatory office of netvork industries, Slovak Republic. National report - regulatory office for

network industries (Slovakia). s.l. : ERGEG, 2010.

107

171. Spainish Energy Regulator (CNE). Spanish Regulator's Annual Report to the European

Commission. s.l. : ERGEG, 2008.

172. Swedish energy agency. Sweden has legal unbundeling Sweden has legal unbundeling Sweden

has legal unbundeling. Eskiltuna : Swedish energy agency, 2007. Sweden has legal unbundeling.

173. Palmblad, L. Information about PV. Swedish energy agency. [Online] [Cited: February 21, 2011.]

http://www.energimyndigheten.se/Global/Solceller/090701-solceller%20broschyr.pdf.

174. Fossum, M and Molinder, A. Mobilen gör jobbet – smarta parkeringslösningar för elbilar.

Fortum. [Online] March 17, 2011. [Cited: March 22, 2011.]

http://media.fortum.se/2011/03/17/mobilen-gor-jobbet-smarta-parkeringslosningar-for-elbilar/.

1

Appendix Austria

In Austria, the “effective and efficient unbundling” method is in use. The method implies structural

separation but no ownership unbundling and eliminating underinvestment through transparent

network development investment planning and effective sanction (121).

In Austria, research organizations and grid operators have done a research on network innovation

zone related to DG in the project “DG Demonetz” (145), but the report is only available in Germany.

Table 1 Investigation in Austria

Questions Answers AT

Support mechanism for DG Green certificates in case of renewable energy

source are available since 2003;

It is the weighted market price paid for CHP plants,

and calculation should assume a base load share of

95% and peak load share of 5% (146).

The existence of aggregator Not found

DG/aggregator has access to wholesale

market

Not found

DG/aggregator has access to ancillary market Not found

Regulation system (regulation period) Revenue CAP regulation (4 year) (101)

Efficiency requirements A weighted average of DEA and MOLS gives the

efficiency score;

Cost input and of relevance are the total costs

(TOTEX);

Additional costs for SG are not considered in the

structure-parameters and will so decrease the

efficiency-score of the DSO (101).

Connection charge Deep, the generator pays for the connection and an

additional entry charge for the possible upgrade of

the grid. Negotiation is an integral part of the

process. There are rules that limit the DSO’s income

from “entry fee” to 30% of the average annual grid

investment (100).

Existence of UoS Yes (34)

2

Definition of the smart meter A smart meter is an electronic, remotely read,

digital electricity meter, which measures the

electrical work and its time of usage without

measuring the electric power of the customer

(100).

The existence and penetration of smart

meter

40,000 smart meters are already in place (147)

Smart meter roll-out scheme Lack of a legal obligation for installing, some DSOs

have begun to roll-out SM on a voluntary base;

A national roll-out is under discussion (100).

Smart meter operation:

The DSO is responsible for smart meter operation

(100);

Metering tariffs are separated from grid tariff (79);

Data privacy law relates only to generic law (100).

Price incentives (consumer price and tariff) Not found

Belgium

The third legislative package on the internal market for electricity and natural gas was unanimously

adopted by the Council on 25 June 2009. The new legal texts came into force on the 3rd September

2009. One of the new regulations is that the actual separation of production and supply activities

from grid activities. This aims to create homogeneous competition conditions, prevent the risk of

conflicts of interest and discriminating behavior in the operation of the grids, and to promote

investments in grid infrastructure (148).

For Belgium the situation differs between the three regions: Brussels capital, Wallonia and Flanders.

Two of them are regulated unbundled and the Flemish Region is analyzing a new “market model”

including the possibility of introducing smart meters (149).

Table 2 Investigation in Belgium

Questions Answers BE

Support mechanism for DG Not found

The existence of aggregator Not found

DG/aggregator has access to wholesale

market

Not found

DG/aggregator has access to ancillary market Not found

3

Connection charge Shallow;

The general approach concerning connection

charging for DG and RES in Belgium is dealt with by

the “Arrêté royal” (Royal Decree) of 11 July 2002,

published in the Moniteur belge of 27 July 200219

(here on referred to as A.R. du 11 juillet 2002).

Chapter II of this Decree details the general tariff

structure (“structure tarifaire générale”) (149)

Existence of UoS No UoS charge for generator (149)

Smart meter roll-out scheme In Brussels and Flanders regions, there are pilot

projects ongoing or in preparation. The results will

be used to decide on a roll-out of smart meters

(100). The Flanders region has done a cost-benefit

of roll-out of smart metering system analysis: the

model has been set up and produced first results.

The goal is to repeat this at a later date, with

better and more complete data (100).

Price incentives (consumer price and tariff) Not found

Demand side management

Several load-shedding contracts with industrial

customers are in force. The contractual capacity is

about 800 MW estimated contribution is 200 WM,

taking into account statistical availability,

estimated at 25%. These contracts are part of the

system services reserve (51).

But no interest in demand response (150)

Czech Republic

The concept of using the shared brand, logo and design of companies within the respective holding

structures continues to predominate in Czech Republic (151).The account for DSO-supply is

unbundled and the ownership for DSO-Generation is unbundled (152).

Table 3 Investigation in Czech Republic

Questions Answers CZ

Production percentage of DG 21.6%, 20.2% of which is produced by

distributed CHP and 1.4% of which is produced

by distributed RES (152).

Support mechanism for DG Producers can switch between the green

4

premium and feed in tariff regimes once a year

(153) .

However, within one electricity generating

plant, both methods cannot be combined (154).

The existence of aggregator Not found

DG/aggregator has access to wholesale market LT bilateral contracts and daily spot market

(153)

DG/aggregator has access to ancillary market Yes (152)

Regulation system (regulation period) Hybrid revenue cap and return on invested

capital (5 years) (101)

Efficiency requirements Efficiency is defined through OPEX only; base is

defined at the beginning of regulation period;

sector efficiency factor is 9.75% for the whole

period;

No DEA or SFA methods used due to small

number of distribution companies in the Czech

Republic. Sector efficiency factor was set by

negotiations of national regulatory authority

(NRA) with DSOs (101).

Connection charge Deep

Existence of UoS No (34)

Smart meter roll-out scheme Under discussion (155);

There are many concerns related to the

management of private information (79).

Price incentives (consumer price and tariff) There is no performance standard in DSO

revenue, benchmarking of DSO builds on both

CAPEX and OPEX (152).

Peak and off-peak pricing (156)

Denmark

All the DSOs are legally unbundled (97). Danish Energy Regulatory Authority (DERA) tried focusing on

issues that differentiate network companies from supply companies within a company group (157).

Denmark publicly announced that they would like to be a ‘play ground’ for electric car developers

(104).

5

Table 4 Investigation in Denmark

Questions Answers DK

Production percentage of DG 36%; 21% of which is contributed by CHP, 5% of

which is RES (152)

Support mechanism for DG Regulated price for CHP; Subsidy and market

price for wind power (152)

The existence of aggregator Not found

DG/aggregator has access to wholesale market Not found

Regulation system(regulation period) Hybrid revenue cap and rate of return

regulation (1 year) (101)

Efficiency requirements No general efficiency requirement;

Special benchmarking model used to derive the

relative efficiency requirement based on the

total cost per component;

Extra ordinary costs and losses are neither

included in the benchmarking;

Smart meters are considered as extra ordinary

costs. It has not been clarified whether other

smart grid investments will be given same

status (101).

DG/aggregator has access to ancillary market Not found

Connection charge Shallow generator connection policy; however

there are different rules depending on the

particular generation technology (152).

Existence of UoS DERA approves the companies’ tariff

methodology. Accordingly, a DSO is free to set

its tariffs as long as the company does not

violate its maximum return on assets and

revenue cap and furthermore does not

discriminate among its customers (157).

Smart meter roll-out scheme A mandatory rollout of smart meters could

soon be a reality (104)

Smart meter operation:

DSO has the responsibility for installation;

DSO is in charge of meter reading;

6

Meter maintenance is done by a party other

than the DSO;

Ownership of metering device is not regulated

(157).

Hourly metering (consumption>100,000

kWh/year) was mandatory from January 2005

(104)

Price incentive/demand response Not found

Finland

DSOs are allowed to be the owner of the electricity supplier (98). Levels (in accounting, legally,

administrative and operatively) of unbundling depends on the size of DSO (158). The unbundling

around Finnish TSO is still under discussion according to its annual report to the European

Commission. A working group has been set up to deliver a proposal for the implementation of the 3rd

package into national legislation (102).

The supervision of Finnish electricity market, network service pricing and terms of network services is

mainly based on so-called ex-post regulation with some ex-ante features (159).

Table 5 Investigation in Finland

Questions Answers FI

Production percentage of DG 15% (158)

Support mechanism for DG Investment grants for RES;

Tax reimbursement for CHP and RES (158)

Green tariffs (156)

The existence of aggregator Not found

DG/aggregator has access to wholesale market The minimum bid for one hour in Nordpool is

0.1 MW, and the trading fees are too high for

small producers (158)

DG/aggregator has access to ancillary market The controllable DG has direct access to the

balance market. The available capacity must be

at least 10 MW (158)

Regulation system(regulation period) Hybrid revenue cap and rate of return

regulation(4 years) (101)

7

Efficiency requirements Both individual and general efficiency

requirement only apply to OPEX;

General efficiency requirement: 2.06% per year;

Method used to calculate the individual

requirement is an average of DEA (Data

Envelopment Analysis) and SFA (Stochastic

Frontier Analysis). All controllable operational

costs are included in the efficiency requirement.

Also all costs for R&D and pilots regarding smart

grid and capital costs are included in the

efficiency regulation (101).

Connection charge No standard approach, DSOs are responsible for

determining policy in this area, however, Energy

Market Authority is evaluating the charge (43).

The connection fees for DG (<2MVA) may only

include the direct costs of connection. The max

level of the connection charge for DG is

regulated. In the distribution networks the

annual network charges for input collected from

an electricity generator may not exceed 0.7

EUR/MWh (102).

Existence of UoS No standard approach, DSOs are responsible for

determining policy in this area, however, Energy

Market Authority is evaluating the charge (158).

It specifies separately for output from the grid

and for input into the grid (102).

Smart meter roll-out scheme A Degree of the Council of State which requires

that by 2014 at least 80% of the consumption

places per each DSO (100).

Recognition of smart meter cost for

determining the allowed revenues/prices

Smart meters are included in the RAB in the

standard cost;

If the company can purchase the meters at a

lower price it will benefit the difference (101).

Smart meter operation:

Ownership of smart meters will belong to DSOs

from 2014 (100);

The DSO is responsible for smart meter

operation (101);

8

Customers with a subscribed power of more

than 63A will have to be metered hourly in 2010

and customers with less than 63A will have to

be meter hourly in 2013 (79);

Data privacy law relates to generic law (149).

Price incentives (consumer price and tariff) Peak-load management (100);

Consumption, billing components, historical

load curve and electricity quality are available to

customers (156).

France

In France the state-owned utility company Electricité de France (EDF) dominates the electricity

industry, which produces, transports and distributed over 95% of electricity. In 2009, DSOs, who

became subsidiaries more recently, consolidated their operating procedures and their position as

energy market players in their own right was recognized (160). DSOs and their roles remain relatively

unknown to the general public. This situation does not contribute to an open market (160). After

consulted among different stakeholders in France about smart metering by French regulatory

authority (CRE), the selected policy has been to introduce a mandatory obligation for one standard

meter box with minimal functional characteristics and enough flexibility for customer to plug a

second box able to provide more commercial special services (79). Minimal functional service will be

ensured by the DSO while extra services, not included in the mission of the DSO, will be provided by

the suppliers (79).

Table 6 Investigation in France

Questions Answers FR

Support mechanism for DG Legal obligation to buy from DG (161)

The existence of aggregator Not found

DG/aggregator has access to wholesale

market

Not found

DG/aggregator has access to ancillary market Not found

Regulation system(regulation period) Revenue cap regulation with target values for

investments (4 years) (101)

Efficiency requirements OPEX allowances are based on negotiations.

General efficiency requirement is 2% (101).

Connection charge for DG Mixed, costs of the physical connection plus any

network reinforcements at the connection voltage

9

(43).

Existence of UoS No charge for generators (34)

The existence and penetration of smart

meter

1% (150)

33 million smart meters in 2008 (104)

Smart meter roll-out scheme The DSO is responsible for a mandatory roll-out by

2017 (101)

Recognition of smart meter cost for

determining the allowed revenues/prices

Costs for the pilot projects are covered by

network tariffs (101)

Price incentives (consumer price and tariff) Peak-load management (104)

Germany

48% of the capacity is connected to the distribution systems, and 25% of this capacity has the

installations with a net nominal capacity of at least 100 MW (162). Also the installation of distributed

generation is increasing from 2009 to 2010 (162).

There is no provision that aims to compensate the DG positive impact on DSO network operations or

penalizing negative impacts, especially occurring in the transmission girds (97). Since RES can receive

larger revenues from the feed-in tariff, there is little incentive for them to participate in the energy

market (97).

As the metering services are liberalized, not only DSO but the independent metering operator can be

in charge of the smart meter operation (79) (100). Smart metering for private customers is in the

beginning step, there is no specific legislation yet (104).

Table 7 Investigation in Denmark

Questions Answers DE

DG production 15%, 9.4% of which is from CHP, 5.5% of which is

from RES (152)

How much DG is owned by DSOs Not much (152)

Support mechanism for DG Feed-in tariff for RES and CHP (97) (152)

The existence of aggregator Not found

DG/aggregator has access to wholesale

market

No regulated network access (161)

DG/aggregator has access to ancillary market In practice no (152)

10

Regulation system(regulation period) Revenue cap regulation(5 years) (101)

Efficiency requirements General efficiency requirement currently is 1.25%

(2009-2013);

The individual efficiency requirement refers to a

DEA and a SFA based on total costs, the

requirement is relevant for adjustment of total

costs (101).

Connection charge for DG Shallow, includes location signal (43).

Existence of UoS No (34)

Smart meter roll-out scheme No policy on smart metering yet, some suppliers

have started to install smart meters (79).

A compulsory full roll-out is under discussion (100)

Price incentives (consumer price and tariff) No relevant or no measure implemented (78)

ToU and load depending tariffs will be available in

2010 (104)

Greece

In Greece there is still lack of infrastructure for DG integration and poor support mechanism for DG

(43). At the same time there are no smart metering requirements or relevant activities so far (104).

There is some experience with smart meters among medium voltage costumers, but nothing for

households yet (79). The lack of proper cost-benefit analysis and the high cost of meters are the main

barriers to the smart metering deployment (79). The electricity grid in Greece in this report is

identified as “not so smart grid” and is not further investigated.

Hungary

The six distribution network companies have been operating as a part of vertically integrated

companies with legal unbundling in compliance with the relevant provisions on legal unbundling of

the Directive 2003/54/EC (163). At present, the Hungarian power market is not competitive (104).

There is no specific regulation around smart metering (100).

Table 8 Investigation in Hungary

Questions Answers HU

DG production 5%, 4.5% of which is from DG-CHP (152)

Support mechanism for DG Feed-in tariff (152)

11

The existence of aggregator Not found

DG/aggregator has access to wholesale

market

Yes (152)

DG/aggregator has access to ancillary market Yes (152)

Connection charge for DG Shallow (152)

Existence of UoS No (34)

Demand Side Management

Not found

Ireland

The Irish DSOs have been unbundled on both legal and functional basis (164). The retail electricity

market is fully competitive and independent companies now supply almost half of electricity

consumed in Ireland (104).

The Commission for Energy Regulation (CER) manages several smart metering trials and a cost

benefit analysis (CBA). The CBA will be completed in March 2011 (164).

Table 9 Investigation in Ireland

Questions Answers IE

DG production Not found

Support mechanism for DG Technical difficulties on DG connection, there are

restrictions on eligibility of market access (161)

The existence of aggregator Not found

DG/aggregator has access to wholesale

market

Not found

DG/aggregator has access to ancillary market Not found

Connection charge for DG Generators only need to pay Generation Capacity

Charge;

No charge for capacity less than 10 MW;

Capacity of DG equal to or greater than 10 MW

pay a site specific charge (164).

Existence of UoS

The existence and penetration of smart 5% (150)

12

meter A full roll-out is under discussion (100)

Smart meter operation:

The four aspects of meter operation are all the

responsibility of DSO (149);

No decision has been taken on who has access to

the data of the smart meter; privacy law related to

meter values is regulated through the Data

Protection Act (100);

The ownership of smart meters lies with the DSO

(149).

Demand Side Management

There is a capacity margin charge in place for

recovering costs associated with demand side

management (164).

Italy

Enel Distribuzione distributes a large share of the Italian distribution system, for example it accounts

for 86.2% of the total volume (165). The Authority opened the procedure for drawing up the

necessary provisions to comply with administrative and accounting unbundling for enterprises

operating in the electricity sectors. This procedure was open to consultation on 9th October 2009

(165).

Table 10 Investigation in Italy

Questions Answers IT

DG production (How much DG is owned by

DSOs)

5% (Much by ENEL) (152)

Support mechanism for DG Priority rule, regulated price and market based

green certificates (152)

White certificate (166)

The existence of aggregator Not found

DG/aggregator has access to wholesale

market

Yes (152)

DG/aggregator has access to ancillary market No (152)

Regulation system(regulation period) Price cap regulation on OPEX, rate of return

regulation on CAPEX(1 year) (101)

Efficiency requirements Efficiency requirements for OPEX;

13

Additional costs for smart grids do not have in the

actual regulatory period specific impact on

efficiency requirements (101).

Connection charge for DG Shallow but negotiated (152)

Deep (43)

Existence of UoS Capacity and energy components;

Generators and end-users both pay for this (152)

The existence and penetration of smart

meter

90% (150) 100% in 2011 (79)

Compulsory (104) with minimum functional

requirement (79)

Recognition of smart meter cost for

determining the allowed revenues/prices

Smart meter costs are treated like other cost

(101).

Metering tariff is separated from network tariff

(79).

Definition of smart meter The Italian regulatory authority established

minimum functional requirements and introduced

incentives for the adoption of advanced metering

features related to quality of supply (104).

Smart meter operation:

DSO is responsible for the smart meter operation.

Italy states that any use of meter values has to be

authorized by the customer, except use for system

functioning (100).

The ownership of meters lies with the DSO (149).

Demand Side Management

Utilities required to make TOU tariffs an option for

all customers (150);

A special customer power supply contracts for

automatic load shedding in emergency situations

(78);

New legislation on smart meter visual display

(166).

Netherlands

14

All Dutch TSOs are already fully unbundled, and all (but two) DSOs have been separated from the

integrated company (104). According to the national report to European Commission, the remaining

two companies that are not yet unbundled announced to postpone the activities related to

unbundling. The metering service is open to competition in the Netherlands (79).

Table 11 Investigation in the Netherlands

Questions Answers NL

DG production (How much DG is owned by

DSOs)

16%, 13% of which is from DG-CHP, and 3% of

which is from DG-RES (152)

Support mechanism for DG Feed-in premium on top of the market price and

tax exemption (97) (152);

The premium varies with the electricity revenues

(97).

The existence of aggregator Not found

DG/aggregator has access to wholesale

market

Yes (152)

DG/aggregator has access to ancillary market No (152)

Regulation system(regulation period) Yardstick regulation; in case of a significant and

exceptional investment a rate of return is applied

(3 to 5 years, now 3 years is chosen) (101)

Efficiency requirements Revenue allowances are based on “yardstick-

costs” which are defined as the average cost of all

grid operators;

The yardstick is calculated with a DEA based on

total costs, each grid operator is required to move

gradually to that common average;

Costs for pilots are treated as ordinary cost (101).

Connection charge for DG A capacity less than 10 MVA is shallow charges;

A capacity over 10 MVA is negotiated and follow a

deep charging philosophy (43)

Existence of UoS Mostly end-users pay for this (97) (152)

The existence and penetration of smart

meter

Mass roll-out will probably start around the end of

2011 (104).

Demand Side Management Not found

15

Poland

In distribution, there are 20 distribution system operators; 14 of those have been separated in legal

terms from former distribution companies, and 6 are the so-called local operators which are not

subject to organizational and legal unbundling because of the number of the consumers (167). Since

1998 the power market has been gradually deregulating, and it is still in transition (104).

Table 12 Investigation in Poland

Questions Answers PL

DG production 16% (152)

Support mechanism for DG Priority rule (152)

The existence of aggregator Not found

DG/aggregator has access to wholesale

market

Practically no (152)

DG/aggregator has access to ancillary market Yes in theory (152)

Regulation system(regulation period) Hybrid revenue cap and return on invested capital

(1 year; 3 years for OPEX) (101)

Efficiency requirements Efficiency requirements is applied for OPEX only;

Regulatory OPEX was calculated by regulator as a

result of a benchmarking;

Model for OPEX for next regulatory period (2011-

2013) is unknown (101).

Connection charge for DG Shallow (152)

Existence of UoS Energy and capacity components;

All generators should pay for this (152).

Smart meter roll-out scheme Under discussion (100)

Demand Side Management Not considered (149)

Portugal

The DSO in Portugal is part of a vertically integrated company. It is therefore obliged to legally

unbundle the other activities in which it is engaged (168).

16

The regulation for DSO in mainland Portugal is taking the form of incentive for efficient management

of costs via a price cap methodology; incentive to improve quality of service; loss reduction incentive

and incentive to improve environmental performance (168). The economic targets were set on the

basis of benchmarking studies of international scope, in the case of distribution system, parametric

(SFA) and non-parametric methods (DEA) were used (168).

Table 13 Investigation in Portugal

Questions Answers PT

DG production (How much DG is owned by

DSOs)

DSOs are not allowed to be the owner of the

supplier only applies to market suppliers but not

to suppliers of last resort (which are regulated)

(98).

Support mechanism for DG RES is paid according to a feed-in tariff scheme

(169).

The existence of aggregator Not found

DG/aggregator has access to wholesale

market

Not found

DG/aggregator has access to ancillary market No

Regulation system(regulation period) Hybrid revenue cap and return on invested capital

(3 years) (101)

Efficiency requirements Efficiency analysis of the past performance using

various methods have been performed;

The efficiency requirement is applied to the OPEX,

additional costs for smart grid like pilot projects,

were included in allowed revenue for the current

regulatory period (101);

And the annual efficiency factors applied to unit

costs were 3.5% (168).

Connection charge for DG Deep or mixed (43)

Existence of UoS Not found

Smart meter roll-out scheme Considering mass roll-out (104)

Smart meter penetration 100% for HV/MV; 0.5% for LV (101)

Demand Side Management Not been considered yet (149)

17

Slovakia

Electricity distribution systems have been legally unbundled. The methods for accounting and

administration unbundling for DSOs have been set in 2009 (170).

Table 14 Investigation in Slovakia

Questions Answers SK

Support mechanism for DG Priority rule and feed-in tariff (152)

The existence of aggregator Not found

DG/aggregator has access to wholesale

market

Yes (152)

DG/aggregator has access to ancillary market No (152)

Regulation system(regulation period) Revenue cap regulation with target values for

investments (3 years, ending in 2011) (101)

Efficiency requirements Efficiency requirement is 5% annually, but PRI-X

cannot be lower than zero, so in practice it is

leading to flat prices across the period;

Efficiency ratios applicable for accepted losses

volume for each voltage level separately (101).

Connection charge for DG Negotiated (152)

Existence of UoS Based on energy (152)

End-users pay for that now, but generators will

also need to pay in future (152)

Smart meter roll-out scheme

No rollout of smart meters has been agreed yet.

The government will perform a feasibility study by

end of 2011 with involvement of DSO’s (101).

Demand Side Management Not found

Spain

In the specific case of PV, Spain has fully recognized the characteristics of the technology and

provided it with what is probably one of the best regulatory frameworks in Europe (43). This leads to

an extremely flexible and relatively affordable connection procedure for small (domestic) PV systems

(43). It has been implemented through a standardized procedure with little or no contribution from

the generators to general network costs. This approach provides a good model for a streamlined and

simple process for connecting small-scale DG plants in general (43).

18

There is no obligation of ownership unbundling for DSOs. The 2007 Act mandates for functional

unbundling of activities as well as legal unbundling, the Act also prevents the regulated activities

companies holding any share in companies carrying out production or supply (171).

Table 15 Investigation in Spain

Questions Answers ES

Support mechanism for DG Cap and floor values are included for the RES price

(97)

The existence of aggregator Not found

DG/aggregator has access to wholesale

market

Yes (161)

DG/aggregator has access to ancillary market Not found

Regulation system(regulation period) Hybrid revenue cap and rate of return

regulation(4 years) (101)

The cap formula includes specific terms regarding

energy losses and continuity of supply (97).

Efficiency requirements No general efficiency requirement;

In the currently proposed model capital costs are

allowed using a reference grid model which looks

upon the built-in system efficiency in the grid.

Additional costs are not taken into account;

OPEX allowances are based on standards cost and

negotiations on the efficiency requirement (101).

Connection charge for DG Deep plus a negotiation process (43)

Existence of UoS Paid by consumers (97)

Smart meter penetration 5% (150)

Smart meter roll-out scheme Minimum functional requirements of meter are

under discussion now (79);

Roll-out until 2018 mandatory by law (101).

Recognition of smart meter cost for

determining the allowed revenues/prices

Investment cost of the meter is regulated

separately through a meter hire charge;

There latter are supposed to be treated like other

investments, but allowed revenues do not

19

currently reflect them (101).

Smart meter operation: DSO is responsible for most operation except

maintenance;

It is another party responsible for the

maintenance (100).

Demand Side Management No (150)

The customers are not aware about the different

meters possibilities (the only information that

they have it ToU tariffs), the regulator is

considering launching an information campaign

(79).

Sweden

Sweden has implemented unbundling according to directive 2003/54/EC from the year 1996 (172). A

DSO is allowed to be a part of a corporate group that has retail and/or electricity production. The

CEO and authorized signatory are not allowed to be the same for the DSO as for the retailer or

electricity producer in the corporate group if the DSO has more than 100 000 customers (172).

Table 16 Investigation in Sweden

Questions Answers SE

Support mechanism for DG Electricity certificates (169) and there is also some

founding for different micro producers where the

person that wants to can apply for money. The

founding is 60 % of the total installation cost for

PV (173).

The existence of aggregator AV Reserveffekt AB is aggregating smaller

consumption units with backup power generation

capacity or load reduction capacity in the range

between 0.336-17.7 MW (year 2011) (143).

DG/aggregator has access to wholesale

market

The entrance level for the Power pool is 10 MW

but if the producer has lower capacity the

production can trade through other companies.

DG/aggregator has access to ancillary market Not found

Regulation system(regulation period) Revenue cap regulation planned for 2012;

currently light handed regulation (4 years) (101).

Efficiency requirements Only general efficiency requirements which is 1%

per year in real terms on costs possible to

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influence;

The RAB via standard costs approved by the

regulator (101).

Connection charge for DG Deep (43)

Existence of UoS Small prosumers do not have to pay any UoS

charges. But they have the right to get payment

for the reduction of losses they cause and the

reduction of DSO’s cost for superior grid (116)

Smart meter roll-out scheme Mandatory (149)

Smart meter operation:

The DSO is responsible for installation and

maintenance (149);

Only monthly meter readings for consumers with

a fuse less than 63 Amps (83);

Data privacy law relates to generic law (100).

Recognition of smart meter cost for

determining the allowed revenues/prices

Smart meter costs are included in the regulation;

Smart meter are included in the RAB at the

standard cost (101).

Demand Side Management Consumers with smart meters that provide hourly

meter readings can choose to have dynamic

pricing contracts. There are also some DSOs that

offer different types of dynamic tariffs (48).

UK

From the Ofgem 2008 National Report to the European Commission, it can be seen that some of the

DSOs are fully ownership unbundled while others are part of vertically integrated groups. And it did

not change from 2008 to 2010. April 2010 to March 2015 is a new regulatory period and Ofgem has

set up a Low Carbon Networks (LCN) fund to support the trials on distribution network. UK has the

most innovative support regulation for DG.

Table 17 Investigation in UK

Questions Answers UK

Support mechanism for DG Quota to buy RES (152)

A pass-through rate is 80%;

Supplementary incentive for DG capacity

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connection is £ 1.5/kW/yr ;

A cap (two times the cost of capital) and a floor

(cost of debt) for overall returns;

Incremental unit costs above £200/kW are paid by

the plant owner through connection charges;

An additional £1/kW/yr for operation and

maintenance;

£0.002/kWh default rate subject to further

development (38).

The existence of aggregator Not found

DG/aggregator has access to wholesale

market

Theoretically yes but hard (152)

DG/aggregator has access to ancillary market Theoretically yes but hard (152)

Regulation system(regulation period) Revenue cap with incentives/penalties based on

performance (from 2015 will be 8 years) (101).

Efficiency requirements Cost allowances based on efficiency analysis of

past performance using various economic

methods based on normalized costs;

Analyses based on OPEX and total network costs;

If a DSO wants to spend additional costs on smart

grids it will need to justify them as part of its

business plan submission to the NRA during price

control review discussions;

Expenditure using money from the LCNF will not

be included in any comparative efficiency analysis

(101).

Connection charge for DG Mixed (43)

Existence of UoS Mostly is energy based (152);

Generators that have been connected to the

distribution network after 1 April 2005 and which

have caused reinforcement on the distribution

grid have to pay Distribution Network UoS (169).

Smart meter roll-out scheme Under discussion (100)

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Smart meter operation All aspects of utility metering have been

unbundled and opened to competition (104);

No specific statements on data access, data

privacy relates to generic law (100).

Demand Side Management Not found