SEE Wholesale Market Opening - Final...

SOUTH EAST EUROPE WHOLESALE MARKET OPENING

Final report – updated with Ukraine and Moldova December 2011

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PÖYRY MANAGEMENT CONSULTING

NORD POOL CONSULTING

ACKNOWLEDGEMENT

The South East Europe Wholesale Market Opening technical assistance project (the Project) is co-financed by two multi-donor trust funds, ESMAP and PPIAF.

The Energy Sector Management Assistance Program (ESMAP) is a global technical assistance program which helps build consensus and provides policy advice on sustainable energy development to governments of developing countries and economies in transition. For more information on the program see the website: www.esmap.org

The Public-Private Infrastructure Advisory Facility (PPIAF) is a multi-donor technical assistance facility aimed at helping developing countries to improve the quality of their infrastructure through private sector involvement. For more information on the facility see the website: www.ppiaf.org

The Word Bank is managing the Project as a part of its support to the development of the Energy Community. For information about the World Bank's energy sector activities see the website: www.worldbank.org/energy

http://www.esmap.org/

http://www.ppiaf.org/

http://www.worldbank.org/energy


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TERMINOLOGY

The Consultant has used the following terminology throughout the report: (with reference to the United Nations Security Council Resolution 1244 for point 1 and 2):

UNMIK – when referring to the Contracting Party

Kosovo when referring to the geographic territory

Former Yugoslav Republic of Macedonia or FYR of Macedonia

Local – not national

Contracting Party – instead of country

The term Contracting Party will now also include Ukraine and Moldova

Jurisdictions when referring to both Contracting Parties, Bulgaria, and Romania

DISCLAIMER

Pöyry Management Consulting (Sweden) AB and Nord Pool Consulting AS retain all rights (including copyrights, brand rights, patent rights) related to the information in this report.

Pöyry Management Consulting (Sweden) AB and Nord Pool Consulting AS do not permit partial quotes from the study report as this can lead to misleading conclusions.

While Pöyry Management Consulting (Sweden) AB and Nord Pool Consulting AS considers that the information and opinions given in this work are sound, all parties must rely on their own skill and judgement when making use of it.

Pöyry Management Consulting (Sweden) AB and Nord Pool Consulting AS does not make any representation or warranty, expressed or implied, as to the accuracy and completeness of the information contained in this report and assumes no responsibility for the accuracy or completeness of such information,

Pöyry Management Consulting (Sweden) AB and Nord Pool Consulting AS will not assume any liability to anyone for any loss or damage arising out of the provision of this report.


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TABLE OF CONTENTS

REPORT SUMMARY 10

SECTION I: HIGH LEVEL RECOMMENDED MARKED DESIGN 16

1. SUMMARY OF RECOMMENDED MARKET DESIGN AND IMPLEMENTATION 18

1.1 Prerequisites 18

1.2 Choice between different Market Design Options 19

1.3 Conceptual Market Design 23

1.4 Business Processes 26

1.5 Integration with Neighbouring Markets 28

1.6 Transition phase: From regulated prices to market prices 28

1.7 CAO – Coordinated Auction Office 33

1.8 VPP Auctions, Bilateral Auctions and Physical Forward Markets arranged by the Local Market Operators 34

1.9 Gap Analysis 34

1.10 Action Plans 36

SECTION II: BACKGROUND 44

2. THE CURRENT STATE OF MARKET OPENING IN SEE REGIONAL ELECTRICITY MARKET 46

2.1 Introduction 46

2.2 Electricity generation and demand 46

2.3 Regional trade in electricity 55

2.4 Market structure, market opening and market model 62

2.5 Prices and tariffs 69

2.6 Current Balance Management in SEE 71

2.7 Congestion management and cross-border capacity allocation 72

2.8 Inter-TSO Compensation mechanism (ITC) 79

3. EXPERIENCES FROM OTHER REGIONAL MARKETS 81

3.1 Selected Local and regional markets 81

3.2 Review of Regional Markets 89

3.3 Conclusion 94

SECTION III: ANALYSIS 95

4. POSSIBLE CAUSES FOR HIGH PRICES IN THE REGION 97

5. RISKS AND OPPORTUNITIES FOR NON-HOUSEHOLD CUSTOMERS 103

5.1 Key risks 103

5.2 Opportunities 104

6. BARRIERS TO MARKET OPENING 107


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6.1 Prerequisites for market opening and current status 107

6.2 Barriers to market opening 113

6.3 Ways to overcome barriers to market opening 115

7. KEY PERFORMANCE INDICATORS 117

7.1 Prices, transparency and surveillance 118

7.2 Access to markets 119

7.3 Access to customers 120

7.4 Market structure and competition 121

7.5 Balance responsibility and balancing markets 122

7.6 Allocation of cross-border capacities 123

7.7 Network tariffs and grid access 124

7.8 Independent regulators and harmonization of regulations 125

SECTION IV: MARKET DESIGN AND IMPLEMENTATION 127

8. SEE WHOLESALE MARKET OPENING, CONCEPTUAL DESIGN AND REQUIREMENTS 129

8.1 Choice between different market designs 129

8.2 Recommended Conceptual Design 133

8.3 Transition Periods, local markets 135

8.4 Establishment of the SEE Regional market 139

8.5 SEE, an integrated part of the European Internal Power Market 141

8.6 Requirements 144

9. REGIONAL MARKET DESIGN 145

9.1 Introduction 145

9.2 General recommendations 146

9.3 Roles and Responsibilities 151

9.4 Grid Tariffs 153

9.5 The relationship between a Regional PX and the Coordinated Auction Office (CAO) 154

9.6 Details of the Day-ahead Market design 155

9.7 Intraday Market 164

9.8 VPP Auction 165

9.9 Market Information 166

9.10 Market Surveillance 166

9.11 Inter-Regional Market Coupling 167

9.12 Real-time Balancing Market 169

9.13 Financial Market 175

9.14 Organization of the SEE Regional Power Market 177

9.15 Legal issues 181

10. ACTION PLAN 187

10.1 Introduction 187


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10.2 Regional Action Plan 187

10.3 Methodology to Establish Action Plans for Contracting parties, Bulgaria, and Romania 190

10.4 Minimum Requirements 190

10.5 Proposed General Decisions and Commitments 192

10.6 Template for the Action Plans 192

10.7 Action Plans for Contracting Parties, Bulgaria, and Romania 197

10.8 Albania 197

10.9 Bosnia and Herzegovina 201

10.10 Croatia 205

10.11 FYR of Macedonia 208

10.12 Montenegro 212

10.13 Serbia 216

10.14 UNMIK 220

10.15 Bulgaria 224

10.16 Romania 227

10.17 Ukraine 230

10.18 Moldova 234

ANNEX A LIST OF REFERENCES 241

ANNEX B GLOSSARY 243


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EXECUTIVE SUMMARY

The 11th Athens Forum Meeting requested the World Bank to develop a study on Wholesale Market Opening in South East Europe for the benefit of all Contracting Parties to the Treaty establishing the Energy Community.

Pöyry Management Consulting and Nord Pool Consulting were commissioned by the World Bank to develop a study on Wholesale Market Opening for the electricity market in South East Europe (SEE). The key outputs of the study are a Regional Market Design (RMD) and an action plan for its implementation.

A new version of the study was developed during 2011 to include Ukraine and Moldova in the study on the same level as the original Contracting Parties.

Based on the findings from carrying out the various tasks that were assigned, the Consultant recommends the following:

1. To secure liquidity and transparency in the initial operational phase of the wholesale market, local authorities need to support the implementation of SEE Day-Ahead Market (DAM) through the introduction of proper incentives for market participants.

Experience from implementation of DAM projects in Europe indicates that the largest obstacles in the initial stage of operation are the lack of liquidity in the day-ahead market.

2. Carry out a staged implementation of a regional wholesale market with respect to both participating jurisdictions and to market functions

Expanding the geographical scope of the regional wholesale market by gradually adding new jurisdictions, starting with a nucleus consisting of Romania, Serbia and Bulgaria

Transition from 100% regulated prices to 100% market prices, exposing market participants to spot prices on marginal volumes from day one of market opening. Each jurisdiction decides at what speed the transition shall proceed. It is of high importance that demand side volumes are brought to the DAM.

3. Facilitate harmonisation of rules and regulations between the SEE Contracting Parties and relevant EU directives and regulations

A common playing field is a prerequisite for all regional market activities.

4. Set a target completion date of January 1st 2012 for the start up of a SEE DAM market and a target date of Jan 1st 2015 for the full SEE electricity wholesale market opening including a financial forward electricity market.

An ambitious plan is required to comply with the commitments made by signing the EC Treaty by all Contracting Parties including Bulgaria and Romania,


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To achieve these target dates the following decisions by Ministries are recommended:

Give incentives to eligible customers to trade at the DAM

Base load contracts at favorable prices (current tariffs). Remaining volumes must be sourced from DAM

Unbundling of supply and generation functions

Generator – Supplier unbundling, at least removal of traditional Full Supply Contracts between Generators and Suppliers/Eligible Customers

Base load contracts between incumbent generators and suppliers to serve tariff customers. Remaining volumes to be sourced from the DAM

To achieve these target dates the following decisions by TSOs/Regulators ought to be made:

Cross border capacities should be allocated to DAM

Balance responsibility for all wholesale market participants

TSOs to purchase main grid losses at the DAM

Local Market Operators to set up physical forward markets within their jurisdiction with local incumbents as market makers.

Characteristics of the open and competitive SEE wholesale electricity market

Enhanced investment climate in the SEE Region

Merit order in generation and optimal use of cross border transmission capacities

A market model which allows for a quick integration with neighboring CEE- and CWE countries through market coupling. Links to other neighboring countries can be handled like it is done today through explicit auctioning of cross border capacities.

A flexible solution for the regional/local market operators, allowing each jurisdiction to decide which functions to be handled by the local market operator or to be outsourced to the regional entity

Transparency of relevant market information and prices secured by a DAM in parallel with auctioning of bilateral contracts

Equal market access to all

Co-existence of bilateral and exchange trading


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REPORT SUMMARY

Introduction

The main geographical focus of the report is the updated nine Contracting Parties to the Treaty that established the Energy Community, i.e. Albania, Bosnia and Herzegovina, Croatia, FYR of Macedonia, Montenegro, Serbia, UNMIK, Ukraine, Moldova and also the former contracting parties Bulgaria and Romania.

The Contracting Parties to the Energy Community Treaty have legally binding commitments to the creation of an internal market for network energy.

The regional market provided for by the Treaty is to be connected to the EC internal market. Through the Energy Community Treaty, the Contracting Parties are bound to implement the “acquis communautaire on energy”1, the “acquis communautaire on environment” and also follow the principles laid out in the acquis on competition insofar as it may affect the trade of network energy between the Parties. According to the Treaty the Parties shall also implement the renewables Directive 2001/77/EC (promotion of electricity produced from renewable sources) and Directive 2003/30/EC (promotion of the use of bio fuels or other renewable fuels for transport).2

Under the Treaty the regulators are cooperating within the Energy Community Regulatory Board (ECRB). The ECRB advises the Ministerial Council and Permanent High Level Group (PHLG) on details of statutory, technical and regulatory rules and make recommendations in the case of cross-border disputes between the regulators.

The electricity sector in South East Europe is characterized by small, but in many cases fast growing markets. The size of the markets in terms of final electricity consumption varies between 3.2 TWh (UNMIK) and 25.6 TWh (Serbia) in the seven original Contracting Parties. With the addition of Ukraine, they are by far the biggest Contracting Party with final electricity consumption of 123.1 TWh. The region exhibits a mixed generation structure with primarily conventional thermal - and hydro power plants. The nine Contracting Parties are in total import dependent, and some of them are suffering from severe shortages.

The general flow of electricity in the region is from the north to the south. Bosnia and Herzegovina is the only contracting party among the seven that has a surplus and the region as a whole is an importer.

Losses (commercial and technical) are in many cases very high and the economies in the region are generally characterized by high energy intensities/low energy efficiency. The Local markets are in most cases dominated by one (state-owned) generator that supplies at regulated rates to tariff customers. The regulated tariffs, although they might cover the current costs, are generally low and not sufficient to cover the cost of new investments. The tariffs do however vary considerable within the region.

1 Directive 2003/54/EC of the European Parliament and of the Council of 26 June 20003

concerning common rules for the internal market in electricity, Directive 2003/55/EC of the European Parliament and of the Council of 26 June 2003 concerning common rules for the internal market in natural gas, Regulation 1228/2003/EC of the European Parliament and of the Council of 26 June 2003 on conditions for access to the network for cross-border exchanges in electricity.

2 The Treaty establishes that the Parties shall present a plan to implement the directives within one year of the date of entry into force of the Treaty.


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A large number of reports have previously been developed covering these or closely related issues related to regional market integration.

One key question has been, should a regional power exchange be established or should there be a continued reliance on purely bilateral contracts?

Furthermore, the market model currently under development relies on explicit auctioning of cross-border transmission capacities. An alternative option would be the use of implicit auctioning. This would require a liquid market place under a „market splitting‟ approach, or „market coupling‟ between several liquid markets.

According to the Terms of Reference for this study, these options should be reviewed, and based on this review a Regional Market Design should be developed, taking into account the possibility of a staged implementation.

The study assignment included the following eight defined tasks:

Task 1: Review of the current state of market opening in SEE

Task 2: Examine barriers to advancing market opening and liberalisation

Task 3: Identify risks and opportunities posed by market opening in electricity supply to non-household customers

Task 4: Review lessons learned from other regional markets

Task 5: Define indicators to measure and monitor progress in opening the electricity market in SEE

Task 6: Developing the SEE Regional Market Design (RMD) and Action Plan for Implementation

Task 7: Workshops for non-household consumers and other market participants on electricity market opening; and

Task 8: Implementation Support

Below, a high level summary is presented for the work covered under each of the assigned tasks.

Task 1: Review of the current state of market opening in SEE

The review of the current state of market opening in SEE conducted by the Consultant, has found that the market opening process has been initiated at local level within all the contracting parties, Bulgaria, and Romania. It has, however, in the various jurisdictions reached different levels of progress.

For some crucial elements of the opening process, e.g. TSO unbundling and establishing a competent regulatory entity, the progress is very satisfactorily, while for other elements, e.g. competition and transparency, the development is only in its infancy.

Lack of market price penetration to final customers is probably the most serious obstacle against establishing an efficient electricity sector. There are generally no publically available and generally trusted reference prices for electricity. Although the possibility for secondary trading of cross-border capacities exists in a few cases these are not liquid and well-functioning markets. Long-term trade in electricity may function reasonable well, but no organized market place for trade in electricity currently exists.

The key findings made by the Consultant are used in establishing the design of the initial open wholesale electricity market in SEE


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Task 2: Examine barriers to advancing market opening and liberalization

The Consultant has identified several potential barriers to advancing market opening and liberalisation.

Many important prerequisites for a regional market opening are only fulfilled to a limited degree.

The Consultant has defined minimum requirements related to the following issues as a prerequisite to wholesale market opening.

TSO Unbundling

Supplier Unbundling

Eligibility

Balance Responsibility and Balancing Mechanisms

Market Concentration

Transparency

Establishment of a Regional DAM

Fulfilling these minimum requirements leads to a removal of identified barriers in each jurisdiction.

Task 3: Identify Risks and Opportunities Posed by Market Opening in Electricity Supply to Non-Household Customers

The Consultant has identified some key risks for non-household customers posed by market opening:

Risk of increased prices:

Risk of unfair competition

Risk of market power

Volatile prices

Risk of limited real market access

While there are risks that may arise which the customers need to be prepared for, there are also several opportunities arising from market opening:

New investments and increased security of supply

Access to a large base of suppliers

New service offerings

Demand side participation.

Investments in own generation

Improved utilisation of generation and transmission


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Task 4: Review lessons learned from other regional markets

The Consultant has reviewed the various market developments and lesson learned in local and regional markets in EU including the Nordic market.

The most important lesson learned seems to be that there must be a strong political will among the countries involved to create an open electricity market. It seems equally important that the cooperative environment within and between the states involved are good and that the politicians dare to take the necessary steps to create a regional market even though the resistance from some parties can be high.

Task 5: Define indicators to measure and monitor progress in opening the electricity market in SEE

The Consultant has defined 50 Key Performance Indicators (KPIs) to monitor the progress of the SEE wholesale market opening. The KPIs will show the pace of progress and make it possible to take measures, if the process is haltering. Some of the indicators measure whether a necessary instrument that can support the desired development is in place or not, while other indicators measure how well these function. The KPIs have been grouped in the following areas:

Prices, transparency and surveillance

Access to markets

Access to customers

Market structure and competition

Balance responsibility and balancing market

Allocation of cross-border capacities

Network tariffs and grid access

Independent regulators and harmonisation of regulation

Task 6: Developing the SEE Regional Market Design (RMD) and Action Plan for Implementation

The main task of this study has been the development of the SEE Regional Market Design and Action Plan for Implementation.

As a reference for this design the Consultant has chosen as benchmarks the successful implementation of competitive wholesale markets in Europe, which are mainly EPEX, Nord Pool, and TLC.

A starting point has been the findings made by the Consultant regarding the current state of market opening in SEE (Task 1) and the barriers to advancing market opening and liberalization. (Task 2)

These findings reveal major gaps between the current state and what is considered as minimum requirements to proceed with a market opening.


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The large gaps that exist today in most of the jurisdictions, confirm that the transition to an open wholesale market is a major step for the SEE region. A staged approach to a market opening, combined with certain incentives for eligible consumers and public suppliers to source from the open market to secure and promote market liquidity, is therefore an embedded part of the design

In order to co-ordinate the wholesale market opening process in the region an action plan is developed.

This plan comprises decisions/activities that must be fulfilled prior to market opening and is made jurisdiction specific. First the minimum requirements for establishment of a regional DAM are defined. The current status for all Contracting Parties plus Bulgaria and Romania is analysed against these minimum requirements. The difference (gap) between requirements and current situation forms the basis for each local action plan.

A common feature seems to be that TSO unbundling and separation of grid tariffs are very well established in the region. Within Supplier/Generator unbundling, however, much work has to be done. Incumbents hold a much too strong grip on customers. Local authorities have to be engaged in creating incentives for customers and Suppliers to trade at organized market places, such as local DAMs.

Task 7: Workshops for non-household consumers and other market participants on electricity market opening

A workshop was organized in Vienna on September 16th 2009 attended by SEE wholesale market participants including EFET representatives.

The agenda was as follows:

1. Introduction/Welcoming Remarks

2. Barriers and Obstacles to Market Opening

3. Risk and Opportunities for Non-Household Consumers

4. Indicators and Monitoring

5. Regional Market Design

6. Action Plan

7. SEE Wholesale Market – Participant perspective

8. Closing Remarks

Task 8: Implementation Support

This task depends on acceptance of proposed market design and implementation plan from all jurisdictions.


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Reading instruction

The report consists of four main sections as well as three annexes.

Section I (chapter 1) is a high level summary of the recommended market design and action plan. These are the key recommendations from the Consultants and are based on the presentation given at the ECRB meetings and workshop in Vienna in September 2009.

Section II (chapter 2-3) contains background information such as the foundation for the project, the current situation in SEE and experiences from other regional electricity markets. A reader with good insights to the region and the subject may want to skip this section.

Section III (chapter 4-7) contains analysis of possible causes for high prices in the current SEE electricity markets, risk and opportunities for non-household customers in an open and competitive SEE regional electricity market, ,and key performance indicators to monitor the progress of the wholesale market opening.

Section IV (chapter 8-10) contains the market design recommended by the Consultant and the action plan to implement the solution. This section provides more details regarding the recommended market design and details and insight to the high level summary in section I.


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SECTION I: HIGH LEVEL RECOMMENDED MARKED DESIGN


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1. SUMMARY OF RECOMMENDED MARKET DESIGN AND IMPLEMENTATION

1.1 Prerequisites

The framework for the SEE Wholesale Market Opening is set by the Treaty Establishing the Energy Community ref [30] and the EC Treaty, ref [13].

The recommended market design is based on the following basic requirements:

SEE, an integrated part of European Internal Energy Market

Technical operation of the SEE grid system spans 4 control areas within ENTSO-E. With the inclusion of Ukraine and Moldova, a 5th area from UPS/IPS is added. Trade across local borders within SEE is currently based on bilateral contracts and explicit auctions. The proposed market design will bring no change to TSOs scheduling and accounting. A day-ahead-market (DAM) will replace some bilateral contracts.

It is recommended that the SEE Wholesale Market Opening should streamline with European trends with price coupling linking local and regional markets in order to enhance efficiency and transparency. Implicit auctioning fits with EuroPEX-ENTSO-E‟s preferred market coupling mechanisms, (ref chapter 8.5 and [12]).

Existing European Power Exchanges (PXs) bring transparency and predictability to market participants and investors across Europe. SEE countries will benefit from harmonization and integration with these markets.

Regional approaches that choose incompatible solutions would obstruct the process of creating an integrated pan-European power market (ref: [12]).

Local control, regional cooperation

The recommended market design aims at having local responsibility of all the trading processes, procedures and trading platforms including the market opening process itself. Regional cooperation and efficient cross-border utilisation will be secured through coupling of local DAMs. TSOs must allocate cross border capacity to DAMs.

Controlled transition from regulated prices to open market

The process of abandoning regulated prices/tariffs is progressing at different speed throughout the SEE region. The recommended design allows for local preferences with respect to further development of this process. Schemes for vulnerable customer sustain.

Quick establishment of incentives to invest

Generator/supplier unbundling and a number of incentives for wholesale market participants to trade at DAM will secure DAM-liquidity. A liquid SEE market coupled to other European power markets with the same trading regimes will soon establish a reliable and trustworthy price reference for the region. As soon as the reference price(s) for the SEE market is established, investors will find it more favourable to come forward. Publishing SEE DAM prices through EuroPEX daily info systems will be a strong indication of market integration.


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Co-existence of bilateral trade and market operators

Until financial instruments are developed, market participants will need bilateral trade (mid- and long term contracts) to supplement DAM trade to handle price risk

Further development of bilateral markets will be driven by market participants as a response to DAM opening. Auctioning of bilateral contracts rather than or supplementing negotiations should, however be considered to increase transparency in mid- and long term markets.

1.2 Choice between different Market Design Options

Choosing a specific reference market model as the key building block for a competitive wholesale SEE electricity market design, is probably the most crucial decision in the project as this will influence many other factors, such as cost of implementation, liquidity in the market place, and in the end it might decide whether the new regional market will be a success or not, measured in broader terms.

To assist in this choice, the Consultant has used a classical decision matrix, with criteria, options (four alternative models), weights for criteria (0 – 100), and ratings (0 – 10).

The four alternative models that have been assessed are:

The European Model (Euro Model)

PJM (Pennsylvania, Jersey, Maryland)

Bilateral Classic (existing market model for SEE)

Bilateral Auction (auction of contracts instead of negotiations)

The following criteria are used:

1. Security of Supply

2. Enhancing Investment Climate

3. EU Mainstream

4. Efficient Utilization of Transmission Grids and Generation

5. Market Price Reference

6. Integration of Renewables

7. Transparency

8. Implementation Costs

Criteria 1-4 are the primary ones given a weight of 100, while criteria 5-8 are secondary and given a weight of 60. Each of the models is evaluated against the chosen criteria.


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The following arguments are used for giving variable scores on how these models match the criteria:

Security of Supply:

Security of Supply is a focal point independent of the model chosen for the wholesale market. It has to be assumed that the necessary measures are taken by the TSOs to maintain the required level for security of supply whichever solution is implemented. Hence the rating is set to 10 (maximum) for all the options.

Enhancing Investment Climate

The Euro Model and PJM are given a high score, while the bilateral models are given a low score.

Investors in generation will also seek a location/market that will offer effective hedging instruments, which will be an effective tool to mitigate the financial risk to an acceptable level. Hedging instrument can range from long term bilateral contracts to liquid financial electricity contracts, where the latter might be the preferred option as it offers a much larger flexibility in adjusting positions in a portfolio

The reason for giving a score of 10 and 8 to the two former models respectively is that the Euro model is in line with the rest of Europe, and will offer especially European investors an alternative to investment in Western Europe. Bilateral market models are given a low score as they offer market places with less transparency and less liquidity, which represent a higher risk scenario to investors

EU Mainstream

The Euro Model is linked to the trends and development of the European electricity market and given the high score of 10.

Efficient Utilization of Transmission grids and Generation

The Euro model and PJM get the high score of 8 since both models provide a merit order use of generation and high utilization of transmission capacities. PJM provides more accurate locational signals through Locational Marginal Pricing (nodal pricing).

Market Price References

The Euro model gets the highest score of 10 as this design provides for the use of zonal rather then nodal market price references.

Integration of Renewables

Large scale integration of renewables is an increasing challenge to any market model worldwide. Different models are however likely to cope with the challenge of renewable and intermittent generation differently. In a future with large amount of renewable and intermittent generation the requirements on the system to handle large fluctuations in output and use of the grid will increase.

The PJM model combines an independent system operator with nodal prices with integrated markets for capacity and ancillary services. This may be a model that is better in handling large amount of renewable generation compared with the Euro model with national or zonal prices and a less strong link between spot markets and transmission companies (see e.g. ref [22]). With this background we have given the PJM model a score of 7, the Euro model a score of 5 and the two bilateral models a score of 3.


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Transparency

PJM is given the highest score of 10 as it provides more access to cost data for generation. Compared to the other models The Euro model is based on portfolio bidding into each bidding area which gives less transparency and also self dispatch of generation which might provide less information for TSOs entering into real-time operation

Implementation Costs

The bilateral classical model is given the highest score as it requires no major changes compared to the current operation in the SEE region. Experience indicates that the implementation of the PJM model is costly.

Summary assessment

Based on this assessment the Consultant recommends the Euro model market design for the SEE region.

The decision matrix is shown in Table 1.


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Table 1. Decision Matrix evaluating four alternative market models

EURO MODEL EURO MODEL PJM PJM BIL CLASSIC BIL CLASSIC BIL AUCTION BIL AUCTION

Criteria Weight Rating Score Rating Score Rating Score Rating Score

0 - 100 0 - 10 0 - 10 0 - 10 0 - 10

Security of Supply 100 10 1 000 10 1 000 10 1 000 10 1 000

Enhancing Investment Climate 100 10 1 000 8 800 2 200 4 400

EU Mainstream 100 10 1 000 2 200 1 100 6 600

Efficient Utilization of T&G 100 8 800 8 800 3 300 6 600

Market Price Reference 60 10 600 8 480 2 120 5 300

Integration of Renewables 60 5 300 7 420 3 180 3 180

Transparency 60 8 480 10 600 1 60 6 360

Implementation Costs 60 5 300 1 60 10 600 8 480

Grand Total 5 480 4 360 2 560 3 920

Alternative market models for the competitive wholsesale SEE electricity market


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1.3 Conceptual Market Design

Deregulation of the SEE wholesale electricity market aims at increasing efficiency and promote investments in the power business in the region. Integration with other European power markets will be to the benefit of the region and each of the countries. Hence, a wholesale market design that facilitates such integration has been a prerequisite for the Consultant when developing the proposed market design.

Figure 1 illustrates the recommended conceptual design.

Figure 1. Conceptual design

The basic elements of the proposed market design are:

1. Local Day Ahead Markets (DAM) combined with bilateral trading and physical forwards organized by local Market Operators.

2. Implicit auction of cross border capacity

3. Balancing responsibility for wholesale market participants

4. Real Time Balancing Market

5. Transparent Market Data

6. Market Surveillance

7. Intraday Market

8. Capacity Reserve Market

9. Financial Electricity Market

During the initial phase of the wholesale market opening efforts should be focused on the first six points.

SEE Regional Power MarketOrganized and bilateral market

one day ahead- auction trade -

Derivatives

Additional Services

Security - Margins - Business reports

Mark-to-Market, Risk Management

Clearing of Bilateral Derivatives

Physical &

Financial markets

Clearing house

Market Operator

DAM

Marketequilibriumhours ahead

- cont. trade -

Hedging

1 day - years ahead- continuous trading -

Balancing

generation

and consumption

in realtime

Services

during the Real-

Time-Operation:

Controlling

frequency and

voltage etc.

BalancingPowerMarket

SystemOperation

Real-TimeOperation

Intraday

FuturesDays Weeks

ForwardsMonths Quarters Years CfDs

Common SEE


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A detailed description of the market design is given in Chapter 8 and 9.

This market concept will offer a number of advantages as it will expose market participants – generators and consumers – to market prices on marginal volumes from day one of market opening and thus provide for

Enhanced efficiency within generation; merit order in all jurisdictions

Improved utilization of cross border transmission capacities; hourly aligning cross border flows in the direction low to high area prices

Alleviating grids during peak hours through reduced withdrawal of flexible loads

Market price signals to be used for system (generation and transmission) expansion planning

High level market design elements:

Staged implementation of a regional wholesale market with respect to both participating jurisdictions and market functions

Parallel development of regional and local markets is a must as the high market concentration in each jurisdiction prevents the establishment of independent local markets.

A regional wholesale electricity market founded on a Day-Ahead Market (DAM) with local DAMs linked together through implicit auction

Flexible solutions for the local DAMs. Each jurisdiction decides which functions to implement on its own and which functions to purchase from a regional service provider.

Local Market Operators set up physical forward markets within their jurisdictions with local Incumbents as market makers.

Introduce transitional incentives for eligible consumers and public suppliers to source from the open market to promote and secure market liquidity. During the transitional period, volumes at a regulated and favourable price will be gradually reduced. The local authorities must decide on the duration of the transitional period. As the success of this design depends entirely upon sufficient volumes nominated at DAM (liquidity), political support is strongly recommended to

Incentivize eligible customers to nominate volumes at DAM

Ensure that public suppliers purchase parts of tariff customers‟ consumption from DAM

Make TSO purchase main grid losses from DAM

Eligible customers can be encouraged to trade at DAM in different ways.

Local markets that allow eligible customers to stay under regulated prices can negotiate special base load contracts – with reduced volumes year by year - for eligible customers if they accept to take the remaining volumes from DAM. In this way eligible customers will have predictability over the transitional period

Local markets that have decided to exclude eligible customers from tariff prices, but experience that competition is not working - might as well offer base load contracts to eligible customers given that they take remaining volumes from DAM.

The most important decision to secure DAM volumes will be to cancel full supply contracts between incumbents and public suppliers serving tariff customers. Full supply contracts prevent volumes to come to the market. They should be replaced by base load contracts covering a certain share of tariff customers‟ yearly energy consumption. Volumes will be reduced year by year based on political


25



considerations. The remaining part of tariff customers‟ load should be purchased by public suppliers from DAM

Specific design elements:

Balancing /Ancillary /Reserve markets

Balancing Responsibility for wholesale market participants. This will provide the market participants an incentive to trade into balance before entering real-time operations

Day-Ahead Market and allocation of cross border capacities. It is assumed that the Coordinating Auction Office (CAO), on behalf of the TSOs, calculates the cross-border capacities to be allocated.

Physical forward markets, organized and bilateral

Financial forward markets, organized and bilateral

Linking neighbouring markets to the regional SEE market

Generic design considerations

Promote competition between organized markets and bilateral trade

Ownership and governance of regional and local market entities

Sustaining the current arrangement of providing electricity at favourable tariffs to vulnerable customers

Allow local incumbents to expand beyond domestic markets in the SEE region, rather than splitting up these companies as they are rather small measured in revenue or TWh compared to the 20 largest generators in the European market.

Enhancement in regional investment climate for new generation. A regional open wholesale market linking SEE to a pan European electricity market, will secure the investors transparency in market data and confidence in market prices

Flexibility through hourly DAM contracts for generators and consumers

A Generator will, through his access to DAM, at any time have incentive to reduce his production if DAM offers cheaper power. Consumers with flexible load will in the same way have incentive to reduce marginal demand (controllable load) during periods with very high prices. In this way all generation, consumption and transmission will “adapt” to market prices throughout the SEE region based on bid/offers of marginal volumes in the open market


26



1.4 Business Processes

The Consultant recommends a decentralized design.

Each Contracting Party (CP) has its own Local Market Operator (LMO);

Each market participant has an agreement with his Local Market Operator;

All bidding, settlement, collateral and participant agreements are made between the market participant and the Local Market Operator;

The Local Market Operator will collect and validate all bids from its participants and creates one Net Export Curve (NEC) combining all the bids from its market participants into one aggregated bid curve (thereby anonymous) that is sent to the SEE Market Service Provider (SEESP) acting on behalf of the Regional PX;

SEE Market Service Provider will collect the Net Export Curves from all Local Market Operators, and will get Available Transmission Capacities (ATC) for all interconnections from the CAO. Based on these data, the SEE Market Service Provider will calculate a common price index for all areas and price for all individual areas as well as the flow on each interconnection. These values will be returned to the LMOs;

Local Market Operators will have a service agreement with the SEE Market Service Provider for the price calculation as well as with the CAO for the allocation of ATCs to be utilized for DAM;

Prices and volumes for each market participant are calculated by the Local Market Operators.

This design is based on Price Market Coupling.

The business process overview is illustrated in the figure below and discussed in details in chapter 9:

Figure 2 Business process overview


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The proposal is based on three (chronological) processes:

1. ATC publication – the publication of ATC from CAO (as representatives for the TSOs) to the SEESP, the Local Market Operators and the participants

2. Bidding process – the process where participants submit individual portfolio bids to their LMOs, the LMOs create NEC curves and submit these to SEESP

3. Results – where SEESP calculates area prices and flows based on the received NECs and ATCs, sends the results to the LMOs and then the LMOs check results and calculate and send the individual results to the market participants.

Figure 3 High-level recommended solution – local control – regional cooperation

Market Participants

Bidding

Results/Settlement

NEC NM2

Regional Price Calculation

SEE Service provider

=NEC NM2

+ + ATCall

ATCall

Flowall ICs

Calculation of TC for all interconnections

CAO

Market Operator 1

Scheduling

Bidding process

Create NEC

Bids

ATCall ICs

Prices all areas

Flow all ICsResults

Market Operator n

Scheduling

Bidding process

Create NEC

Bids

Results

NEC NM1

Prices all areas

Flow all ICs

Market Participants

Bidding

Results/Settlement

NEC NM1

Connection flexibilityLocal control –

regional cooperation

1

1

1

2

2

2

2

3

3

3

3

3

3 3

3

2

2


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1.5 Integration with Neighbouring Markets

A liquid SEE wholesale market coupled to other European power markets with the same trading regimes will soon establish a reliable and trustworthy price reference for the region and attract investors.

Implicit auctions will link local SEE DAMs to neighbouring DAMs. Transitional solutions with reservation of minor cross border capacities for explicit auctions might be required.

Exchange with neighbouring countries with no DAM will run like today, based on explicit auction and bilateral trade.

Imbalance handling and settlements must be harmonized according to common rule books.

Integration of European spot power markets made a big step forward when The power exchanges APX-Endex, Belpex, EPEX Spot, GME, Nord Pool Spot, and OMEL March 18th this year announced the creation of a six party project aimed at delivering a single price coupling across the Nordic, Central West and Southern European regions, potentially as early as next year. The Price Coupling of Regions (PCR) project will address the implementation of a common price coupling solution through which spot electricity price formation will be coordinated in an area potentially covering approximately 2,900 TWh per year of power consumption. The initiative is open to other power exchanges and market areas joining on fair and equal terms and represents a development towards a truly integrated European spot market for electricity.

1.6 Transition phase: From regulated prices to market prices

Exposing eligible customers fully to market prices from day one of the wholesale market opening process will meet hindrance in most countries due to uncertain market prices and their volatility. For this reason transitional schemes should be considered. The need for such schemes will vary across the region, because each jurisdiction has a different starting point.

Some countries have already taken steps to expose eligible customers to market prices. In general a transition period with steadily decreasing contract volumes supplied at regulated prices is recommended to gain acceptance among market participants. This solution is illustrated in the figure below.


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Figure 4 Transitional period – market and regulated prices – Eligible Consumers

Incentive contracts should be established prior to market opening as an offer to eligible customers. This will give them the necessary predictability and they will respond to market prices from day one. They can profit from reducing consumption during peak prices.

During the transition phase – or in general in market opening - the challenge is to establish sufficient volumes (liquidity) on the DAM. It is therefore important that the demand side bid for volumes themselves.

Full Supply Contracts - meaning that the customer can consume any quantity at a fixed contract (tariff) price - between Generators and customers are the greatest obstacle to DAM liquidity. In this situation the Generator will give a net bid on the DAM and purchasing volumes will be very low.

Full Supply Contracts between Public Suppliers and customers, on the other hand, can be accepted as long as the Supplier purchases additional volumes on the market and consequently pays market price for marginal volumes.

Base load contracts between Generators and Public Suppliers to serve Tariff Customers will bring remaining volumes from the demand side on the market.

The following figures illustrate how this design works.


30



Figure 5 Recommended transitional design per jurisdiction

Bilateral trade will focus on mid- and long term agreements while DAM will offer market participants an instrument to fine-tune their hourly supply/demand balance (contract portfolio).

If incentives are necessary to motivate eligible customers to exercise their eligibility from day one of market opening, base load contracts with Generators – declining over time - can be a solution, in line with the arrangement proposed for serving tariff customers.

In order to increase liquidity, TSOs should buy grid losses from DAM.

A simple contract portfolio for a Public Supplier serving Tariff Customers is shown below. Base load contract between Public Supplier and Generators (incumbents) and hourly contracts from DAM filling the gap between the base load contract and estimated consumption.

Pass-through mechanisms of electricity prices to regulated tariffs are required to avoid setting Public Supplier at risks.

G

PS/S

Traders

TC EC

TC = Tariff Customer

EC = Eligible Customer taking balance responsibility himself

EC1= Eligible Customer staying under a portfolio manager

PS = Public Supplier

PEXDAMTSO

EC1

Import/

export

losses

EC1

Base Load Contract to TC

Full Supply Contract

Ordinary trading channels


31



Figure 6 Public Supplier with trading portfolio for Tariff Customers

Traders, Eligible Customers and Suppliers will in general have a more complex contract portfolio, established over time in order to minimize cost, but the principles are the same. Hourly contracts from DAM fill the gap between contracted volumes and estimated load. They “trade into balance”.

Deviations from expected load will be handled on the imbalance market – or later when implemented – on the intraday market. The structure of such a contract portfolio is illustrated below.


32



Figure 7 Trading portfolio for Eligible Consumers & Suppliers

Generators, Suppliers and Eligible Customers will in this way be exposed to market prices on marginal volumes, increasing over time as volumes for eligible customers and tariff customers are scaled down. These volumes, together with export/import volumes will give DAM liquidity. Market prices will therefore be established from day one of market opening with sufficient liquidity.


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1.7 CAO – Coordinated Auction Office

As described in chapter 2.7, when a well-functioning DAM for the whole region is in place, all available transmission capacity should be made available for the implicit auction. This implies that in the final solution, long-term transmission capacity auctions will not be needed. For the SEE Regional Power Market the main function of the CAO is to provide correct transmission capacities to the market independent of the market concept.

The following simplified diagram is an illustration of the co-existence of CAO and a SEE Regional Power Market:

Figure 8 CAO functions in the Regional PX

Dedicating cross border capacity to the SEE Regional Power Market is an essential policy decision in order to establish a Regional PX. The CAO will be responsible for determining tradable cross border capacities, performing explicit auctions and providing the Regional PX with daily capacities for the implicit auction. In this way the two concepts mutually support each other.

It is important to stress that explicit and implicit auctions cannot be efficiently implemented on the same electrical borders in the Day-ahead time frame.

A regional balance management concept (BETSEE - Balancing Energy Tool in the SEE) is under consideration among SEE TSOs. This will be a useful instrument to handle imbalances, but it should use free transmission capacity (not allocated) only. Reservation of cross border capacities for balancing purposes will necessarily reduce DAM liquidity. DAM liquidity is the number one requirement when opening the regional wholesale market.

Intraday/

Balancing Mechanism

Long-term auction

(year,quarter,

month, week)(Y% available)

Transfer to DAM(Use It Or Get Paid)(Z)

DAM utilization(TCDAM )

CAO Explicit auctions Day-ahead implicit auction

Calculation of available transmission capacity for DAM implicit auction

(performed at 10:00 D-1):

TCDAM= D + rest of Y + Z + released portion of X

in both directions

The remaining capacity after DAM is available for Intra-day trading

Security margin(X% margin)

DAM reservation(D% reserved)

TSO allocations


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1.8 VPP Auctions, Bilateral Auctions and Physical Forward Markets arranged by the Local Market Operators

A VPP (Virtual Power Plant) auction is a mandatory auction of generation capacity in order to mitigate incumbents‟ dominant market position. The buyer gets a contract (base or peak) at auction price, but the owner of the VPP operates the plant independently of how the buyer nominates capacity from the plant.

The proposed market solution implies that incumbents serve tariff customers through a base load contract with the public suppliers.

Such a contract reduces incumbents‟ dominant market position in the same way as VPP auctions. The only difference is that prices are set differently.

For this reason, the Consultant does not see the need for VPP auctions from day one of market opening. VPP auctions might be considered later when downsizing of volumes for tariff customers has “strengthened” incumbents‟ potential dominant market position.

VPP Auctions serve however other important missions: They bring transparency to the forward market and offer hedging instruments to market participants.

Auctioning of bilateral contracts brings transparency, but volumes are not guaranteed unless local authorities come up with special regulations.

A market based solution which combines transparency and (minimum) liquidity is much to prefer rather than mandatory schemes. The Consultant recommends a solution in which local Market Operators set up physical forward markets within their jurisdictions with local Incumbents as market makers.

Physical forward markets will soon be changed into financial forwards as this is a much more flexible solution. This process will be driven by market participants.

1.9 Gap Analysis

The restructuring of the local electricity markets has already been initiated. The required unbundling of transmission and generation is completed, while needed transparency of i.e. market information and competition are far from satisfactorily and clearly lagging behind the development in the rest of Europe.

The table below summarizes the gap analysis for all jurisdictions (further details given in Chapter 10).

The gap analysis clearly indicates that major changes have to be implemented if a market opening is going to be successful. This is reflected in the action plans.

.


35



Table 2. Summary of gap analysis

TSO Unbundling

Supplier Unbundling

Eligibility Balance Responsibility, Mechanisms


Transparency Establishment of DAM

Albania

BiH

Croatia

FYROM

Montenegro

Serbia

UNMIK

Bulgaria

Romania

Ukraine

Moldova

Legend: green = no gap, yellow = minor gap, red = large gap, green +yellow and yellow +red indicate in between gaps


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1.10 Action Plans

Complete regional and local action plans are given in chapter 10.

It has been stipulated in the action plans that the opening of the wholesale electricity market can be achieved by January 2012. It is important to note that the implementation entails parallel activities at local and regional level. Due to large incumbents in most of the jurisdictions no local market can exist on its own, but only through the co-existence with other local markets forming a regional SEE electricity market.

A bilateral market will operative side by side with an organized DAM. When the market price in a DAM has gained the necessary trust and recognition, a financial electricity mid- and long-term market can offer trade in derivatives with reference to local and regional market price indices.

The completion of these changes in wholesale market operations should be completed by January 2015. The latter is according to the Energy Treaty agreement signed by all contracting parties

1.10.1 Regional Action Plan

The regional action plan contains the following summary activities:

Review and Acceptance of Market Design

It is estimated that the review of the final report and the acceptance of the proposed market design for the SEE wholesale market can be completed by June 30th 2010.

Project Establishment

Following the acceptance of the market design the regional project can be initiated with the following actions:

Select Regional Project Manager (PM)

Establish detailed project plan, budget, and financing plan for SEE Wholesale Electricity Market Opening project

Approve project plans, budget and financing

Appoint project members from each CP/Stakeholder to form the Regional Project Team

Arrange kick-off meeting at the end of August 2010

Regional Activities

It is recommended that the project is organized as part of the EC/Athens Forum process and that the PM reports status to ECRB/PHLG four times annually


37



Legal

A number of agreements have to be negotiated at the regional level. This will entail at least the following:

Agreement Regional Market Operator – Regulators for Contracting Parties

Agreement Regional Market Operator - TSOs for Contracting Parties

Agreement Regional Market Operator - Market Operators for Contracting Parties

The regional entity has been termed Regional Market Operator. This can be established as an agreement only between participating contracting parties. Alternatively a more formal legal entity can be incorporated being the legal counterparty to market operators in all Contracting Parties.

Establish wholesale SEE regional market frameworks and detailed design

Based on the accepted SEE market design and relevant EU directives and regulations, the frameworks and detailed specification for the SEE regional market must be established

Coordinate project activities in Contracting Parties

The Regional Project will be responsible for coordinating the activities including the necessary harmonization of market and grid codes in each Contracting Party

Procurement/Implementation/Installations/Testing of Regional IT systems

This activity must be coordinated with a similar activity for each of the local markets.

Trials and Operations Regional DAM

Regional Market Trials must be run prior to going live with DAM trades. This will be a common activity involving the participating market operators and stakeholders in all the Contracting Parties, Bulgaria and Romania

Go Live SEE Regional Power Market (DAM)

It is stipulated that the Regional DAM can go live January 2012.

Physical/Financial Forward Electricity Market

As soon as a DAM price is established, financial electricity products should be offered in line with requirements from all local participants and international traders.

On the next page is shown a detailed Gantt diagram for the regional project. The duration of this project will span from start–up in mid 2010 to the end of 2014.


38



Figure 9 SEE Wholesale Market opening – Initial setup

Impl. auction

Preparing for impl.

auction

Explicit auction

HU

Candidates

MD

UKR


39



Figure 10.Gantt diagram for Regional Action Plan:


40



1.10.2 LOCAL ACTION PLANS

In chapter 10, specific local action plans are developed for each jurisdiction taking into account the gap analysis, where it is documented the deviations between minimum requirements for participating in an open wholesale market and the current status in each jurisdiction.

The list of decisions is tailor made for each jurisdiction within the following areas:

TSO Unbundling

Supplier Unbundling

Eligibility

Balance Responsibility and Balance Mechanism


Transparency

Establishment of DAM

A template Gantt diagram for the local action plans is presented in Figure 11.


41



Figure 11. Action Plan Template for Contracting Parties, Bulgaria, and Romania

Completed activities are marked as milestones per Jan 1st 2010 and with green text.


42



1.10.3 Dry run

A dry run serves several different purposes:

simulate a regional competitive market;

train market participants;

simulate different market setup scenarios.

Prior to market opening such exercises will prepare market participants and facilitate a smooth market opening. The idea is to simulate a DAM through bids and offers from Generators, Suppliers, Traders and Eligible Customers.

Cross border capacities and base load contracts to serve tariff customers have to be allocated. In order to simulate the effect of electricity exchange with neighbouring countries, existing bilateral contracts may be represented by price independent bids in the relevant bidding areas. The DAM simulator will calculate area prices and flows on interconnections.

Training of market participants can go on until real market opening takes place and even beyond to familiarize new market entrants. Simulations of future market development will be ongoing activities.

1.10.4 Action plans – market participants

Generators, Suppliers, Traders and Eligible Customers all have to establish new operational working routines in order to handle new market opportunities and challenges. Long and short term power price variations call for hedging strategies. This will be a core business for Traders, Generators and Suppliers. Eligible Customers will choose different solutions. Large industries could develop their own trading skill (figure below) while small enterprises could buy portfolio management services – including imbalance management - or stay at a market based contract price (fixed or variable).

Illustration of a big industrial customer‟s possible organization of power sourcing after establishment of a DAM is shown in Figure 13 below.


43



Figure 12 Power sourcing on a liberalized market – example for Industry

A condensed overview of new tasks for market participants is given below.

Figure 13 Action Plans for different types of Wholesale Market Participants

Generators and big Suppliers will need this competence in-house. Eligible Customers can outsource power procurement, balancing and trading in different ways as discussed above.


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SECTION II: BACKGROUND


45





46



2. THE CURRENT STATE OF MARKET OPENING IN SEE REGIONAL ELECTRICITY MARKET

2.1 Introduction

The following sections set out a quantitative summary of the regional electricity sector under the following topics:

electricity generation and demand;

electricity imports and exports;

market structure and market model; and

prices and tariffs.

Pöyry makes long range electricity and gas market price projections for the region, with the exception of for Ukraine and Moldova, as part of its pan-European market modelling, designed for use by investors in project evaluation, and updated quarterly. Data items with a source labelled "Pöyry EurECa3 analysis" are based on this modelling work. No modelling work has been made explicitly for this project, but we have drawn on results from other studies.

The statistical information in this section sets out a background which emphasises the need for:

efficient dispatch and cross-border trading arrangements between the Parties and with the surrounding countries;

increases in consumer tariffs to economically efficient levels, which will lead to a reduction in inefficient patterns of electricity consumption,

improved levels of payment for electricity; and

very high levels of investment in generation and network infrastructure.

The necessary investment, reduction in inefficient consumption and improvements in the efficiency of generation production can only realistically take place with a move to market-based (marginal) wholesale pricing and regional coordination.

2.2 Electricity generation and demand

Small, but growing, local markets4

Figure 14 shows that the size of the markets, in terms of final energy consumption, varies widely, but also that most of the markets are small. The smallest market in energy terms is UNMIK with a final electricity consumption of 3.2 TWh (2005), closely followed by Albania, Montenegro and Moldova. The largest is Ukraine with a final electricity consumption of 123.1 TWh (2005), followed by Serbia with 25.6 TWh (2005). The final electricity consumption in

3 EurECa is the name given to Pöyry‟s pan-European electricity model. 4 2005 data from IEA has been used to ensure cross-jurisdiction consistency. Later IEA

data does not provide data for all Contracting Parties. A comparison with 2007 data indicates that the regional electricity consumption has increased by approximately 15% between 2005 and 2007. Although there are differences in the consumption growth between countries the overall pattern remains unchanged.


47



Ukraine is then five times as large as in Serbia, as the second largest country, and close to 40 times as large as in UNMIK, the smallest country. Network losses5 are generally quite large ranging from 14% in Croatia, up to 37% in UNMIK, with an average of 21%. The electricity consumption is expected to grow rapidly over the coming years, which implies significant requirements on new generation investments.

Figure 14. Final electricity consumption and network losses (2005) and expected consumption year 2015, TWh

Source: Energy in the Western Balkans, IEA 2008; Eurostat for Bulgaria and Romania; Pöyry EurECa analysis, Energy strategy of Ukraine til 2030, Moldova and Transnistria statistics

High energy intensities – low energy efficiency

The economies in the region generally have high energy intensities. As is displayed in Figure 15 below, energy intensities are considerably higher than the average OECD level ref [23]. This is explained by the degraded state of energy infrastructure, high energy losses in transformation, transmission and distribution and inefficiency in the end-use sector. The high network losses shown in Figure 15 are an illustration of this.

The energy intensities of Montenegro is a bit misleading in the figure as a large portion (approximately 40%) of the electricity is used by an aluminium plant, KAP.

Croatia has relatively high energy efficiency, but according to IEA (ref [23] the jurisdiction still has an energy savings potential of around 25% of the total primary energy supply. The region as a whole could save 13.4 TWh annually by bringing losses down to the level of Croatia. At the same time high energy prices and high energy consumption put a significant

5 Including transmission and distribution technical losses and commercial losses.

3,2 3,6 3,8 6,2 7,7

14,4

25,6 27,9

46,9

123,1

4,5

7,05 9,465,46

10,413,22

22,11

37,5440,5

63,7

199,7

6,505

0

20

40

60

80

100

120

140

160

180

200

0

20

40

60

80

100

120

140

160

180

200

UNMIK Albania Montenegro FYR of Macedonia

Bosnia and Herzegovina

Croatia Serbia Bulgaria Romania Ukraine Moldova

Final electricity consumption, TWh Network losses, TWh Expected electricity consumption (2015)


48



pressure on household budgets, and it is estimated that 16% of the people are exposed to energy poverty.6 It is reasonable to believe that the current high energy intensities/low energy efficiency are likely to be affected by changes in prices that a market opening could result in for some of the countries. Given the starting point, increased energy efficiency can also mitigate the economic impact of possible increases in electricity prices.

Figure 15 does also display that the Parties have high carbon intensities compared to OECD averages. Serbia has the highest level of carbon intensity (1.2) which corresponds to its high dependency on coal and Albania the lowest (0.3) due to its high usage of hydropower resources.

Figure 15. GDP per capita, electricity and carbon intensity, 2005

Source: Energy in the Western Balkans, 2008; CO2 emissions from fuel combustion 2008 ed, IEA, 2008, IEA Energy Balances for non-OECD countries, Moldova and Transnistria statistics, Pöyry analysis

A mixed generation structure but with import dependency

The region is dependent on imported primary energy, primarily oil and natural gas. Several of the countries are also heavily dependent on import of electricity. The region excluding Ukraine, Romania and Bulgaria is a net importer of electricity, taking into consideration the comments from the report (see Moldovan case – Transnistria region). Lack of reliable electricity supply is generally a serious problem in the region. An IEA report on the Western Balkans, (Ref: [23]) mentions the erratic electricity consumption pattern of the poorer parts of the population as a key factor for concern. This is driven by the fact that fuel wood is used for heating needs by the poor, but during the heating season electric heaters are often used when fuel wood demand spikes. This then exacerbate seasonal and weather related peaks in electricity demand. Extreme peaks can then cause black-outs or require rationing. The utilities are forced to maintain considerable reserve requirements, which then reduce

6 Statement excludes Ukraine and Moldova.

0,3

0,4

0,3

0,7

0,5

1,0

0,7

0,2

0,1

0,50,6

0,2

0,3

0,6

0,4

0,8

0,60,7

1,2

0,7

0,5

1,1

0,9

0,4

0

0,2

0,4

0,6

0,8

1

1,2

1,4

0

5 000

10 000

15 000

20 000

25 000

30 000

35 000

kW

h/G

DP

(US

D, P

PP

); CO

2 M

t/GD

P (U

SD

, PP

P)

US

D (

PP

P)

GDP PPP per capita Electricity intensity CO2 intensity


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potentials for exports and revenues. Low tariffs and payment discipline also limit the revenues.

The total electricity generation in the region7 is a mix between conventional thermal generation, hydro plants and nuclear power, as shown in Figure 16. Other renewable sources, besides hydro, have played a very limited role so far.

Figure 16. Regional electricity generation by fuel 2008, %

Source: ENTSO-E, OST, NERC, Moldova and Transnistria statistics

The generation structure is however very different in the different countries, see Figure 17. Albania gets almost all of its domestic generation from hydro power, but is also to a high degree import dependent. This is in particular the case in drought years. Other countries such as Bosnia and Herzegovina, Croatia and Serbia also get a third or more of their generation from hydro power. On the other extreme of the scale is UNMIK, which gets almost all of its domestic generation from thermal plants (lignite) and which is also import dependent. Ukraine shows a large share of domestic generation from nuclear power (49%), and is the only country with nuclear generation of the Contracting Parties. Many of the countries in the region are import dependent, and some of the countries are heavily dependent on import of electricity. Ukraine and Bosnia Herzegovina are the only two of the Contracting Parties which are not dependent on import of electricity, which the possible inclusion also of Moldova.

It is necessary to add a note about Moldova. In the figure, Moldova is shown as a net importer of electricity. This is due to the fact that the largest domestic power plant in Moldova is located in a region known as Transnistria, which de facto cannot be totally controlled by Moldova. In 2008, only 28% of the final consumption was supplied by internal generation, when excluding Transnistria in the data for Moldova. The sub-national import need of

7 Also including Romania and Bulgaria

16%

31%

31%

7%

0%

15%

0%

Hydro Nuclear Coal and Lignite Gas Oil Mixed fossil fuels Other renewables


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Moldova depends on whether electricity is sourced from the Transnistria region or Ukraine. In 2009 and 2010, no electricity was imported from Ukraine according to Moldelectrica (or less than 0.1 TWh in 2010). If including the generation from Transnistria, Moldova is actually self-sufficient with electricity.

The regional generation mix highlights the importance of trade and the potentially significant benefits that can be achieved through improved regional trade. Hydro and thermal based systems are excellent complements due to the regulation possibilities connected with hydro (with storage), but also the increased security of supply that can be expected. The needs for regional trade is furthermore emphasised by the clear import dependency of some of the countries in the region.

Figure 17. Electricity generation by fuel 2008 by jurisdiction, %

Source: ENTSO-E, KOSTT, OST, NERC, Moldova and Transnistria statistics

Figure 18 shows the peak electricity load in 2008 and expected peak load in 2015 in comparison to the generation capacities in 2008 and 2015 (expected), respectively. This shows that in along with the growth in electricity consumption the peak demand will also grow in most of the countries in the region.8

The capacity margins vary considerable throughout the region. Some countries have very small capacity margins, while others – most notably Romania and Moldova – have a very substantial capacity margin. A similar structure can also be expected to remain in the near future.

With respect to Moldova, it is important to keep in mind the region of Transnistria, where 87 % (2008) of the generation capacity in Moldova is located. This has a huge impact on the

8 The methodology used to forecast Expected Peak Electricity Load in 2015 for Ukraine

and Moldova is based on the same growth rate as expected for Electricity Consumption.

0 %

10 %

20 %

30 %

40 %

50 %

60 %

70 %

80 %

90 %

100 %

Hydro Nuclear Fossil fuels Other renewables Net import


51



picture of the capacity margin in Moldova, which is changed from a substantial surplus to a shortfall of almost half of peak electricity load in 2008 (load data excluding Transnistria).

Figure 18. Peak electricity load 2008 and 2015 (expected); Generation capacity 2008 and 2015

Source: Pöyry EurECa analysis, OST, KOSTT, ENTSO-E, Ukrenergo, NERC, Energy strategy for Ukraine til 2030, ANRE, Pöyry analysis

Table 3 below provides some summary comments on the demand and supply balance for each of the nine Contracting Parties.

0,0

10,0

20,0

30,0

40,0

50,0

60,0

GW

Peak Electricity Load 2008 GW Generation Capacity 2008 GW

Expected Peak Electricity Load 2015 GW Expected Generation Capacity 2015 GW


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Table 3. Comments on demand and supply balance

Demand and supply Comments

Albania Hydro dominated (approx. 98%).

Highly import dependent (24-40% over the last years).

Load shedding required since 1997.

One river system generates 88% of the electricity. Import dependent during droughts.


Approx. 60% thermal, 40% hydro of domestic generation.

In recent years a surplus jurisdiction.

Consumption expected to increase considerable over the coming years and by 2014 be higher than the domestic generation.

Bulgaria Approx. 7 % hydro, nuclear 35 % and conventional thermal close to 60 %.

Net export amounted to 5.4 TWh of electricity in 2008.

Construction of a new nuclear power plant possible.

Croatia Mix between thermal and hydro generation.

Import dependent.

Deficit is expected to grow in the future to a level of approximately 9.5 TWh by 2020.

Hydro and nuclear generation reduced during droughts.

FYR of Macedonia Approx. 75% thermal, 25% hydro of domestic generation.

About 2.5 TWh import of 8.5 TWh consumption.

ELEM has sufficient generation to cover the demand of EVN in terms of energy, but not sufficient capacity to meet winter peak.

Of import of 2.5 TWh about 800 GWh is for tariff customers.

Montenegro Approx. 60% hydro, 40% thermal (lignite).

1/3 or more of supply imported (in 2008 about 40%).

Considerable undeveloped hydro potential.

Romania Almost 30 % hydro, 15 % nuclear and 55 % conventional thermal.

Net export amounted to 4.4 TWh of electricity in 2008.

Significant undeveloped hydro potential.

RES-E is promoted through a market based green certificate system.

Serbia Approx. 75% thermal (mostly coal) and 25% hydro.

Relatively well balance between supply and demand. Previous deficit turned into a small surplus.

UNMIK 97% thermal (lignite).

Import dependent (number).

Load shedding applied.

Only 52% of the delivered electricity billed and of this only 2/3 was collected.

Low availability of existing plants.

High demand growth.


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Demand and supply Comments

Ukraine 49% nuclear, 45% thermal (which of approx. 70% is coal) and 6% hydro

Net export amounted to 5.9 TWh in 2008

Moldova 90% thermal and 10% hydro

Import dependent when taking into account the region of Transnistria

Vulnerability with regards to the region of Transnistria

87% of generation capacity located in Transnistria, whereof 98% of capacity belongs to one power plant

Import possibilities from Ukraine balances the situation with vulnerability due to Transnistria

Need to import balancing power from Ukraine

Source: Team analysis

The discussion and data in the three paragraphs below include all nine Contracting Parties.

The current generation capacity in the region is about 109 GW according to ENTSO-E, Platts and the regulators of Ukraine and Moldova. However, taking the expected availability into account the firm capacity in the region would be approximately 91 GW.9 Particularly for coal and lignite plants the actual available capacities are substantially lower than the reported figures. This implies that the actual base load fossil share of regional capacities is lower than shown in Figure 19.

Figure 20 shows the hourly load in the region for the 3rd Wednesday of each month during 2008. Based on this data the regional peak (in January) was slightly below 60 GW, which is somewhat below the peaks reported in Figure 18. Nevertheless, while the capacity margins are limited for some countries, on a regional level there seems to be a substantial margin between the peak load and the installed generation capacity.

In order to look further into the capacity margin an approximation has been done of the regional generation capacity split into base load and peak load. As has been noted before the regional capacity margin is rather substantial. This is evident in figures below. However, some capacity is currently not producing or is used very sparsely due to the lack of maintenance. Furthermore, a substantial part of the generation fleet will have to be replaced in the future due to old age. The latter is especially true for old coal and lignite capacity. Together with an increasing demand for electricity, regional capacity margin should decrease in the future. Figure 19 below suggests that even the base load generation should be sufficient to cover also the peaks, provided that the capacity is available.

9 Team analysis


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Figure 19. Regional generation capacity split on type of capacity, percent and GW

Source: ENTSO-E and Platts, NERC, Ukrenergo, ANRE, Pöyry analysis

Figure 20. Hourly load, 3d Wednesday in each month 2008

Source: ENTSO-E; KOSTT, OST, Ukrenergo, ANRE. NOTE: For Albania data we only have data for January and July.

BaseloadHydro, 6

BaseloadNuclear, 17

BaseloadRenewables, 0

BaseloadFossil, 57

PeakHydro, 17

PeakFossil, 11

0%

10%

20%

30%

40%

50%

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50 000

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70 000

6 12 18 24 6 12 18 24 6 12 18 24 6 12 18 24 6 12 18 24 6 12 18 24 6 12 18 24 6 12 18 24 6 12 18 24 6 12 18 24 6 12 18 24 6 12 18 24

January February March April May June July August September October November December

Ho

url

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ad

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Moldova

Ukraine

UNMIK

Serbia, excl. UNMIK

Albania

Romania

FYR of Macedonia

Montenegro

Croatia

Bulgaria

Bosnia and Herzegoviina


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Old coal and lignite fired plants in the region

There are approximately 27 000 MW of coal and lignite fired plant in the region with an age of more than 30 years, see Figure 21. 10 Old generation units and an increasing demand in the region will require more generation capacity

Figure 21 Age distribution of Coal and Lignite fired plants

Source: Team analysis based on data from Platts, NERC, Ukrenergo, ANRE. Data for Serbia includes UNMIK and Montenegro due to the data source.

2.3 Regional trade in electricity

The former Yugoslavian transmission system was a 400 kV system spanning about 800 km connected to the ENTSO-E synchronous system. In 1991 it was split in two separate parts. Croatia and the Federation of Bosnia and Herzegovina (within Bosnia and Herzegovina) became part of the ENTSO-E zone 1, while Republika Srpska (within Bosnia and Herzegovina), Serbia, FYRO, Bulgaria, Romania and Greece formed ENTSO-E zone 2. In October 2004 these were again reconnected. The total interconnection capacity (net transfer capacity) in the region was in beginning of 2007 about 5800 MW, which is about 35% of total peak demand in these two zones.

Ukraine and Moldova are in a different situation from the rest of the Contracting Parties, as, with the exception of a smaller part of Ukraine, the countries are synchronised with UPS/IPS (Russia). Only the so-called “Burshtyn Island” in the west part of Ukraine is synchronised with ENTSO-E. Further, to make possible electricity exchanges between Moldova and Romania, a part of Romania is sometimes operated in island mode.

Ukraine and Moldova jointly applied to join ENTSO-E in 2006 and the application was formally accepted by ENTSO-E the same year. A pre-feasibility study has recently been

10 Excluding Bulgaria and Romania.


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started (as of 2011). A discussion of this is added to the respective Gap analysis in chapter 10.

The region in total is dependent on imported energy, primarily oil and natural gas. In general, cross-border electricity exchanges in SEE are somewhat lower compared to other regions in Europe (Ref: [4]. However, the total trade flows between the countries included in Figure 22 was in 2008 above 105 TWh. Looking only at trade flow between the original Contracting Parties11 of the Energy Treaty and the additional, Ukraine and Moldova, trade flow was in 2008 about 39.4 TWh. The total electricity consumption (including network losses and consumption of pumped storage units) in the nine original Contracting Parties and the additional, Ukraine and Moldova, was in 2008 about 348 TWh. Thus, about 11 per cent of the regional electricity consumption was subject to trade between these countries.

The main trading pattern in the region is a flow of electricity from the north to the south, as illustrated in Figure 22). Import is mainly provided from Hungary, Romania and Bulgaria and with Serbia being the main transit jurisdiction.

Figure 22. Net electricity flows, 2008

Source: ENTSO-E, KOSTT, Ukrenergo

NOTE! Detailed data and explanatory note available in Table 4

11 The current seven contracting parties plus Bulgaria and Romania.


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Table 4. Electricity exchanges in South East Europe 2008, TWh12

Source ENTSO-E, KOSTT, Ukrenergo

NOTE! Separate data for UNMIK (UN) is not available from ENTSO-E since ENTSO-E does not recognize KOSTT as a TSO, but are included under the Serbian control area (EMS). We have received data from KOSTT and deducted those flows from the flows for Serbia according to ENTSO-E. All numbers are rounded to the closest 0.1 TWh.

As Table 4 (and Figure 17) illustrates, there are some jurisdictions which are import dependent to a very high degree:

Albania is a net importer (2.1 TWh) with large imports from mainly Greece, but also from Montenegro and to some extent from UNMIK.

Croatia is a net importer (6.6 TWh) with large net imports from Serbia, Hungary and Bosnia and Herzegovina. The jurisdiction also has considerable trade with Slovenia (being a net exporter to Slovenia).

UNMIK is a net importer (0.6 TWh) with large net imports from Serbia, but also net export to Montenegro and FYR of Macedonia (transit trade).

Montenegro is a net importer (1.8 TWh) with large import mainly from Bosnia and Herzegovina, but also from e.g. UNMIK. Montenegro has a relatively balanced trade (on a yearly level) with Serbia, and is a net exporter to Albania.

FYR of Macedonia is a net importer (2.7 TWh) with large import mainly from/through UNMIK, but also from Bulgaria. At the same time, FYR of Macedonia has a net export to Greece.

Moldova is a net importer (2.2 TWh), with import from Ukraine and export to Romania (export of electricity produced in the Transnistria region of Moldova).

Four jurisdictions are net exporters:

12 The numbers in this table also includes transit flows

AL AU BA BG GR HR HU IT UN ME MK RO RS SL UA MD SK PL BY RUSUM

AL 0 0,2 0 0,2 0,4

AU 0,8 1,4 1,2 3,4

BA 2,7 2,1 0,3 5,1

BG 4,6 1,1 0,3 2,4 8,4

GR 1,7 0 0,2 0,1 2

HR 0,7 0 0 4,9 5,6

HU 0,7 5,3 0,1 2,7 0,1 8,9

IT 0 1,8 0,1 1,9

UN 0,2 0,7 2,7 0 3,6

ME 0,8 0,2 0,1 0,4 1,5

MK 0 1,2 0 1,2

RO 3,1 0,7 3,2 0 0 7

RS 2,4 0 2,1 0 3,7 0,6 0 0 8,8

SL 0,9 2,2 4,7 7,8

UA 3,8 1,4 5,0 0,2 0 6,1 16,5

MD 0,8 2,0 2,8

SK 1,2 1,2

PL 0

BY 0,0 0,0

RU 7 7,3

SUM 2,7 1,6 3,3 3,1 7,6 12,3 5,3 6,3 4,0 3,4 3,9 2,6 9,2 6,2 10,6 5,0 0,2 0,0 0,0 6,1 93,3

Exp

ort

er

Importer


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Bosnia and Herzegovina exports mainly to Croatia and Montenegro, but has a net import from Serbia.

Bulgaria exports to Greece, Serbia and FYR of Macedonia, but has a net import from Serbia.

Romania exports to Serbia and Bulgaria, but also to Hungary.

Ukraine exports to Hungary, Romania, Poland and Moldova.

Serbia has a relative balanced trade.

2.3.1 Trading licenses13

Various licensing regimes can create barriers for traders to enter into the market. Requirements for trading licenses exist (or are foreseen) in all participating countries in the relevant region. The licensing regimes often require a registered seat in the jurisdiction which creates an additional burden for international traders.

The licenses are typically issued by the relevant regulatory authority. The trading licenses typically cover wholesale trade, retail supply of eligible customers, cross-border trade and transit, but there are differences. The licensing procedure typically has to be conducted in the local language and relevant documents are in most cases not available on the internet.

There are differences in the maximum time allowed for completing the licensing procedure ranging from 30 days in several countries up to 180 days. In the case of Bosnia and Herzegovina no limit is set. Furthermore there are variations in the licensing fees between the countries, both in terms of structure and levels.

13 A survey on license requirements were made in 2008 and received answers from

Bosnia and Herzegovina, Croatia, Serbia, Greece, Slovenia, Austria, Hungary, FYR of Macedonia and Cyprus. (Energy Community Regulatory Board, Licensing requirements 2008). This section builds on that report unless otherwise stated.


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Task Force (TF) 4 of the ECRB Electricity Working Group has conducted a survey on the licensing requirements in the Energy Community (8th Region).14 The survey does not include Ukraine and Moldova. The TF identified two basic models related to wholesale trading:

Explicit request for license

Explicit request for license and local presence for trade and for transit: Croatia, Bosnia and Herzegovina, Serbia, UNMIK, Albania

Explicit request for license and local presence only for trade and not for transit: Romania

Explicit request for license and wider presence than local allowed only for trade: Hungary

Explicit request for license just for local companies for trade and for transit: Macedonia.

No licensing requirements:

Austria (BRP6-status approved by regulator or member of BRP)

Italy (registration with Market Operator and System Operator)

Montenegro (public procurement rules, no real wholesale market activity)

Slovenia (BRP or member of BRP).

In addition a mixed solution was identified for Greece.

The TF also considered different options for harmonisation such as:

i) harmonisation of licensing procedures

ii) abolition of licenses

iii) fade out of licensing complemented with other measures

iv) one license valid in the region

The recommendation of the TF was to pursue the third option of fade out of licensing combined with other measures.

14 Proposal for a Harmonized System of Wholesale Trade Licensing in the 8th Region,

July 2009


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Table 5. Summary of licensing requirements in different countries

Jurisdiction Trading license required

The license covers Requirement of registered company in the jurisdiction

Reporting

Albania YES Wholesale trade, cross-border trade, transit

YES Wholesale trade, cross-border trade, transit


YES Wholesale trade, retail supply to eligible customers, cross-border trade, transit


Croatia YES Wholesale trade, cross-border trade, transit

YES Wholesale trade, cross-border trade, transit

FYR of Macedonia



Montenegro No license, Public procurement rules

No license, Public procurement rules

Serbia YES Wholesale trade, retail supply to eligible customers, cross-border trade, transit



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Jurisdiction Trading license required

The license covers Requirement of registered company in the jurisdiction

Reporting

UNMIK YES Two types of licenses give the right to wholesale trade: Electricity and natural gas trade license & Cross border transmission of electricity and natural gas

YES Two types of licenses give the right to wholesale trade: Electricity and natural gas trade license & Cross border transmission of electricity and natural gas

Ukraine YES These licenses that is part of the market today: License for electricity producers

License for electricity transmission (Ukrenergo - TSO)

License for electricity distribution (DSOs)

License for electricity suppliers at regulated tariff

License for electricity suppliers at non-regulated tariff

License for wholesale electricity supplier (Energorynok)

License for cogeneration

YES According to the requirements of the licenses

Moldova YES The license for supply covers activities for supply, import and export.

YES According to the requirements of the license

Source: Energy Community Regulatory Board (2008), Albanian Energy Regulatory Entity, ERO, Comment by ECRB 2009, Proposal for a Harmonized System of Wholesale Trade Licensing in the 8

th Region, TF4, ECRB EWB, July 2009, NERC/ANRE

2011


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2.4 Market structure, market opening and market model

In several of the Parties there is one dominant, state-owned generator. There might be some fringe competitors, but each local market can typically be characterised as being very close to a monopoly (with the exception of Romania, Moldova and Ukraine).15 As shown earlier, the local markets are also small except Ukraine, which limits the degree of competition that can be expected on each market in isolation. Distribution and supply are typically also dominated by one company in all Parties, except for Ukraine and Moldova, although there might be some small distributors.16 However, given that the consumers in most cases either are not eligible or not interested in exercising their eligibility this is currently of little importance. The limited interest in exercising eligibility seems to be explained by the fact that most consumers would face higher prices on the open market than under regulated tariffs. Given current regulated tariffs little switching can be expected unless customers are forced to switch (or the regulated tariff is removed for eligible customers).

15 The case for Moldova depends on whether the Transnistria region is included or not in

the analysis of Moldova. Excluding this region, there are four separate generating companies operating in Moldova, even though all are state owned (one however has 64% of installed capacity). Including Transnistria, one power plant owned by Russian Inter Rao has 86% of the installed capacity.

16 In Moldova there are three integrated supply and distribution companies, in Ukraine there are 27 regulated tariff suppliers which are also distribution companies.


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Table 6. Degree of horizontal unbundling of state-owned company

Generation Distribution and supply

Albania KESH 99% market share. In addition to KESH Distribution three private companies share the distribution of electricity in parts not controlled by KESH.


Both electricity utilities in FBiH are heading to legal unbundling between generation, distribution and supply.

Utility in RS has legally unbundled Generation from Distribution and Supply.

Electricity utility of Brcko District still fully bundled legal entity.

Bulgaria No ownership unbundling yet of transmission.

Local electric utility (NEK, 100 % state owned) owns a large number of generation plants.

Process of privatisation.

NEK operates the transmission system.

DSO function unbundled.

Croatia HEP Generation about 80% market share.

TPP Plomin (co-owned by HEP and RWE).

NPP Krsko 50% HEP owned.

Industrial power plants.

Small renewable.

HEP distribution legally unbundled.

FYR of Macedonia

ELEM dominant generator.

TPP Negotina separate company.

Small HPP owned by other market players.

Distributor privatized (Austrian EVN).

Montenegro Two legally unbundled companies. EPCG owns all generation and distribution and supply. Transmission JPC owns and operates transmission.

EPCG functionally unbundled with three divisions (generation, distribution and supply).

A2A, an Italian investor owns about 40% of EPCG. Transmission JPC is fully government owned.

Romania Ownership unbundling of transmission and generation.

Generation predominantly state owned but split into several independent units.

Distribution unbundled and 5 out of 8 regional distribution companies have been privatised.

Serbia EPS 100% of generation. (5 generation companies within EPS)

Legally independent subsidiaries. DSO function legally unbundled from other operations.

UNMIK Generation and distribution/supply integrated


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Generation Distribution and supply

Ukraine One nuclear company which is state owned (49% of generation). Five large companies owning majority of thermal power plants – four state controlled, one private.

On 31.12.2010 there were 40 integrated regional distribution and supply companies, 4 only distribution companies and 286 suppliers at non-regulated tariff (65 of them were working actively).

Moldova Excluding Transnistria:

Four separate companies owning one generation asset each, all companies state owned, largest has approx. 70% of generation.

Including Transnistria:

One dominant generator, MGRES, has approx. 70% of generation.

Three integrated supply and distribution companies.


Vertically unbundling has progressed somewhat during the last years. Albania, Croatia, FYR of Macedonia, Serbia, UNMIK, Ukraine and Moldova have legally unbundled TSO/MOs and Bosnia and Herzegovina has ownership unbundled ISO and TRANSCO, while Montenegro has a functionally unbundled TSO. However, in Croatia the HEP group is made up of multiple companies covering production, transmission and distribution, i.e., the transmission operations is part of the same group as the main generator. However, there is a separate market operator owned by the Republic of Croatia.

The unbundling between generation and distribution (including supply) has however not reached as far. In Albania KESH Distribution is unbundled and about to be privatized. However, KESH Generation is obliged to sell to the wholesale public supplier at regulated prices. In FYR of Macedonia the distributor is now owned by Austrian EVN, but also here the dominant generator, ELEM, is required to sell at regulated prices. Among the remaining Parties generation and distribution/supply are conducted within the same company or group of companies that may be legally unbundled.


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Table 7. Degree of vertical unbundling

Transmission, system and market operator

Generation and distribution

Albania 100% state owned legally unbundled TSO.

KESH Distribution unbundled and about to be privatized. Additional distributors selling in “non-KESH” areas.

KESH Generation obliged to sell to the wholesale supplier.


Independent ISO and TRANSCO. Both electricity utilities in FBiH are heading to legal unbundling between generation, distribution and supply.

Utility in RS has legally unbundled Generation from Distribution and Supply.

Electricity utility of Brcko District still fully bundled legal entity.

Bulgaria 100% state owned (by NEK) legally unbundled TSO.

NEK operates a large number of generation plants but privatization underway.

Distribution unbundled and provided by regional companies (E.ON AG, EVN AG and CEZ a.s.).

Croatia Legally unbundled transmission company, but part of the HEP group.

Market operator 100% state owned (legally unbundled).

HEP a group with multiple affiliated companies in the energy value chain.

FYR of Macedonia 100% state owned legally unbundled transmission system and market operator.

Distributor privatized (Austrian EVN).

Main generator, ELEM, obliged to sell at regulated prices.

Montenegro Legally unbundled TSO, (Transmission IPC).

Functionally unbundled with three divisions (generation, distribution and supply).

Romania 100 % state owned legally unbundled TSO.

Partly unbundling of distribution

Serbia 100% state owned legally unbundled TSO.

Generation and distribution/supply integrated. Legally independent subsidiaries. DSO function legally unbundled from other operations. Generation legally unbundled from other operations (5 generation companies).

UNMIK17

100% state owned legally unbundled TSO.

Generation and distribution/supply integrated.

17 The ownership over all assets of the Republic of Serbia (including transmission system

assets) are pending final resolution of the status of Kosovo and Metohija, pursuant to UN SC Resolution 1244


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Transmission, system and market operator

Generation and distribution

Ukraine 100% state owned legally unbundled TSO.

Generation and distribution is unbundled (some distribution companies own generation units as well, but negligible). However, about 50 % of the generation market is price regulated.

Moldova 100% state owned legally unbundled TSO.

Generation and distribution is unbundled. Prices for all generation in part of Moldova excluding Transnistria are regulated (except for electricity sold by sugar-refinery plants owning CHPs).


Very few end-customers are active on the open market. Typically the regulated tariffs are below the prices available on the open market and the incentives for exercising its eligibility is thus often very limited.

Table 8 provides an overview of the current state of end-user market opening. Formally all the nine Contracting Parties have opened their end-user markets. Albania, Bosnia and Herzegovina, Montenegro and Serbia have formally all opened their markets for all non-household customers. FYR of Macedonia, UNMIK and Moldova have eligibility thresholds based on connection levels (Moldova some additional requirements as well), while Croatia and Ukraine has opened the market for all customers (Croatia in 2008).

In most cases, in spite of opening there has been no or limited market entry. In Croatia eligibility is mandatory for high and medium sized customers, while in FYR of Macedonia eligibility is mandatory for all customers above the stipulated threshold. Discussions to make eligibility mandatory are ongoing also in other countries. In practice this implies that no regulated tariff is available for the eligible customers, but that they have to rely on the market.

An important barrier to market opening is that supply and distribution have, in general, not been unbundled. This can be expected to inhibit market entry, since new entrants may not trust that they will be treated on an equal and fair basis with the distributor‟s own supply business.

Another important barrier is the low regulated tariffs (see also section 0). A key conclusion from IPA (Ref: [25]) was that “…there have been no new entrants and the incumbent has retained 100% market share. This is because the regulated tariffs are below levels at which new entrants would be able to enter the market to compete effectively and have even been stated as being below the wholesale energy price which a new supplier would have to buy energy at”. It is clear that as long as there are regulated tariffs available below the cost for a new entrant, effective market opening will be very difficult to achieve.


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Table 8. Degree of market opening

Eligibility threshold Customers exercising eligibility

Albania All non-household customers.

Customers can apply to become eligible. It has been proposed that all customers on the 35 kV level or above should automatically become eligible.

Currently only 1 customer.

Bosnia & Herzegovina

All non-household customers. They can stay under regulated tariffs and so far no one executes his eligibility.

Bulgaria All customers. Large and medium sized industry.

Croatia All customers. Mandatory for high and medium sized customers.

FYR of Macedonia

Connected on 110 kV. Mandatory for eligible customers.

As of 1 January 2008 there are 8 eligible customers (those connected to 110 kV or above), which implies a market opening of 34%.

Montenegro All non-household customers. Only one supplier. Traders‟ access to final customers is currently subject to consideration.

Romania All customers. Mostly large and medium sized industry.

Serbia All non-household customers (47% formal market opening).

No one executes his eligibility.

UNMIK Connected at 10 kV or above. There are two declared eligible customers

Ukraine There is no definition in of eligibility in the legal framework.

N/A

Moldova Customers connected to the transmission grid, with electronic metering installed and no debt.

3 qualified - 1 only exercising eligibility. According to the law, from 2013, all non-household customers will be eligible and from 2015 all customers including household will be eligible.

Source: Energy Community Treaty Implementation – presentation at 14th Athens Forum, DG TREN Report on progress in

creating the internal gas and electricity market, technical annex. Com(2009) 115, Team analysis

Several countries have market models with a wholesale public supplier. The wholesale public supplier then often has “priority” access to the domestic generation which is ear-marked for domestic consumption (tariff customers). This of course limits the amount of electricity that is available for trade.


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Table 9. Nature of trading model

Albania Market model based on bilateral contracts.

Wholesale and Retail supplier responsible for supply to tariff customers.

Bosnia & Herzegovina

12 traders (incl. 3 Generators). They cannot sell to final tariff customers who are supplied by “their” (3) wholesale Supplier. These Suppliers have “all in” contracts with their respective Generator.

Bulgaria Market model based on bilateral contracts.

Croatia HEP supplies all tariff customers. Eligible customers can by from Suppliers/Traders who have access to export/import

FYR of Macedonia

New market rules under development. MEPSO‟s previous role as wholesale supplier has been abolished.

Montenegro 56 Traders wait for access to final customers. Today only Trader/Trader and cross border exchange

Romania Established power exchange (OPCOM) with good liquidity.

Serbia EPS Mother Company acts as a regulated public wholesaler for tariff customers. Tariff customers are served by 5 retail suppliers for tariff customers which are currently within the DSOs. EPS Mother Company has full supply contracts with EPS Generation.

37 traders have access to eligible customers and export/import.

UNMIK Market model based on bilateral contracts.

KEK regulated wholesale supplier.

Ukraine Single buyer market, WEM

Regulated and non-regulated part of wholesale market

Export/import used to be managed by one single state-owned company, Ukrinterenergo. In 2010, introduced annual and monthly explicit auctions for export transmission capacity.

Moldova Market based on bilateral contracts

Mainly regulated internal market

Wholesale and Retail supplier responsible for supply to tariff customers.

Imports through dedicated company, Energocom, only, but open for other companies (preference of exporters is reason for the current structure)



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2.5 Prices and tariffs

Low – but varying retail tariffs

Figure 23 below shows that Albania has the highest retail tariffs for households and some of the highest retail tariffs for Industrial and Commercial (I&C) customers of the Contracting Parties.

Bosnia and Herzegovina has the second highest retail tariffs for commercial customers, while its retail tariffs for industrial users and households are around the mean of the region‟s values.

Croatia has some of the highest retail tariffs for households, while its retail tariffs for Industrial and Commercial (I&C) customers are around the median of the region‟s values.

FYR of Macedonia is offering some of the region‟s lowest retail tariffs to industrial customers and households, while its tariffs for commercial users are at the median level for the presented countries in South East Europe. From 1 November 2008 all tariffs were increased with about 13%, which is valid until the end of 2008. A new tariff methodology is currently under development.18

Montenegro has the highest retail tariffs for commercial users in the presented markets in South East Europe, while its retail tariffs for industrial customers are varying from close to the mean to the highest of the region‟s values. Its retail tariffs for households are a little higher than the mean.

Serbia has the lowest retail tariffs in the region, right across the three segments of industrial, commercial and household customers. This may be due to a number of reasons, including the protection of so-called vulnerable costumers and some level of support for energy intensive heavy industry.

Ukraine has the second lowest retail tariffs for household and commercial customers in the region, while the level for industrial customers is close to the mean. Tariffs for households are quite substantially subsidized by the other segments. In Ukraine the tariff is differentiated on voltage level, not on customer type.

Moldovan tariff Methodology was changed in 2007 and from 2011 differentiated tariffs according to the voltage level where approved. Households and non household customers connected to the network with the same voltage receive electricity at the same tariffs.

A general feature across the region is that the commercial customers are typically paying more than household customers. This can hardly be explained by differences in the cost structure motivating such differences in tariffs.

18 Interview with ERC, December 2008


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Figure 23. Retail tariffs 2007, €/MWh

Source: ECRB 2008 Market Development Report and Eurostat, UNMIK comment on report, NERC, ANRE, Pöyry analysis

In March 2009 a Study on Tariff Methodologies and Impact on Prices and Energy Consumption Patterns in the Energy Community was published. (IPA, 2009).19 The study concludes that the overall average retail tariff varies considerably between the parties, as is also showed by Figure 23. The study covered tariffs from 2005 to 2008 (2008 not available for all parties), and showed that the tariffs generally have increased over the period and in many cases significantly so.

19 The study was commissioned by the Energy Community and does not include

Romania, Bulgaria, Ukraine and Moldova

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ial

Co

mm

erc

ial

Albania Bosnia and Herzegovina

Bulgaria Croatia FYR of Macedonia

Montenegro Romania Serbia UNMIK Ukraine Moldova

€/M

Wh


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According to the report no jurisdiction (with the partial exception of Albania) used tariff based methods to protect vulnerable customers. However, this seems hard to reconcile with the fact that commercial customers in most cases are paying more than household customers. Although, there might not be lower tariff targeted towards vulnerable customers, the tariffs seems to be kept low in general.

The study also included a review of the cost coverage. This showed differences in the allocation of costs between e.g. transmission and distribution, and also differences in how the return on asset was calculated. The report specifically mentions that Serbia applies a 0% weighted average cost of capital on transmission, in UNMIK “the distribution and transmission system are deemed to be past their useful economic lives and have no value” and in Montenegro it was recognised that the applied cost of capital for both transmission and distribution is below the true cost of capital.

Errors in the rate of return for monopoly operations such as transmission and distribution may not distort the functioning of the wholesale market, as long as the transmission and distribution companies are able to fund the necessary investments, However, the report also states that for the regulated generation tariffs “…as with rate of return for transmission tariffs, the rate of return used may not reflect the full cost of capital of generation because of the assumption that Government as shareholder may prefer to keep prices down rather that obtain a full return on its equity…”. From a market development point of view this is highly problematic since it will provide an important barrier for new entrants in generation in the region.

One important conclusion from the above mentioned study is that “Much of the variation in overall tariff levels between the parties is driven by differences in generation costs and that this is largely related to the type of generation”. A well-functioning regional market can be expected to change this situation, as the wholesale power price can be expected to converge across the region. This would lead to a more efficient price formation, but is also expected to lead to increased profits for the generators having the low cost generation possibilities.

2.6 Current Balance Management in SEE

The level of real time automation and communication in many countries of SEE is still limited (ETSO, Current State of Balance Management in South East Europe, June 2006). Some of the obstacles are that changes to the output of individual generating units cannot be auctioned without substantial manual intervention. Remote metering on some HV transmission network points are not installed and modern SCADA systems are yet to be implemented in some countries.

Balancing mechanisms are still not in place in all countries. This is the case for Serbia, Montenegro, FYR of Macedonia, Ukraine and Moldova. However, all countries have market models (or are implementing market models) which include balancing mechanisms/balancing markets. In Bosnia and Herzegovina a balancing mechanisms is in place and it is one of the responsibilities of the ISO. In Croatia the market operator settles unbalancing energy for balance responsible parties. In Albania the TSO is responsible for the organization and administration of electricity payment settlements among the market participants and manage the imbalance settlements statement process. Also in UNMIK the TSO is responsible for procuring system balance through the balancing mechanism.

South East Transmission System Operators (SETSO) are currently in the design stage of the Regional Balance Mechanism (BETSEE RBM or BETSEE). The aim is to achieve a system that facilitates: technical correctness, effectiveness, truthfulness, individual rationality, budget balance and social welfare.


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This initiative has to be seen in view of the fact that electricity markets in the SEE region are still in the early stages of development. Market operations and their degree of openness vary greatly, traded volumes are low (especially in the short term) and exchanges struggle with low levels of liquidity.

In consideration of the challenging environment the approach was chosen to develop a concept of the RBM that assumes minimal prerequisites regarding the existing market structure.

In an Examination Paper (ETSO, Regional Balancing Mechanism BETSEE for South-East Europe, April 2008) the SETSO Task Force simulated and analysed the potential consequences for SEE countries where the RBM Design (dated Nov 2006) implemented in the Region today (April 2008).

The examination paper concluded20, under the premise that the RBM development in the SEE Region was still an ongoing process and therefore subject to uncertainties that:

Depending on the availability of balancing resources there will be parties having benefits and parties facing disadvantages in case of a jurisdiction deciding to join the RBM.

The absence of a transparent balance energy price is a challenge for the RBM, short term markets are underdeveloped and cross-border transfer prices for balancing can not be accurately accessed, this could cause irregularities in the function of RBM.

It is expected that the RBM will have low liquidity as a direct result for the fact that the RBM is designed by an imperfect mechanism. TSOs and market participants will face risks that they are unable to fully manage due to lack of transparent information.

Improvement to liquidity will not bee seen until the implementation or improvement of short term trading (Day-ahead, intraday) markets and improvement in transparency in the market participant activities in the participating countries.

Monitoring processes conducted by Regulators will be required in order to prevent manipulations and to guarantee the necessary level of transparency in market participant‟s activities.

2.7 Congestion management and cross-border capacity allocation

The principles for Cross Border Congestion Management are described in the Regulation (EC) 1228/2003. This regulation, through the Energy Community treaty, is also applicable in the SEE countries.

One major task of the harmonization of SEE region is the establishment of a Coordinated Auction Office (CAO). In the future, the office should provide mainly auctions on different periodical bases and should organize a “secondary” market for physical transmission rights (has still to be developed). The according action plan has been launched and the first steps are already implemented. It is foreseen that the yearly Auction 2010 will be managed by the CAO (Ref: [1]). In December 2008 a Memorandum of Understanding (MoU) was signed in Tirana by all the relevant TSOs except for Bulgaria and Serbia of the original Contracting Parties. Bulgaria disagreed with respect to the geographical scope and Serbia‟s position was that the MoU should only be signed by TSOs in charge of capacity allocation, i.e. KOSTT should not be among the signatories. It was then also agreed that the future CAO

20 These conclusions are still valid after the inclusion of Ukraine and Moldova


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should be located in Montenegro. Ukraine and Moldova is not part of this as of the date of this study.

The CAO currently agreed to be established in Montenegro is an organization that will be set up and owned by all (or some of) the SEE TSOs. There is currently a working group established.21

The basis for the CAO is:

Established and owned by TSOs

Facilitate regional congestion management

and the goals as defined in their action plan are:

Better utilization of existing cross border capacities without jeopardizing system security

Higher degree of market harmonization due to coordinated capacity allocation to the SEE region

Simplicity in handling for market participants (“one-stop-shop” solution)

An important question for the design of the SEE Regional Power Market for the same region is how the CAO and the regional PX can co-exist. There are several good reasons for seeing this as two complementary initiatives that together can facilitate a better regional energy market for the SEE region:

The CAO organisation is a good platform for the cooperation in the region;

To have a coordinated approach to transmission capacity allocation is vital for a well-functioning DAM;

The goal of a higher degree of transparency and equal access as defined for the CAO is also an important basis for the SEE Regional Power Market;

It is a TSO task to define the available transmissions capacities for the market, and a coordinated effort is welcome;

To the Regional PX, the method of calculation is not important – as long as a portion of the transmission capacities is left for the DAM.

For more information of the integration of CAO and the SEE Regional Power Market, see chapter 1.7.

In July 2007 and revised by ECRB in January 2012, the SETSO TF conducted an analysis of the current situation of the applied procedures for the transmission capacity allocation.22 In the report it was concluded that significant improvement to the allocation procedures can be noticed. A few areas however fall still short of full compliance with the CM Guidelines. At present 50:50 capacity split is still used, the objective however is to introduce joint auctions. Not all the data relating to auction procedures and auction results, as well as commercial and physical flows are publicly available.

A Regional Congestion Management Benchmark (ref [6]) analysed the level of compliance of the SEE with the Regulation in respect of Cross Border Congestion Management and found

21 Please refer to http://www.energy-

community.org/portal/page/portal/ENC_HOME/AREAS_OF_WORK/ELECTRICITY/Regional_Market/CAO for more information.

22 Overview of transmission capacity allocation methods in SEE, Status June 2007, updates received in January 2012


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that, while the basic principles of the Regulation has already been implemented, currently all TSOs fall short of being in full compliance with Congestion Management Guidelines.

Figure 24. Cross border capacity allocation schemes

Source: Energy Community Secretariat, Presentation on Energy Community Treaty Implementation given at the 14

th Athens

Forum and updates received in January 2012

Most of the original participating parties introduced a market based allocation scheme, as shown in Figure 24. The exceptions are Bosnia and Herzegovina were a pro rata allocation scheme is still in use. On most borders the capacity is allocation of the capacity is split between the countries, but in a few cases joint allocation of the capacity is made (only between one contracting party and a non-contracting party/EU member).

Ukraine and Moldova does not have a market based allocation scheme for capacity either.

The pricing method (congestion fee) differs across the region, as shown in Figure 25. Naturally, on the Bosnia and Herzegovina borders there is no auction price since a pro rata allocation scheme is used. However, also on the Albanian part of the borders between Albania and Montenegro and Albania and Greece there is no auction price. The Albanian capacity is mostly used to support import to its tariff customers. The Montenegrin and FYR of


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Macedonian TSOs apply pay-as-bid23 for the capacities allocated. The remaining countries24 use clearing price25.

The differences in the allocation of capacity, as well as the differences in pricing methodologies constitute one obstacle to trading. In particular, non-market based allocation results in different possibilities for different market actors to access the interconnectors. But also the differences in pricing methodologies may constitute a barrier to trade.

Figure 25. Cross-border congestion fee pricing methods

Source: Energy Community Secretariat, Presentation on Energy Community Treaty Implementation given at the 14

th Athens

Forum and updates received in January 2012

The EC guidelines specify that the allocation at an interconnection line shall be coordinated and implemented using common allocation procedures by the involved TSOs. Although market based allocation schemes are common, the TSOs typically allocate their share of the interconnector capacity. None of the borders, with the exception of two in Croatia and FYR of Macedonia fulfil the Congestion Management Guidelines. Coordinated capacity auctions are performed only by a few participating parties.

23 Each bidder pays according to his own bid. 24 This includes also the lines between UNMIK and neighbouring countries where

allocation is done by the Serbian TSO. 25 Each bidder pays the same market clearing price


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In the South East Europe Market Monitoring project cross-border congestion is used as one indicator of overall market conditions. The quarterly report for March 2008 - June 2008 (Potomac Economics, November 2008) studies 20 interconnectors.26 Of these 20 interconnectors ten were categorised as “inactive”, meaning that there were little reservations of capacity made and small or no physical flow. The inactive lines were the ones that tend to be used for trade in the west-to-east direction. The remaining 10 were active, with both significant reservations and physical flows. Four of them had physical flows roughly equal what would be expected from transactions between the parties to the interconnector, while in the other six the physical flows exceeded what would have been caused only by the two counterparties, i.e. the flows would have been generated from other sources. For four interconnections the physical flow exceeded what would arise from regional AAC alone, which would have been caused either by unofficial transactions or unexpected loop flows. For these four interconnections the flows also exceeded the implied physical limit of the interconnection.

The quality of data and the provision of information have not yet reached satisfactory levels. Not one TSO can be identified for providing the level of information that is required by the Congestion Management Guidelines.

Despite the fact that all TSOs in the SEE region provide access to web pages in English, barriers for foreign traders and the development of an integrated electricity market do exist as not all necessary information is made available in English.

26 22 interconnectors should have been studied, but the necessary data was only

available for 20.


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Figure 26. Provision of information by TSOs

Source: ECRB, Regional Congestion Management Benchmark, 2008, and updates received in January 2012

The existence of Secondary Markets is a requirement according to Congestion Management Guidelines. Secondary Markets have yet to be implemented as only few Secondary Markets do currently exist. Some market rules in the SEE region do not allow for the formation of Secondary Markets yet.


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Figure 27. Availability of Secondary Markets

Source: ECRB, Regional Congestion Management Benchmark, 2008 and updates received in January 2012

Regulation (EC) No 1228/2003 describes three options for the use of congestion management revenues:

Guaranteeing the actual availability of the allocated capacity;

Network investments maintaining or increasing interconnection capacities;

As an income to be taken into account by regulatory authorities when approving the methodology for calculating network tariffs, and/or in assessing whether tariffs should be modified.

According to ECRB EWG Benchmarking Report for 20008 most of the countries in SEE already have provisions concerning the use of the revenues in their legislation, and even countries that do not have it in their legislation have implemented one of the three options.


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Table 10. Use of Congestion Management Revenues

Legal provisions Actual use

Albania <No information> <No information>

Bosnia and Herzegovina No provisions within its legislation

Mainly used as an income to be taken into account by regulatory authorities

Croatia Provisions included in legislation

Used according to all three options

FYR of Macedonia Provisions included in the legislation

Used according to all three options

Montenegro <No information> <No information>

Serbia Provisions included in the legislation

Used as an income to be taken into account by regulatory authorities

UNMIK Provisions included in the legislation

Income deducted by the Regulatory Authority from the Cost base. Legal framework also opens for the other two options.

Ukraine Provisions included in legislation

Used for network investments

Moldova Provisions will be included in legislation (drafting process started)

To be used as an income to be taken into account by regulatory authorities when approving tariffs

Source. ECRB, ECRB EWG Benchmarking report 2008

2.8 Inter-TSO Compensation mechanism (ITC)

A new voluntary agreement on Inter-TSO Compensation for transit for the years 2008 and 2009 was signed by 39 TSOs from 34 countries in October 2007 (ETSO, Report on Inter-TSO compensation mechanism, 2007). This agreement builds on the interim ITC Agreement from 2007 whereupon the SEE region was fully integrated into the ITC mechanism of the rest of Europe.

The following principles are to be followed for the ITC mechanism for the years 2008 -2009:

Allocation/compensation mechanism for infrastructure costs

Allocation/compensation mechanism of costs arising through cross border transit losses

Financing of the compensation fund and the treatment of ITC perimeter countries

Financial net results based on agreed principles for each ITC party


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3. EXPERIENCES FROM OTHER REGIONAL MARKETS

The selected markets in this section are based upon the EC treaty (Ref:[13]), in the current market development supported by EU as well as in the EuroPEX/ENTSO-E report of January 2009 (Ref:[12]).

The experiences are high level summaries to define some of the experiences from other market developments in Europe. This chapter is based upon reports from the local regulators and are expressing their view of their markets.

3.1 Selected Local and regional markets

In this chapter we will briefly review the relative success of selected Local markets. The main purpose of the review is to rank the degree of market success within each and one of a number of measurable parameters listed below.

The parameters will be ranked low, medium and high. The score low signifies that the market element is weak; medium signifies that the market element clearly is present but that there still is a way to go. High signifies that the market element is fully implemented.

The given scores are based on Local reports submitted by the regulators in each jurisdiction27. There is no unified template how to write these reports. Hence, the score given should only serve as an indication for the particular jurisdiction in question. In addition the scores given are based on a qualitative and not quantitative manner and could therefore be subject for discussion.

In the end of the chapter we will go through the various finalized and ongoing initiatives on establishment of regional electricity markets.

For the local markets the parameters that will be used are as follows:

Establishment of a reference price for electricity

A clear reference price for the commodity electricity is necessary for transparency in the market and for market efficiency. Score high is only given to well functioning markets where a high share of produced electricity is settled with the reference price as commodity price.

Supply quality and security

Reliable delivery of power is of uttermost importance in any economy. That quality requirements are specified and complied with is essential in order to minimize distortions to the operation of the electricity market. Score high is given to markets where both quality and security are meeting international standards for industrialized countries.

Wholesale market liquidity

In order to foster a competitive electricity market, energy suppliers, generators and large scale consumers need access to a competitive energy wholesale market with sufficient liquidity. Only markets where this is the case receive the score high.

27 All reports can be found on the ERGEG web site.

http://www.energyregulators.eu/portal/page/portal/EER_HOME/EER_PUBLICATIONS/LOCAL_REPORTS/Local%20reporting%202008


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Transparency

Market transparency is crucial to establish an efficient electricity market. All participants should have access to all relevant information regarding the electricity system‟s infrastructure and operational conditions. All relevant market information should be available for all market participants simultaneously. Electricity markets where this is the case will be given the score high.

Market Surveillance

In a competitive electricity market an independent and efficient market surveillance function should be present. Market surveillance is necessary to monitor the market to unveil abuse of market power or market manipulation. Only markets where this function is taken well care of and where appropriate actions can be taken to deal with abuse of market power or manipulation of the market will score high.

Metering and main grid settlement

The settlement of imbalances requires a well organized Imbalance Management and an appropriate meter value collection and processing system. The score high is given to electricity markets where imbalance settlement is executed by the TSO and based on AMR-systems and appropriate imbalance prices.

Profiling and handling of not hourly metered consumers

In order to enable competition between supply companies not-hourly metered consumption must be handled by the usage of profiles representing normal consumption during the day, night and time of the year. Electricity markets with established profiling and change-of-supplier procedures will receive the score high.

Wholesale market settlement

While settlement of energy trading takes place bilaterally or through organized markets the imbalance settlement for a period of wholesale market participation is handled by the TSO. The shorter settlement periods are and the more frequent the settlement takes place the lower uncertainty regarding past periods‟ financial obligations is. This also leads to lower collateral needs. The score high is given to markets with monthly or more frequent imbalance settlement.

Wholesale market access

The extent of competition in a liberalized market is dependent on the degree of access for various participant groups as large and small end-users and generators, suppliers and renewable energy producers. The score high will be given if all relevant participant groups have access to the wholesale market at the same conditions and terms.

Demand Side Management (DSM)

Demand side management (DSM) entails actions that influence the quantity or patterns of use of energy consumed by end users, such as actions targeting reduction of peak demand during periods when energy-supply systems are constrained. Peak demand management does not necessarily decrease total energy consumption but could be expected to reduce the need for investments in networks and/or power plants. An electricity market with strong incentives like contracts between TSO and large scale consumers and/or settlement of consumers based on hourly values using reference prices reflecting the marginal costs of generation will score high.


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Imbalance costs for wholesale market participants

The TSO is responsible for balancing the electricity system in real-time. An efficient Balancing Mechanism and a cost-reflective imbalance settlement system receives a high score.

Investment climate (investments signals, investment activity, investment focus, investment incentives, investment signals)

This parameter regards to what extent incentives and procedures to encourage maintenance, upgrading or construction of new production facilities or grid are in place. A system that encourages investments all over the electricity value chain will be given the score high.

Unbundling and regulation of grids and system operation (SO)

In liberalized electricity markets there will be various forms of unbundling of vertically integrated companies which own grid, supply role and generation capacity. Only electricity markets which have minimum an economical unbundling receive the score high. In line with EU legislation, physically unbundling for distribution companies with less than 100 000 customers is not required to get this score.

Change of supplier

To foster competition, change of supplier should be the result of a simple self-explaining administrative procedure and at no cost for consumers. Procedures applicable to involved suppliers and grids should be well developed and organized. Information of all available suppliers, with types of contracts and prices should be easily accessible to get the score high.

Regional integration/cooperation

The end user market is normally local, but the extent of regional integration and harmonization as price convergence, cross border capacity, exchange of balancing services and market coupling creates a more competitive wholesale market and contributes to security of supply. High cross border capacity is also important to reach the EU aim of establishment of regional markets. The score high is given to countries which are integrated or closely cooperate with neighbouring countries.


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Table 11. Selected markets and their success

Features: Romania Germany Austria Italy France Nether-lands

Ireland UK Sweden Norway

Establishment of a reference price

medium high high high medium high medium medium high high

Supply quality and security

high high high high high high medium high high high

Wholesale market liquidity

medium high high high low high high medium high high

Transparency low medium high medium medium high medium medium high high

Market surveillance

medium high medium high medium high high high high high

Metering and main grid settlement

medium medium medium medium medium medium high high high high

Profiling and handling of not hourly metered consumers

low high high medium low high medium high high high

Wholesale market settlement

medium medium medium medium medium medium medium high high high

Wholesale market access

medium high high medium medium high medium high high high

Participants exposure to

medium medium medium medium low high medium medium high high


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Features: Romania Germany Austria Italy France Nether-lands

Ireland UK Sweden Norway

spot market price

Demand side management

medium high high High medium high low medium high high

Imbalance cost for wholesale market participants

medium medium high medium medium high medium low (high prices)

high high

Investment climate

high medium high High medium medium high high medium medium

Investment incentive

medium high high High high medium high high medium medium

unbundling medium low medium High low medium medium high high high

Change of supplier

low medium medium medium low High medium high high high

Regional integration

high high medium High high High medium high high high

Note: All scores are based on reports to ERGEG submitted by the national regulators.


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Romania

Romania is the Eastern European jurisdiction that has been most successful in establishing a market. Romania has established a power exchange, OPCOM which is the largest PX in the Eastern European area. Romania has fulfilled the EU requirements regarding unbundling, an independent TSO, regulator and market operator. However, the establishment of a fully competitive physically market requires that the content in the parameters listed above get more sophisticated. The fact that around 50% of the consumers are still part of the regulated market also hampers the development of the market.

However, only 5.2 TWh was traded at the DAM at OPCOM in 2008. Although this makes OPCOM an Eastern European champion the share is too small to make a real significance in the big picture.

Germany

The German market is characterized by a generation structure where RWE and E.ON in particular create an oligopoly that supplies large industrial customers and municipal utilities. In this market competition is limited. Market information is voluntary and is not based on regulated procedures, which again explains the medium score at the transparency parameter. In the household end-user market competition exists but procedures and grid access are complicated and costly. This fact explains that less than 4% changed supplier in 2007.

On the positive side, the trading volume at the Energy Exchange (EEX), in both the physical and financial market is steadily increasing. In 2008 the traded volume at the spot market increased to 154 TWh compared to 123.7 TWh in 2007. Supply quality and security as well as regional integration are among the best in Europe. Also investment climate and incentives for renewable Energy is at top in Europe.

Austria

In Austria most of the features that characterize a competitive market are in place, however the volumes traded at the power exchange EXAA are still marginal and the households tend to stick to their local supplier, and hence limit the competitive aspect of the market, despite an effort by the regulator the last years to pave the way for an easy and transparent way to change supplier.

Also in the case of unbundling the current requirement of legal unbundling combined with lack of monitoring of integrated companies by the provincial governments in charge of this process, only give a medium score on this parameter.

Regional integration with Germany is high, and due to the importance of this market the score high is given despite lack of efficient integration with other neighbouring markets.


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Italy

In Italy the regulated spot electricity market is divided into: the day ahead market (MGP), where hourly electricity trades are carried out for the following day. The Intraday Market (MI), where variations of the volumes of electricity traded in the MGP are negotiated. After these markets there is the Dispatching Service Market (MSD) where TERNA procures the necessary resources for dispatching and ensures the security of the electricity system.

Since the establishment of the sport electricity market in year 2004, the electricity volumes managed within the sport market are larger than the volumes managed under bilateral contracts.

Liquidity in the spot electricity market has increased since its establishment occurred in year 2004 (from 29.1% up to 69% in 2008). This increase was due not only to a greater competitiveness but also to a larger number of transactions by the Institutional operators (Single Buyer, GSE). The number of operators also rose extensively from 73 in 2004 up to 151 in 2008.

Regarding security of supply the situation has improved very much in the recent years due to the commissioning of new generation power plants. The installed capacity has risen from 85,5 GW in year 2005 up to 98,6 GW in year 2008.

Service quality regulation for distribution started in year 2000 and was renewed in year 2004 and 2008. Service quality for transmission was established within the new regulatory framework for the period 2008-2011 and it is based on a penalty and incentive mechanism in order to improve the continuity and quality of supply.

For the regulatory period 2008-2011 an ad hoc regulation on quality for transmission is set within the Deliberation of the Regulatory Authority n. 341/07. A penalty and incentive mechanism for quality and security of supply has also been established under the Italian regulatory framework.

France

In the path towards a liberalized internal energy market in EU, France has traditionally been anything but a forerunner in the process. Only the minimum requirements of the various EU directives and regulations have been implemented in the local legislation.

Even though EDF‟s monopoly in the electricity sector has been broken, EDF still has a dominant position in all areas in the electricity value chain, including the ownership of the regulator CRE. This fact hampers the development of real competition in the French market.

Another obstacle to competition is that regulated retail tariffs are retained alongside market contracts through the “tariff transitoire d‟ajustement du marché” (TaRTAM). The introduction and prolongation of TaRTAM has according to the regulator closed the large business market as alternative suppliers to EDF hardly can match the regulated prices.

For small consumers like households there are little signs of competition one year after deregulation. This can be explained by low regulated prices, which means there is not much to gain by entering the free market. In addition only 1/3 of the consumers are aware that such an opportunity exists. There is also a fee attached to the change of supplier which hampers the competition.

For new investments in generation capacity TaRTAM could be an obstacle in the future. However, a new ambitious programme to double the share of renewable sources is adopted, and the production surplus is already high, so TaRTAM will not create a big problem in the years to come.


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The recent coupling of the French, Belgian and Dutch markets, and the coming extension to the German and Luxembourg markets in 2009, means that the regional integration is high.

The traded volume at the Powernext spot market was 44 TWh in 2007.

The Netherlands

The Netherlands has a highly developed electricity market and gets a high score on most parameters directly relevant for a competitive market. However, the volumes traded at the power exchange, APX, are still low, 21 TWh out of a total consumption on 112 TWh (2008), but is increasing year by year.

The weakest parameters in the Dutch market are investment climate and incentives, where it seems like that the Dutch focuses on import and regional integration to cover its normal deficit on around 20% of total consumption.

Only legal unbundling are required which explains the medium score on this parameter.

Ireland

The energy market in Ireland is a centrally dispatched or single price market. Compared to the other European markets, which clearly separate the TSO and market operator function, in a single price market the transmission and system operation costs are included in the price for the energy delivered or produced. The single price market is also typically constructed with focus on the generation side. The generators place bids for the plants they wish to operate. The bid with the highest price necessary to meet demand sets the pool price.

Organizing the market this way means that the competitive element clearly is present, but lack of a reference price, weak demand side, limited wholesale market etc. means that in most of the directly market based parameters it is hard to reach a higher score than medium.

In 2007 the Single Electricity Market (SEM) for Ireland and Northern Ireland was established. SEM consists of a gross pool market, into which all electricity generated or imported onto the island must be sold. This was an important step for greater competition in the electricity sector. In addition Spanish ENDESA has bought two power stations from the dominant Irish power producer and grid owner ESB, and thereby reducing the generation market share of the latter to 40%.

Ireland is in the process of launching a pilot smart meter project aiming at optimizing the Irish electricity market. This explains the high score in the metering parameter.

UK

The same characteristics regarding a single price market in Ireland is also valid for UK. However, the UK market is far more mature. Hence, the competitive aspect is higher. In addition there exists a spot market run by the Dutch market operator APX. However, this spot market only takes 1-2% of the totally traded volumes and plays little significance.

In addition, NASDAQ OMX and Nord Pool Spot have been chosen to establish a spot and financial market in UK, which also includes, intra day market, a physical forward market and a clearing function. The Spot market should be operative from Q2. 2009.


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Norway and Sweden

Together with Denmark and Finland, Norway and Sweden constitute the most competitive and liquid regional electricity market in the world. Maybe the single most important factor behind the success of the Nordic Market is that all aspects, from regulation to market operation in the electricity market chain in each of the four countries are fully market based. This is not the case in many other European markets that strive to combine the old regulated regime with a market regime. This fact is particularly important for Norway as Nord Pool is located in Norway, and hence a subject for Norwegian legislation and regulation.

However, looking at Norway and Sweden separately there are differences in the ways the markets are organized. In e.g. congestion management Norway uses market splitting which can result in 2-3 price areas for electricity within Norway in case of congestions. In Sweden countertrade is used to secure that all customers get the same price within Sweden. Currently work is ongoing that might result in the establishment of more price areas in Sweden

Also when it comes to market power there are generators like Vattenfall of Sweden and Statkraft of Norway that would have been too dominant if they had been operating within a strictly local market. However, in the integrated Nordic wholesale market these companies‟ market power is limited.

3.2 Review of Regional Markets

The establishment of regional markets normally is a step-by-step process where two or more countries decide to cooperate to integrate a few or more functions in order to make more efficient use of the cross-border capacity. Over time these functions can be deepened and expanded to include new areas until, in the end, there is a true regional market that at least complies with the following criteria.

Good conditions for power trading – this is crucial as this is the very motor and driving force behind the development of an integrated market. A well functioning regional market pre-requires that the physical and financial market work and that there is trust in the price formation. There should be reciprocity between the markets, a minimum degree of harmonization and smoothly functioning routines for joint planning and operation.

Balance mechanism and the settlement of imbalances – The rules governing the integrated regional market must be established also regarding to regional cooperation in the balancing mechanism. Settlement procedures should be harmonized and based on market prices.

Equal access to information – all participants in the market should have equal access to all relevant information, at the same time and at the same cost. This also includes information about transmission facilities.

Market based solutions for congestion management- this is crucial to achieve an efficient electricity market.

Investments in new transmission links – if socio-economically justifiable, and to ensure the dynamic development of the electricity regional market, the cross border capacity among the countries involved should be sufficient.

Until now only the Nordic electricity market Nord Pool can be said to be close to fully comply with the above mentioned requirements. However, the Iberian market (Spain and Portugal) and the TLC market (France, Belgium and the Netherlands) can be said to be regional markets.


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3.2.1 Present situation and initiatives

The Association of European Power exchanges (EuroPex) and European Transmission System Operators (ETSO) have recently launched a report: “Development and Implementation of a Coordinated Model for Regional and Inter-Regional Congestion Management”

In the report the status and future plans for established regional markets and market coupling projects are described. The report can be downloaded for free at: http://www.europex.org/default.asp?kaj=news&id=277

The Nordic electricity Market – Nord Pool

The Nordic electricity market Nord Pool became the first regional market in the world when Sweden, and later Finland and Denmark joined the originally Norwegian power exchange in the last half of the 1990ies. Nord Pool is Europe‟s largest market place for physical and financial power contracts. The Nord Pool market consist of a physical market which offers intra day trading and various types of contracts for DAM, a financial market providing forward and futures contracts and in-house clearing of contracts. Nord Pool also offers trade in European Emission Allowances EUAs and certified emission reductions (CER).

The success story of Nord Pool can be explained by many factors:

As already mentioned there was a political will in all the 4 countries to create a liberalized and regional competitive energy market, even if the scepticism within the electricity sector definitively was present.

The Energy mix used in the various Nordic countries is highly complementary. This was a driving force to integrate the markets.

A close cooperation between the involved TSOs and their commitment to facilitate the joint regional market was and is clearly the most important reason for the Nordic success.

A nearly common language, culture, historical background, political system etc. made integration much easier.

The long history of Nord Pool can to a large extent explain its relative success compared to other power exchanges. It takes time to establish a viable market.

http://www.europex.org/default.asp?kaj=news&id=277


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The TLC area and the continental European Power market

The so called TLC area consisting of France, Belgium and The Netherlands is the most recent example of an emerging multi nation regional market.

In 2006 implicit auctions replaced the previous system of explicit auctions. The result of this exercise has been convincing. The use of existing transmission capacity has been optimized by approximately 60% and the prices in these 3 countries have also been identical in around 60% of the time. (http://www.apxgroup.com/index.php?id=185).

Compared with the criteria above, The TLC countries have not gone into e.g. cross border intraday trading and common balancing arrangements. The main purpose of the TLC market is to harmonize the prices in the three countries involved by distributing electricity from low price to high price area and more efficient use of the daily interconnection capacity. However there are discussions regarding further development towards an integrated market. France and Belgium have since 2007 been making intraday exchanges using pro rata allocation. A similar project is in progress on the Dutch borders with Germany and Belgium.

The TLC market will to a large extent be enlarged in the near future in the flow based market coupling project with Germany which will contribute further to the EU aim of an internal European Energy market. France and Germany are also in the process of operating a common spot market (EPEX) which also includes Austria and Switzerland.

Market coupling between TLC-area, Germany and the Nordic Power market

Germany and Nord Pool have established European Market Coupling Company (EMCC) to run implicit auctions covering the two interconnections between Northern Germany and Denmark. The capacity is 373 MW and 379 MW at the two interconnections and can be seen as a pilot project for further integration between the Nord Pool area and Germany. The implicit auctions where launched in 2008 but closed down for further analysis due to non optimal results regarding the utilization of capacity between the market areas (http://www.marketcoupling.eu).

At the end of 2008 also the NorNed cable (700 MW) between the Netherlands and Norway was put into commercial operation. For the moment the cable capacity is sold through explicit auctioning, but the plan is to switch to implicit auctioning during 2009.

Market coupling projects in other parts of Europe

Also in other parts of Europe the trend is that various states are in a process to couple their electricity markets. Austria, Czech Republic, Germany, Hungary, Poland, Slovakia, Slovenia are for the time being in a process evaluating the potential for market coupling in the Central Eastern Europe region, and how to organize such a market coupling.

The liberalization process in these countries is not as mature as in the western European countries, which is also mirrored in the design of the electricity market coupling projects. For the time being it appears that explicit auctions are the chosen alternative in this part of Europe.

http://www.apxgroup.com/index.php?id=185

http://www.marketcoupling.eu/


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3.2.2 Lessons learned

In this section we will reflect upon some important issues that should be born in mind in order to create an efficient regional market.

As a starting point the essential and most important requirement is that there is a strong political will among the countries involved to create such a market. It is equally important that the cooperative environment within and between the states involved are good and that the politicians dare to take the necessary steps to create a regional market even though the resistance from some parties can be high.

Benefit of a regional market

By looking at Nord Pool and other regional and local liberalized markets in Europe it is fair to state that at least the following benefits have been achieved.

The use of the energy sources in the Nordic countries with hydro power in Norway, combined hydropower and thermal power in Sweden and Finland, and thermal and wind power in Denmark has been optimized.

Even though the proven balance in relative terms has been reduced compared to the increase in consumption the security of supply has been maintained. In dry years a hydro nation like Norway can be supplied with electricity from the other Nordic countries. In other words the need for reserve capacity at local level has been reduced without jeopardizing the security of supply.

However, the free market can also make it tempting for hydro producers to sell as much electricity as possible in times where the price is high, without keeping a sufficient reservoir reserve for dry years. This potential problem is in particular important to be aware of when the market concentration is high.

In all the Nordic countries there is a major market actor that would have had too much market power in a strictly local market. In the Nordic regional market there are enough actors to secure competition.

Due to the competition among producers, distributors and retailers the electricity price to end users has been kept at a low level given the generation reserves available.

In a liberalized market the price for electricity is a very rapid signal for the state of the market. This is a clear benefit, but at the same time it is a political challenge to stick to the market price mechanism in deficit situations.


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Organization and regulation of the market

Both in the establishment of local and regional markets a regulator with sufficient power to secure that issues as cross subsidization between monopoly functions (ownership of grid) and competitive functions (production and retailing) for vertically integrated companies are avoided. A strong regulator is also necessary to deal with the complicated issues regarding monopoly control as e.g. tariffication. At the same time the lesson learned is that the role of the regulator should be clearly defined. A regulator that inappropriate interferes in the daily tasks of the TSO or market operator is an obstacle for the optimal development of the market.

In a regional market the TSOs which, from a technically point of view, best know how to optimize the smooth functioning of the regional market should be a driving force and key actor in the integration process. If the TSOs are not sufficiently involved it is much harder to create a market.

It is a recurrent challenge in a regional market that the TSO move what is originally a local bottleneck to the border and thereby disturb the regional market. This is owing to the fact that the TSO in a pressed situation tends to put local interests in front of the common regional interest. In order to secure that the various TSOs involved are pulling in the same direction, also in pressed situation, their cooperation should be based on a written contract where issues like this are treated.

An issue that concerns the organization of the market as such is that investors should be assured that the market framework would remain stable for a long period of time. Stable market conditions are necessary for the investors to calculate rate of return for their investments under normal circumstances. A well developed financial forward market facilitates such stability. For the same reason it is important that all issues regarding the electricity market are transparent and easy accessible.

Organization of the Power Exchange

Experience shows that the market place itself will gain on competition from the bilateral market. This competition secures that the market operator constantly will try to improve the products offered to the market, improve the service, reduce the product prices etc.

In advanced markets the PX is counterpart in all contracts. This is a big advantage for the risk management of the actors trading at the PX as their payment are secured and their administrative burden eased. To provide this counterpart service a clearing house function must be established in-house or outsourced to a bank or a financial institution.

The establishment of a financial market has also proven to be a clear advantage for the well functioning of an electricity market and for the market participants. The traded volumes at the financial market are normally many times higher than the trade at the DAM and hence, important for the market liquidity.

As in all issues regarding a liberalized market, transparency and well established information services are important in order to create trust in the marketplace and the price formation.


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3.3 Conclusion

The last years we have seen a development of power exchanges all over Europe. So far the volumes traded at the PXs‟ spot markets are, with exception of Nord Pool, relatively small but the volumes are steadily increasing. In the eastern part of Europe the traded volumes at each PX are, with the exception of OPCOM in Romania, less than 3 TWh. This means that the PX's, for the time being, only play a marginal role in the Eastern European market.

So far it is in particular French/German EPEXSpot and Romanian OPCOM that stands out as potential regional champions in respectively the Western and Eastern part of Europe, while Nord Pool Spot is the dominant and sole operator in the Northern part of Europe.

All in all, the trend all over Europe, from south to north, from east to west is that former local markets link themselves together. In EU there is an aim that regional markets should be established as a sliding path or stepping stone towards a single European Electricity Market. Current market coupling initiatives indicate that in the future local markets will partly or fully be replaced by regional markets.

The recommended model for SEE is based upon experiences from these markets, and is very close to the current TLC arrangements.

This is also supported by the current CWE (Central-West Europe) market framework.

In October 2009, OMEL, EPEXSpot and Nord Pool Spot signed an LOI where they state their common interest for together enabling a cooperation based on a price market coupling between these three big power exchanges.

The Consultant‟s proposal is in-line with these initiatives and this would give the SEE region a good position when the integration within Europe is ready to take its next steps.


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SECTION III: ANALYSIS


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4. POSSIBLE CAUSES FOR HIGH PRICES IN THE REGION

Wholesale electricity prices in the region are seen as high. The lack of transparency in the pricing makes it difficult to assess the actual price level. According to the ToR for this project, prices go up to €100/MWh. It seems clear that the prices in the SEE region have been affected by the lack of transmission and generation capacity. Model analysis (Ref: [29]) suggest that competitive prices in the region in the year 2008 would be in the range of €90-€100, but that the prices would be reduced in the future when new capacity (in generation and transmission) is added. The modelled prices are broadly in line with new entry cost for CCGT.

However, more efficient utilization of the existing transmission capacities and a generally better functioning market is likely to contribute to improving the situation. The lack of well-functioning wholesale markets across the region is a contributing reason. Some of the requirements – frequently some or all of these are missing in SEE – for an efficient wholesale market are (Ref: [8]):

efficiently functioning and liquid spot market;

availability of an efficient balancing mechanism market;

support framework for market access;

good level of transparency;

well established roles/positions for all market players, including the TSO (as a provider of efficient balancing services), producers and suppliers (using market mechanisms to hedge risk), traders and brokers.

These criteria are generally not fulfilled, or at best partly fulfilled.

The data shown in section 2.2 shows that the capacity in the region should be sufficient to cover the demand. At the same time the lack of generation capacity in the SEE region is often highlighted as a significant reason for the high tariffs.

A significant proportion of the capacity is however in bad shape. Official plans call for rehabilitation of approximately 11.5 GW of existing capacity to extend their operating life and restore their efficiency and reliability (Ref: [10 ]).28 The age of installed base in Ukraine and Moldova also suggests that rehabilitation will be necessary. Currently 0.9 GW are under reconstruction in Ukraine.

IPA Energy + Water Economics (2009) 29 have calculated what they refer to as the generation as a percentage of the maximum that could have been produced using the equation (MWh produced)/(MW capacity* 8760), which is shown in Figure 28. They note that the countries that have a high level of generated units relative to capacity are those with more thermal generation. However, this might in many cases not be a very relevant comparison. Hydro systems are more often energy constrained rather than capacity constrained, while thermal systems typically are capacity constrained. More interesting, for countries with a high share of hydro there was a clear fall in this index in 2007, this was a dry year in the region.

28 Study does not include Ukraine and Moldova 29 Study does not include Ukraine and Moldvoa


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Figure 28. Generation as share of theoretical capacity

Source: IPA Energy + Water Economics, 2009

The regional load factor for 2008 per technology is displayed in Figure 29. The hydro plants in the region has an average load factor of just below 30%, while the conventional thermal plants (fossil fuels) has an average load factor just above 30%. Nuclear has an average load factor of over 70%.The hydro plants can be expected to produce close to the available energy, which is determined by the inflow of water. In 2008 this resulted in a generation of 57.4 TWh out of a total regional generation of 352.3 TWh.

The load factor of conventional thermal units, using available data, is quite low. This reflects that that reported capacities are substantially higher than actual available capacities. The load factors do also vary substantially between the different countries in the region.

The regional consumption (including network losses and consumption of pumped storage units) was in the same year about348 TWh, which would result in a net export of app. 2 TWh.


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Figure 29. Regional load factor per technology, 2008

Source: Own calculations based on data from ENTSO-E, Platts and OST, NERC, Ukrenergo, ANRE, Moldova and Transnistria statistics

In general there are however shortages and there are also large imbalances between different parts of the region as displayed in Figure 16 and Figure 22. A Generation Investment Study was prepared in 2004 and updated in 2006 (Final report January, 2006). 30 According to this study the SEE power system as one fully interconnected network would reduce the investment requirements and save approximately €3 billion (NPV) during the period 2005-2020. This also points at the importance of efficiently used interconnectors.

Within the Market Monitoring Project substantial price differences between the Romanian spot market prices and Austrian prices has been reported (Ref: [27]). 31 This indicates either a lack of physical transmission capacities or that the capacities are not fully used. They also report that on 7 paths (out of 21) the ATC was below 50 MW in at least one month studied, and in 13 paths it was below 100 MW. Their conclusion was that “the wide availability of ATC indicates that reserving capacity has not been a problem. However, more than one-half of the paths indicated ATC of 100 MW or less during the period.” It is unclear whether this actually has reduced trade.

In the Market Monitoring Project quarterly for March 2008 – June 2008 20 interconnectors were studied, out of which 10 were “inactive” (little or no reservations and small or no physical flows). These were mostly trade in the west-to-east direction. The other 10 had both significant reservations and physical flows. For four interconnections the flows exceeded the implied physical limits.

30 Study does not include Ukraine and Moldova. 31 Project did not include Ukraine and Moldova in 2008.

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A network modelling analysis32 (excluding Ukraine and Moldova) showed that in a base case hydrological scenario for the year 2010 most of the lines in the region are loaded less than 25% of their thermal limits. Only seven out of 49 400kV and 220 kV was in this analysis loaded more than 50% of their thermal ratings and only one more than 50%. However, other elements may be loaded more (e.g. transformers in sub-stations and some internal lines).

There is thus a mixed picture, but the lines used for trade in main trading direction (north-to -south) are used to a high degree and are in some cases very congested, which limits the possibility of trade and increase prices (in deficit regions). Figure 30 shows the “free” capacity on the different interconnectors. On some interconnectors the calculation results in a significant negative number, which indicates errors in data.33

Figure 30. Free capacity as % of max monthly capacity, 2008

Note: The graph shows the difference between the maximal monthly capacity (NTC*number of hours) and the actual total monthly flow on different interconnectors (in each direction) as a percentage of the maximum available monthly capacity.

Source: Own calculations based on ENTSO-E and Ukrenergo data

32 Generation Investment Study, Transmission network checking, draft report, March,

2005 33 A negative number implies that the flow in each hour (on average) is higher than the

NTC.

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Due to the often cumbersome procedures to get access to the networks, in many of the Contracting Parties most of the cross border trade is currently carried out by traders acting as intermediaries between importing and exporting countries (Ref: [10]). As previously mentioned different principles for allocating capacities are also currently used in the region. Significant capacities are directly allocated to supply domestic customers in several countries, one jurisdiction uses pro-rata allocation and the other use different pricing methods for transmission capacities (pay-as-bid and market clearing price). These difficulties are likely to lead to inefficient utilisation of the capacities, which would also contribute to higher prices. At an interview with ELEM (FYR of Macedonia) it was mentioned that 30% or more of the (import) price is due to capacity payments for interconnectors.34

The efficient use of interconnectors is e.g. demonstrated by the introduction of the market coupling between France, Belgium and the Netherlands (Tri-Lateral Coupling – TLC). Figure 31 and Figure 32 show the price difference between France and Netherlands 1 month before and after the introduction of the market coupling. Figure 31 shows the daily average price difference, while Figure 32 shows the average hourly price difference. Both of these show a clear decrease in the price differences, and in particular a clear decrease in the price difference during peaks. In particular Figure 32 shows that the price difference in the afternoon/evening peak was reduced dramatically following the introduction of the market coupling. This may be a reflection of reduced possibilities for exercising market power following the market coupling.35

Figure 31 . Price difference between France and Netherlands 1 month before and 1 month after introduction of market coupling

34 Interview with ELEM, December 2008 35 No detailed analysis has been made and we have no evidence that market power was

actually exercised.

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Figure 32. Average hourly price difference between France and Netherlands 1 month before and 1 month after the introduction of market coupling

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5. RISKS AND OPPORTUNITIES FOR NON-HOUSEHOLD CUSTOMERS

The risks and opportunities for non-household customers are likely to differ across the region. Given that the main trading pattern currently is from the north to the south competitive prices are likely to increase to the south in the region, but the degree of such price differences would depend on the congestions in the region. Some parts of the region also suffer from shortages and load shedding, while other parts have a surplus. Furthermore, the current situation in terms of tariff differs. Montenegro for instance has substantially higher tariffs than other countries in the region.

5.1 Key risks

The main risks for the customers are related to prices.

Risk of increased prices

There is a risk of price increases when moving from regulated tariffs. It is reasonable to believe that competitive electricity prices in the region at least in the short run will be higher than the currently regulated prices. This is only partially related to the creation of a regional market, but more from the gradual phase-out of (implicitly) subsidised electricity prices. To meet increasing demand and to replace old generation plants new investments are needed ant the current price level can not support new generation investments. The electricity prices therefore need to be increased with or without a market solution.

Assuming that prices will become more and more market based over time, customers in the southern part of the region, currently being the most dependent on imports, are likely to have more to benefit from improved regional trade, compared to customers in export areas.

Risk of unfair competition

There is also a risk of even more pronounced price increases for eligible customers if substantial parts of the market are kept on low regulated tariffs. If only part of the market is being opened for competition while substantial part is kept on regulated tariffs for a prolonged period of time it is likely that the prices for the customers on the open market increase even more. If a substantial part of the demand is kept on relatively low regulated tariffs these are less likely to respond and adapt their behaviour reducing the overall low level of efficiency in the region.

Risk of market power

Each local market is currently very concentrated and a reasonable level of competition is dependent on a successful regional integration. With a successful regional integration, coupled with effective surveillance from market operators and competition authorities, a reasonable level of competition could arise.

It is however not unlikely to expect that over time some consolidation in the market structure would occur. Given that the main generators are currently state owned this is however a decision that remains within the domain of the local governments.


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Volatile prices

Experiences from other competitive electricity markets show that the price volatility may be high. This can be expected also to occur in a competitive market in this region. Market participants need to apply methods to manage this short run price volatility, including financial contracts as well as demand side response.

Risk of limited real market access

With explicit auctioning market participants need to gain access to transmission capacity in order to trade regionally. Some experiences so far in the region indicate that there might be a problem related to the availability of transmission capacity. In some of the interviews in this project is has been suggested that there are cases where traders seem to have been using their reserved capacity in a way that has blocked trade.

Even with more efficient allocation, experience shows that the utilization of the transmission capacity is less efficient with explicit auctioning. This may lead to more frequent bottlenecks and increase in prices.

The financial markets are not yet developed, which limits the possibilities for market participants to hedge price risks. Particularly in a transition phase – until such markets have developed – this may create difficulties.

If a day-ahead-market is unable to attract sufficient liquidity the possibilities for market participants to trade will be limited.

Summary

A key risk for non-household customers is that electricity prices may increase in an open market. This risk is particularly enhanced if only a few customers are faced with market prices, while most remain on (low) regulated tariffs. Securing an efficient working market and a high degree of competition is important to counter-act this.

5.2 Opportunities

A well functioning wholesale market in SEE will bring many opportunities to the participants.

Higher electricity prices will increase new investments and security of supply

When price levels are below the cost of new investments, it will not be possible to get new commercially driven investments, which may worsen the supply-demand balance. Increased security of supply will require both a more efficient use of the existing system, but also new investments. The necessary investments can in practice only be achieved if investors receive the required income. Particularly in the parts of the region where load-shedding is common practice, customers are likely to benefit from increased security of supply over time.


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Real competition – Access to a large base of suppliers

With the current market structure the (non-household) customers are essentially dependent on the local supplier. This is further enhanced by the fact that the local (low cost) generation is in many cases reserved for the local tariff customers. Market opening will create opportunities for non-household customers to get access to a larger base of suppliers. Currently non-household customers can formally become eligible in (almost all) countries in the region,36 and in a few it is mandatory for customers above the defined threshold. The latter implies that those customers to not have access to a regulated tariff.

Access to new service offerings

As has been the case in more developed electricity markets this has led to a broader range of services offered, providing the customers with new and better possibilities for contractual arrangement, hedging etc. The market for hedging will develop when there is a trustworthy spot price that can serve as basis for financial hedging contracts.

Possibility for demand side participation

Demand side bidding/participation may enable (non-household) customers to reduce the cost of electricity by adapting the consumption to the actual prices. The surplus capacity could be sold back to the market.

Investments in own generation

In an open market the customers may also invest in generation and thus hedge for price variations and sell surplus to the market.

Better utilisation of generation and transmission capacities

In a well functioning wholesale market the utilisation of generation and transmission capacities will be optimised and thus minimise cost for the buyer of electricity on the market. Also a generator will benefit from the fact that his units will only run when it is economically beneficial for the owner of the unit.

36 A few jurisdictions define the eligibility threshold on connection level, which means that

all non-household customers cannot become eligible in those jurisdictions.


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6. BARRIERS TO MARKET OPENING

6.1 Prerequisites for market opening and current status

In general most jurisdictions have fulfilled the minimum requirements for unbundling as defined by the EU legislation, but this is not enough to create a wholesale electricity market in the SEE. The EU 3rd package for the electricity and gas market includes increased requirements for unbundling. The 3rd package is expected to be formally adopted by the Energy Community in the near future.

The degree of competition in the market is generally low in the SEE region with in most cases one dominant generator in each jurisdiction. Furthermore, it is common practice that this generator is obliged to first-hand supply to the domestic tariff customers. This limits the possibilities for trade and reduces or eliminates the incentives for eligible customers to exercise their eligibility. In some countries no regulated tariff is offered to eligible customers, which in effect means that those customers are the only one facing the marginal cost of generation in the region.

As stated above (see section 2.4 and 0) there are some clear problems related both to the regulated tariffs and to the market structure. Supply and distribution has not been unbundled in all of the jurisdictions in the region, which creates an unequal playing field for the incumbent supplier and a new entrant. There is a high risk that new entrants fear that it will not be treated in a fair and equal manner by the distribution company as it is competing with its supply businesses. However, this is probably currently overshadowed by the fact that the regulated tariffs mostly are at levels which makes it very difficult for new entrants to profitable enter the end-user market. Even though both of these problems primarily relates to the retail market and not the wholesale market, it puts limitations on the business models that a new entrant also on the wholesale level can apply. A new generator will then have difficulties in securing its own end customer base, but has to rely on selling to the incumbents.

On the wholesale level there is no clear wholesale reference price established. This reduces the possibility for efficient trade between parties, and is also likely to lead to less efficient use of the system.

Local generators in most SEE countries are obliged by law to continue to supply tariff (captive) customers, as per the local energy legislation for Public Service Obligation (PSO). Thus, they are allowed to request capacity from the TSOs for so-called Already Allocated Capacity (AAC) for import purposes (Ref: [2]). In effect, part of the cross-border capacity is reserved for fulfilling this PSO and restricts the availability of transmission capacities to new entrants.

One of the main market imperfections is the lack of clear incentives to SEE TSOs to support cross-border trade and invest more in integrating the regional markets. In this respect an operational framework of Co-ordinated Flow-Based Explicit Auctions (CAO) is being implemented for allocating interconnection capacity in the region.

This initiative has led to a dry-run simulation through 2006, with continuing work and simulations in 2007, potentially increasing the appetite of traders to participate as well. One important issue is the distribution and use of revenues from the CAO and the ensuring effect on TSOs‟ participation in this framework, the actual capacity that they provide to the market and the corresponding benefits for the regional cross-border trade and planned further market integration of the regional electricity systems (Ref: [2]).


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However, some of the incentives that may benefit TSOs in the area can cause higher customer bills and lead to a market distortion. The OPEX and CAPEX spending on the jurisdiction‟s grid are covered by regulated tariffs and the inter-TSO compensation mechanism. The CAO-generated revenues is thus an extra income for the grid operators(Ref: [2]), unless it is either used for investments or for reducing the tariff according to the established guidelines.

In regions with liquid and efficient markets, the use of congestion revenues – through either investment to reduce congestion or to provide firm availability of capacity or lower tariffs – should lead to an improvement in welfare. Until the SEE markets are developed to this level, it is important to prevent scenarios where TSOs are obtaining certain incentives to “retain” congestion on their borders, especially given the fact that the framework for allocation of transmission capacity is not completely market based yet.

During the 14th Athens Forum the Energy Community Secretariat gave a presentation regarding the situation as of December 2008. The figure below is taken from that presentation. As shown by this figure some legal provisions are missing in most of the central areas for wholesale market opening in more or less all the countries. For three of the key issues the situation is reported as being the following:

Market opening (in the figure below) refers to the opening of the market for final customers. The summary above shows that only Croatia is fulfilling the requirements of Directive 2003/54/EC in this respect. Several, such as FYR of Macedonia, Montenegro and UNMIK have significant bottlenecks in this area, while the remaining contracting parties only have some provisions available.

Also related to cross-border trade, none of the contracting parties fulfil all the requirements. Croatia and Serbia are reported as only missing some provisions.

Congestion management is more advanced, although none of the contracting parties fulfil all of the provisions.

Figure 33. State of play, December 2008

Source. Energy Community Secretariat, presentation given at the 14

th Athens Forum, this is not updated with Ukraine and

Moldova, the current status is found in the ECRB Annual report for 2011,

Bottlenecks Some provisions are available Some provisions are missing All provisions are available

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Independent of the market model eventually chosen some prerequisites have to be fulfilled, possibly to a varying degree dependent on market model. Some important prerequisites will be:

Wholesale reference price, transparency and liquidity

Secondary markets for energy and cross-border capacities

Competition in generation

Price penetration

Effective market opening

Independent regulators

Effective TSO unbundling

Effective DSO unbundling

Demand side participation/management

Imbalance cost/balance responsibility

Market based allocation of cross-border capacities

Wholesale reference price, transparency and liquidity

Price reference is a basic prerequisite for power trade, power plant operation, consumer behaviour and investment decisions. A minimum degree of liquidity is required to establish confidence in the reference price and to reduce volatility. Most bilateral markets show sufficient liquidity in long term products. For the SEE region the challenge is to create liquidity in short term products.

Energy reference prices can be developed in different ways, but typically organized market places with sufficient liquidity is important for a reliable reference price to be established.

With market models based on implicit auction (of cross-border capacities) the cross-border flows will be determined by the prices established on organized market places. This is not the case with market models based on explicit auctions. For such market models reference prices are however required in order to secure the correct flows since the bids for cross-border allocation will be based on these prices.

Currently there are no liquid market places in the region and no generally known and accepted reference price for electricity. However, there are active traders functioning as mediators and these can be expected to have a reasonable good knowledge about the relevant reference price.

Secondary markets for energy and cross-border capacities

Related to the establishment of trustworthy reference prices is the availability of liquid secondary markets. This is also important to ensure efficient use of the system.

Currently there are no secondary markets for energy. According to the ECRB EWG Benchmarking report (version 30 April, 2008) only Serbia and UNMIK offers the possibility for secondary markets for capacities (and UNMIK does currently not control the cross-border capacities). Market rules may in some cases also have to be changed in order to implement secondary markets for energy as well as cross-border capacities.


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Competition in generation

Any well-functioning market requires a sufficient degree of competition in order to avoid market power. With local energy markets this sufficient degree of competition would have to be upheld in each (small) local market. For most, or possibly all, of the markets in the SEE region it is unlikely that a sufficient number of generators can be established. Regional integration to some degree dilutes market power, and thus reduces the requirements on each local market.

With the exception of Ukraine, Moldova and Bosnia and Herzegovina, all the local markets for the Contracting Parties are dominated by one generator37. There are in several countries additional market participants/generators, but from a competition point of view the effect of these can be expected to be very limited.

A well-integrated regional market could be expected to function reasonable well given the number of generators that would be present. This of course requires that the markets can be sufficiently integrated and that there is both sufficient interconnector capacities and that these capacities are utilized in an efficient way. There are currently many active traders that can provide some competition in the cross-border trade.

Price penetration

In an efficient power market final consumers and generators react to market prices. Market design aims at exposing a steadily increasing number of market participants to short and long term marginal prices. “Full supply contracts”38 and regulated prices are not compatible with price penetration.

Currently the price penetration to end-users is limited in the region. The countries typically have regulatory regimes in place that are supposed to be cost-reflective. The level of the regulated tariffs varies widely within the region. The tariffs are however typically not sufficient to cover the cost of new investments. The payment discipline is also in many cases low.

Most of the customers in the region are not exposed to market prices. In some countries (Ukraine, Moldova, Croatia, FYROM and Montenegro) eligible customers are exposed to market prices.

Effective market opening

In order for a competitive wholesale market to emerge it is necessary that there are customers available to supply.

Currently the customers are in most cases “locked” into their current supplier, either through not being eligible to switch or not having any incentives to switch supplier. In all cases the effective market opening is low and, with the exception of Croatia, FYROM and Montenegro the de facto market opening is zero or close to zero with (almost) no customers exercising their eligibility.

37 In Serbia there are 5 generation companies that are legally unbundled, but within the

EPS group as daughter companies 38 With full supply contracts we refer to a type of contract where the customer can off-

take as much electricity as it wants and the customer has no cost for imbalances (the customer has no reference consumption). This is sometimes also referred to as “all in” contracts.


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Independent regulators

Independent regulators equipped with the sufficient regulatory capacities are important in any market setting. A more complex market design is however likely to put higher demand on the regulator. In particular, regional integration may require cross-border regulatory interventions.

All the countries in the region have formally independent regulators, although the capacities of the regulators vary.

Effective TSO unbundling

All of the foreseen market models require neutrality of the system and market operator.

Most of the countries have established independent TSOs. The exceptions are Bosnia and Herzegovina where an independent ISO is established, Croatia where an independent market operator is established but the TSO is within the HEP Group and Montenegro where this process has only begun.

Effective DSO unbundling

DSO unbundling most directly affects the retail level and is thus not an absolute requirement. A well functioning retail market however supports and enhances the functionality of the wholesale market. Demand side participation in energy markets can be prevented by discriminatory behaviour from a non-unbundled DSO. Many markets around the world work reasonable well without a complete (e.g. ownership) vertical separation. It is however important to make a proper ring-fencing of the DSO activities.

In FYROM distribution and supply has already been separated from generation and privatized. Distribution and supply are however not separated. Several others are either in the process of separating the distribution and supply activities or have already legally separated these activities. In no case there is an effective separation between DSO and supply activities.

Demand side participation/management

Participation in energy markets from the demand side generally improves the functionality of the wholesale market. However, many energy markets are relatively well-functioning without an active demand side. Demand side management is however likely to be important e.g. in order to reduce load shedding and increase energy efficiency.

In the few countries were some customers are more directly exposed to market prices, the demand side can be expected to be more responsive to market conditions.

Imbalance cost/balance responsibility

Competitive energy markets require that the responsibility for upholding balance is allocated to the TSOs. However, each market participant is required to trade into balance.

Currently Bosnia and Herzegovina and Croatia have established systems for balance responsibility.

Market based allocation of cross-border capacities

Independent of market model chosen the cross-border capacities should be allocated using market based methods (implicit or explicit auctioning). Currently the allocation is basically based on explicit auctioning in all countries except Bosnia and Herzegovina (UNMIK does


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not control the capacities in/out of the area). It is however common that some capacities are reserved for the supply to tariff customers. The allocation is furthermore mostly done on a long-term basis and the availability of secondary markets is limited.

The pricing is also based on different methods, with some countries using pay-as-bid.

Summary assessment of the current situation

On some points the development has proceed relatively far:

All countries have established independent regulators, although they may in some cases need to be strengthened. Looking at the regional perspectives the difficult challenge of regional cooperation between regulators probably has to be further developed, as is typically also the case in the rest of Europe.

All countries, except Montenegro, have also advanced relatively far in terms of TSO unbundling.

Market-based allocation of cross-border capacities, through explicit auctioning, is also the dominant method.

On other issues far less progress have been made:

There are generally no publically available and generally trusted reference prices for energy.

Although the possibility for secondary trading for cross-border capacities exist in a few cases these are not liquid and well-functioning markets.

Long-term trade in electricity may function reasonable well, but no organized market places for trade in electricity currently exist.

According to the Consultant‟s understanding balance responsibility has only been developed in a few cases. In most of the region the dominant generators are in practice responsible for upholding the balance and provide ancillary services to the system operator.

Although formal market opening (end user eligibility) is reasonable well progressed, the actual market opening is in most cases non-existent or very limited.

Customers currently face market prices only to a very limited extent. This is particularly the case regarding more short-term price signals.

Effective unbundling of DSOs has not progressed very far. Although in several cases the distribution and supply have, in various ways, been separated from generation, distribution and supply have not been separated from each other. This may be of less urgency in terms of creating a regional wholesale market, but is of importance to secure that customers get access to the electricity market.


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6.2 Barriers to market opening

There are several potential barriers to advancing market opening and liberalisation. First of all, the prerequisites for regional market opening discussed above are generally only fulfilled to a limited degree.

Unbundling

While TSO unbundling generally has proceeded well in the region, effective unbundling of DSOs has not progressed very far as mentioned above. In addition to the TSO and DSO unbundling, it is also important to consider the relationship between the incumbent generators and the incumbent suppliers.

In many cases there is either not unbundling between the incumbent generator and the incumbent supplier (usually with a responsibility as public supplier). The public supplier often buys all or most of its volumes from the incumbent generator. If this close relationship is continued there is a risk of insufficient liquidity in an open market.

Regulated rates too low: incentives for investments and eligibility

It is important to recognize that this is a poor region and that a relative high degree of the population suffers from energy poverty. Based on consumer protection concerns it is common to want to keep the cheap generation for the home market and offer this to the consumers at low regulated rates. Although the regulated rates may cover the cost of the existing system, those price levels are insufficient to cover the cost of new investments on a commercial basis and generally below the prices on the open market. The perceived risk of price increases can thus be considered to constitute an important barrier. Related to this is also the concern that increases in the prices will have a negative impact on the industrial development and the competitiveness of the local industries in the region.

This situation is however different in different countries. Montenegro for instance has substantially higher tariffs than other countries in the region. It is possible that the customers in Montenegro can gain from regional market integration. On the other hand, in most countries the regulated tariffs are lower than what can be expected in the open market at least in the short run.

It should be noted that if price levels are below the cost of new investments, it will not be possible to get new commercially driven investments, which will worsen the supply-demand balance.

With the current price regulation the interest of the eligible consumers to exercise their eligibility is limited or non-existing. In a few countries the eligible consumers are forced out on the open market. In order to create a well-functioning market opening it is necessary to gradually increase the number of customers on the open market. This can either be done by eliminating the option of regulated tariff for eligible customers, or by changes in the tariff regulation.

Balance responsibility

As already mentioned above, balance responsibility has only been developed in a few cases, while being under development in other cases. In most of the region the dominant generators are in practice still responsible for upholding the balance and provide ancillary services to the system operator.


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Market concentration: Local markets too small

The local markets in the region are small. Unless a regional solution can be achieved there is a risk for a fragmented market structure with negative consequences.

With local markets each market need competition in generation. Currently each market is dominated by one dominant generator,39 with the exception of Bosnia and Herzegovina with 3 dominant generators. It will be difficult to establish competition in all areas in the SEE. It would require splitting the current dominant players. Most of these players, “Local champions”, are not large in a regional context and could even expand in a SEE Regional Power Market.

Reduced costs and increased security of supply can be expected from a regional market both in the short- and long run. The power systems in the region differ widely between countries in terms of the generation mix. Typically it is very beneficial to integrate hydro and thermal systems in order to exploit the different characteristics and the storage possibilities in the hydro system. This will reduce generation costs. The hydro dominated systems typically need to import during droughts and are thus dependent on a regional solution. The more thermal dominated systems can on the other hand benefit from lower generation costs when there is excess water.

In the long run the investment incentives are likely to improve. By interconnecting a larger system a more stable price can be expected, which reduces the risk for the investors. Furthermore, the current locked in markets limits the possibility of commercial profitable investments. It is difficult for other market players than the regulated utilities that can transfer new capacity into its rate base or IPPs with a supply agreement to a regulated utility to make profitable investments.

Transparency

For a well functioning market transparency is of the outmost importance. Wholesale market information is currently in most cases not available and sufficiently transparent. A barrier to achieving a well functioning wholesale regional wholesale market is thus the currently low degree of transparency.

Limited experience of electricity market operation

There is also relative little experience and knowledge about market operations in the electricity sector in the region. There is currently:

No Power Exchange

No regional wholesale reference price

Limited secondary market for electricity cross-border capacities

Limited experience of Balance Responsibility

Limited/short experience in unbundled TSO

Some experience of independent regulator

Market participants need to understand and adapt to the concept of a competitive electricity market. This will require gradual capacity building, and a gradual evolvement of the market.

39 In Serbia there are 5 generation companies that are legally unbundled, but within the

EPS group as daughter companies


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Mutual recognition and trust in parties

On a broad political level there are important political barriers related to the mutual recognition of parties. This is typically issues that goes beyond the electricity market, but have an impact on the possibilities of progress. Energy market integration is to a high degree dependent on trust, since energy security is vital to any nation. In comparison, the well advanced regional integration in the Nordic countries was based on a long history of cooperation between the countries, which provided a solid foundation.

The political barriers, both related to concerns for price increases and the mutual recognition of parties and trust between nations is probably the most difficult to overcome.

6.3 Ways to overcome barriers to market opening

The following bullet list concludes the recommendation to overcome current barriers:

Increasing the degree of market price penetration to end use customers

Increasing the incentives for final customers to exercise their eligibility

Establishing reliable wholesale reference prices

Establish a regional SEE wholesale market

Establishing systems for balance responsibility

Improvements in the utilization and allocation of cross-border capacities

Establishing a secondary market for cross-border capacities

Education and training for market participant

A political will to establish a SEE wholesale market

Market price penetration to end use customers

End use customers need to be able to react on actual marginal price levels. This will give the right incentives for demand side participation and energy efficiency measures at end use customers. Therefore the end use customers need to purchase electricity in a way that they are exposed to the marginal prices (hourly). The current used “full supply contracts” and regulated prices need to be abolished.

Incentives for final customers to exercise their eligibility

With regulated prices lower than market prices no eligible customer will exercise their eligibility. This can be solved either by increasing regulated prices to a higher level than the market prices or by not giving the eligible customers the alternative of regulated prices.

Reliable wholesale reference prices

A reliable wholesale reference price is extremely important, as this price is the basis for all kind of price hedging products, both physical (bilateral contracts) and financial.

The future wholesale reference price is a key parameter for investors of generation capacity, and end use consumption, when taking investment decisions. If there is no reliable reference price and/or the reference price is difficult to predict the risk in investments will increase.

A regional SEE wholesale market

Considering the current market situation in SEE with one large incumbent generator in almost every jurisdiction it is not feasible to establish separate wholesale markets in every


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jurisdiction. This would imply splitting up each local incumbent into many generators. In a regional context most of the incumbent generators are not dominant and in a European context the incumbent generators are small.

When the Swedish wholesale electricity market was opened Vattenfall had a market share in generation of 50% on the Swedish national market and was considered to dominant. By forming a joint market with Norway the market share became acceptable.

With a well-integrated SEE market the competition is expected to work reasonable well, but it will require close surveillance from market operators and competition authorities.

Systems for balance responsibility

A prerequisite for new generators and end use customers to participate on the wholesale market is to have a system for balance responsibility in each jurisdiction. This means that all generation and eligible end use customers are exposed to the concept of hourly electricity balances. For each hour the balance responsible party balances forecasted demand plus sold electricity with planned generation and bought electricity (planning phase). Both bilateral trade and electricity sold on the DAM are included. Afterwards (settlement phase) the actual demand and generation is controlled in the balance settlement. There should be some sort of “punishment” for the difference between planned and settled result. This will give the balance responsible parties incentives to trade themselves in balance at the DAM.

Utilization and allocation of cross-border capacities

The allocation of cross-border capacities also needs improvements in some cases. With the ongoing work on coordinated auctioning, important improvements can be expected.

A secondary market for cross-border capacities

Establishing a secondary market for cross-border capacities (with an explicit auctioning model) and securing sufficient liquidity in these markets is important.

Education and training for market participant

The current and future wholesale participants need to be educated and trained in the functioning of the new market and the roles and responsibilities of each market participant.

Political will to establish a SEE wholesale market

At least, but probably most important, a political will to establish a SEE wholesale market is vital for the success of the mission. Without a political commitment in each of the jurisdictions no well functioning market will be achieved.


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7. KEY PERFORMANCE INDICATORS

The progress of the SEE wholesale market opening needs to be monitored. Key Performance Indicators (KPI) is a tool in the monitoring. The KPIs will show the pace of progress and make it possible to take measures, if the process is haltering.

The KPIs are suggested to be prepared by ECRB and the national regulators. They will also be used by local ministries, the World Bank, TSOs, investors and others with an interest in the development of the wholesale market in SEE.

It is also suggested that the KPIs are used on a regular basis, for examples quarterly and annually. The KPIs need to be published in some sort of monitoring report and made accessible for all interested parties, for example through the web page of ECRB.

From a qualitative perspective one can distinguish between two types of indicators. The first one measures whether the necessary instruments are in place that can support the desired development. The second type of indicators measures how well these instruments functions. We propose a number of KPIs that should measure both of these aspects.

We have defined 50 KPIs to monitor the progress of the SEE wholesale market opening. The KPIs have been grouped in the following areas:

Number of KPIs

Prices, transparency and surveillance 8

Access to markets 6

Access to customers 6

Market structure and competition 14

Balance responsibility and balancing market 5

Allocation of cross-border capacities 6

Network tariffs and grid access 2

Independent regulators and harmonisation of regulation 3

Some of the KPIs are the same as in the Report on Progress in Creating the Internal Gas and Electricity Market (Ref: [19]). These KPIs probably needs to be monitored as a requirement from the EU and it will thus not be any extra work for ECRB and the regulators.

The monitoring, as proposed in this report, needs to be coordinated with the ECRB Marketing monitoring work stream by USAID/Potomac Economics. This project has so far mainly concentrated on the allocation of cross-border capacities.

Most of the KPIs have been defined in the scale of 0 – 100%, where 100% indicates that the goal for the KPI is fully achieved. Some KPIs have other scales, examples of this is HHI and C3. There are also some indicators that can not be fit into the 0 – 100% scale, examples of this is “Price correlation between price areas” and “Number of balance responsible parties”.


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7.1 Prices, transparency and surveillance

Trustworthy market prices that reflect the underlying costs are key to a well functioning market.

From a market design perspective it is important that prices reflect the relevant cost of generation, i.e., that prices generally reflect the short run marginal cost, and that these wholesale prices are passed through and reflected in end-user prices. It is not possible to link the success of a market design to a particular price development or price level since that is dependent on the cost structure, need for investments etc. Prices may thus both increase and decrease without any of that necessarily being a sign of a good or bad market design.

From a market design perspective it is more important to measure whether the prices are competitive both on the wholesale market and in the retail market. Two KPIs are proposed to capture this.

For the wholesale market the price mark-up above the short-run marginal cost (SRMC) is a key indicator (Lerner index40). The SRMC could possibly be calculated based on the last thermal unit used in the jurisdiction (standardized costs based on fuel prices and the efficiency of the plant). However, the drawback of using the last unit actually used is that if infra-marginal units are held back from generating the wholesale market prices could equal SRMC (zero mark-up) in spite of market power being exercised. Thus, it is preferable to calculate the SRMC based on an assumed availability of the power plants.

If the jurisdiction is importing the SRMC for the jurisdiction would equal the SRMC for the most expensive import (i.e. the SRMC in the most expensive export jurisdiction).

Furthermore, it is important that trustworthy price references are established. It is proposed that this is measured in the short run through the correlation between the wholesale prices and the end-user prices. In the long-run a trustworthy forward price reference should have implications for new construction of power plants - if the forward prices are above the LRMC of the most competitive plants investments should be triggered.

Transparent prices are also important for market participants. We propose to measure price transparency through the existence of daily published prices. Trustworthy prices also depend on a well-functioning, neutral and non-discriminatory price setting process. Market surveillance is important to secure this.

40 The Lerner index is calculated as mark-up on SRMC (wholesale price-SRMC) divided

by the SRMC.


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Table 12. Key Performance Indicators - Prices

Indicator Measure/scale Comment

Wholesale price mark-up – Wholesale Lerner index

(Difference between wholesale energy prices and system SRMC)/system SRMC

Could be measured for peak and off-peak respectively.

Retail price mark-up – Retail Lerner index

(Difference between end-user energy prices and wholesale prices)/Wholesale price

Per customer group, excluding network tariffs, taxies and levies.

Trustworthy price reference – degree of spot price pass-through to end-users

Correlation between end-user energy prices and wholesale prices

Per customer group, excluding network tariffs, taxies and levies.

Trustworthy price reference – New capacity build where LRMC < forward price

Yes = 100%; No = 0% Future KPI. Relies on existence of forward markets.

Price transparency – existence of daily published prices

Yes = 100%; No = 0%

Establishment of market surveillance

Yes =100%; No = 0%

Existence of regulated (energy) prices

No = 100%, Yes = 0% For each customer group

Transparent market information

No = 100%, Yes = 0% Publication of all information related to the formation of market prices.

7.2 Access to markets

For an effective market opening it is important that market participants have access to market places where relevant products can be traded. Organized market places are the most accessible type of market place. However, standardized trading contracts and products can also facilitate trading in the absence of an organized market.

Market participants also have the need for hedging price risk. One possibility for hedging is through bilateral (financial) contracts between e.g. a producer and a consumer. A market place for trading financial products provides better liquidity and facilitates access to the market.


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Table 13. Key Performance Indicators - Access to markets


Existence of spot market power exchange(s) open for all market participants

Yes = 100%, No = 0%

Volumes traded at spot market power exchange(s)

Volume traded at spot market exchange in GWh/Total consumption in GWh (%)

Yearly numbers.

Standardized forward contracts/products defined

Yes = 100%; No = 0%

Forward market established Yes =100%, No = 0%

Volumes traded at forward markets

Volume traded at forward market exchange in GWh/Total consumption in GWh (%)

No restriction on market access due to type of market participant

Yes = 100%, No = 0% License systems do not restrict market participation of generators, suppliers, or final customers from direct market participation, including the right to import/export (if relevant).41

7.3 Access to customers

To measure the access to customers three indicators are proposed. The first indicator measures the formal market opening, i.e., the share of consumption that has the legal right to switch supplier. The second indicator measures the share of consumption that is actually exercising the eligibility, and the third indicator the degree of supplier switching within one year. These indicators combined show how accessible the final consumers are for a new entrant into a market.

41 Import/export only is relevant with physical trade and explicit auctioning of

transmission capacities. Otherwise all volumes are bid into the local market.


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Table 14. Key Performance Indicators – Access to customers


Formal market opening Eligible consumption in

GWh/Total consumption in GWh (%)

Number of eligible consumers/Total number of consumers (%)

The time line for market opening is determined by EC regulation and the Energy Treaty

Actual market opening Consumption exercising eligibility

in GWh/Total consumption in GWh (%)

Number of consumers exercising eligibility /Total number of consumers (%)

Consumers that have switch suppliers or left regulated tariffs.

Degree of supplier switching Consumption switching supplier

within one year in GWh/Total consumption in GWh) (%)

Number of consumers switching supplier within one year/Total number of consumers (%)

Measures the consumer switching activity within one year.

7.4 Market structure and competition

Electricity markets are generally vulnerable to market power and it is important to measure that the market structure is such that competition is facilitated. A key issue is to define the relevant market. It may be that neither local nor the full regional market is the relevant market from a competition point of view, and also that the relevant market may vary from time to time (due to changes in demand, available generation capacity and available transmission capacity).

Under the section prices we have also proposed measures that try to capture the mark-up above marginal cost, i.e., the actual competitiveness of the market.


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Table 15. Key Performance Indicators - Market structure


Price correlation between price areas

Simple correlations between wholesale market prices

Relies on the availability of prices

Share of time with price differences

Share of time (%) with price differences between price areas

Relies on the availability of prices

Market concentration, Generation

HHI42

C343

Number of companies with more than 5% market share

All measured both in MW and GWh

Market concentration, Retail

HHI

C3

Number of companies with more than 5% market share

Measured in GWh

Vertical unbundling of generation from TSO

Functional and accounting: Yes = 100%, No =0%

Legal: Yes = 100%, No = 0%

Ownership: Yes =100%, No = 0%

Measurement should be based on legal requirements that are enforced.

Vertical unbundling of supply/retail from DSO

Functional and accounting: Yes = 100%, No =0%

Legal: Yes = 100%, No = 0%

Ownership: Yes =100%, No = 0%

Measurement should be based on legal requirements that are enforced.

7.5 Balance responsibility and balancing markets

A functioning wholesale market is dependent on price dependent bids in order to create liquidity. With the introduction of balance responsibility market participants will have to trade into balance in advance.

Balancing markets allows the TSO to balance the system for deviations after gate closure in the spot market at the lowest possible cost. In the SEE context a regional market is preferable.

42 HHI (Herfindahl-Hirshman Index) is calculated as sum of the square of the market

shares for all market participants: ∑(market share)2

43 C3 (Concentration of 3 largest companies) is calculated as the sum of the market shares for the three largest companies.


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Table 16. Key Performance Indicator - Balance responsibility and balancing markets


System for balance responsibility established

Yes =100%, No = 0%

Full supply contracts Generators and Suppliers, and between Generators and Eligible Consumers abolished

Yes =100%, No = 0%

Balancing market established

Yes =100%, No = 0% Local or regional market

Regional balancing market established covering more than 1 jurisdiction

Yes =100%, No = 0% Yes if the jurisdiction is participating in the regional market

Number of balance responsible parties

#

7.6 Allocation of cross-border capacities

Cross-border capacities need to be allocated in a transparent and fair way and there are requirements to use market based methods for allocation of cross-border capacities. There are two methods for market based allocation: explicit auctioning and implicit auctioning. The market design proposal developed in this study rests on the use of implicit auctioning.


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Table 17. Key Performance Indicators - Allocation of cross-border capacities


System for market based allocation of cross-border capacities established and implemented

Yes = 100%, No = 0% Either explicit or implicit auctioning. If different methods are used at different interconnectors a capacity weighted average should be used.

Share of capacity allocated through market based allocation mechanisms

Capacity allocated through implicit auctioning/Total transmission capacity (%)

Capacity allocated through explicit auctioning/Total transmission capacity (%)

Price differentials and flows Share of flow in right direction

(from low price to high price area), (%)

1-flows in wrong direction

Price differentials and use of capacity

Share of time with price differentials between market areas with unused transmission capacities (%)

Price differentials * unused transmission capacity

7.7 Network tariffs and grid access

It is possible to have different network tariff models within one market, although too large differences may have negative impacts on e.g. the location of investments and dispatch. This study does not focus on the details of the network tariff regimes. However, in order to facilitate trade and participation on an open market distance independent point of connection tariffs or postage stamp tariffs are proposed. Furthermore, non-discriminatory access to the grids is essential for a functioning market.


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Table 18. Key Performance Indicators - Network tariffs and grid access


Establishment of distance independent point tariff (postage stamp)

Yes = 100%, No = 0%

Regulated (non-discriminatory) third party access to grids established

Yes = 100%, No = 0%

7.8 Independent regulators and harmonization of regulations

Independent regulators are important for the functionality of any electricity market. For a regional market it is also important that a functioning regional cooperation between regulators is established. It is however inherently difficult to measure “harmonization”, expect for the case when full harmonization between all entities in a common market has been reached.

Table 19. Key Performance Indicators - Independent regulators and harmonization of regulations


Formal independence Yes = 100%, No =0%

Financial independence Yes =100%, No = 0% The regulator not

dependent on the government for funding

Harmonized licensing framework

Licensing framework meeting the basic requirements of the market design: Yes = 100%; No = 0%


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SECTION IV: MARKET DESIGN AND IMPLEMENTATION


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8. SEE WHOLESALE MARKET OPENING, CONCEPTUAL DESIGN AND REQUIREMENTS

8.1 Choice between different market designs

Choosing a specific reference market model as the key building block for a competitive wholesale SEE electricity market design, is probably the most crucial decision in the project as this will influence many other factors, such as cost of implementation, liquidity in the market place, and in the end it might decide whether the new regional market will be a success or not, measured in broader terms.

To assist in this choice, the Consultant has used a classical decision matrix, with criteria, options (four alternative models), weights for criteria (0 – 100), and ratings (0 – 10).

The four alternative models that have been assessed are:

The European Model (Euro Model)

PJM (Pennsylvania, Jersey, Maryland)

Bilateral Classic (existing market model for SEE)

Bilateral Auction (auction of contracts instead of negotiations)

The following criteria are used:

1. Security of Supply

2. Enhancing Investment Climate

3. EU Mainstream

4. Efficient Utilization of Transmission Grids and Generation

5. Market Price Reference

6. Integration of Renewables

7. Transparency

8. Implementation Costs

Criteria 1-4 are the primary ones given a weight of 100, while criteria 5-8 are secondary and given a weight of 60. Each of the models is evaluated against the chosen criteria

The following arguments are used for giving variable scores on how these models match the criteria:

Security of Supply:

Security of Supply is a focal point independent of the model chosen for the wholesale market. It has to be assumed that the necessary measures are taken by the TSOs to maintain the required level for security of supply whichever solution is implemented. Hence the rating is set to 10 (maximum) for all the options.


The Euro Model and PJM are given a high score, while the bilateral models are given a low score.

The reason for giving a score of 10 and 8 to the two former models, is that the Euro model is in line with the rest of Europe, and will offer especially European investors an alternative to


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investment in Western Europe. Bilateral market models are given a low score as they offer market places with less transparency and less liquidity, which represent a higher risk scenario to investors.

EU Mainstream

The Euro Model is linked to the trends and development of the European electricity market and given the high score of 10.

Efficient Utilization of Transmission grids and Generation

The Euro model and PJM get the high score of 8 since both models provide a merit order use of generation and high utilization of transmission capacities. PJM provides more accurate locational signals through Locational Marginal Pricing (nodal pricing).

Market Price References

The Euro model gets the highest score of 10 as this design provides for the use of zonal rather then nodal market price references.


Large scale integration of renewables is an increasing challenge to any market model worldwide. Different models are however likely to cope with the challenge of renewable and intermittent generation differently. In a future with large amount of renewable and intermittent generation the requirements on the system to handle large fluctuations in output and use of the grid will increase.

The PJM model combines an independent system operator with nodal prices with integrated markets for capacity and ancillary services. This may be a model that is better in handling large amount of renewable generation compared with the Euro model with national or zonal prices and a less strong link between spot markets and transmission companies (see e.g. ref [22]). With this background we have given the PJM model a score of 7, the Euro model a score of 5 and the two bilateral models a score of 3.

Transparency

PJM is given the highest score of 10 as it provides more access to cost data for generation. Compared to the other models The Euro model is based on portfolio bidding into each bidding area which gives less transparency and also self dispatch of generation which might provide less information for TSOs entering into real-time operation


The bilateral classic model is given the highest score as it requires no major changes compared to the current operation in the SEE region. Experience indicates that the implementation of the PJM model is costly.

Summary assessment

Based on this assessment the Consultant recommends the Euro model market design for the SEE region.

The decision matrix is shown in Figure 35, and cumulative scores for each model shown in Figure 36.


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Figure 34.Decision Matrix for alternative market models:


EURO MODEL EURO MODEL PJM PJM BIL CLASSIC BIL CLASSIC BIL AUCTION BIL AUCTION

Criteria Weight Rating Score Rating Score Rating Score Rating Score

0 - 100 0 - 10 0 - 10 0 - 10 0 - 10

Security of Supply 100 10 1 000 10 1 000 10 1 000 10 1 000

Enhancing Investment Climate 100 10 1 000 8 800 2 200 4 400

EU Mainstream 100 10 1 000 2 200 1 100 6 600

Efficient Utilization of T&G 100 8 800 8 800 3 300 6 600

Market Price Reference 60 10 600 8 480 2 120 5 300

Integration of Renewables 60 5 300 7 420 3 180 3 180

Transparency 60 8 480 10 600 1 60 6 360

Implementation Costs 60 5 300 1 60 10 600 8 480

Grand Total 5 480 4 360 2 560 3 920

Alternative market models for the competitive wholsesale SEE electricity market


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Figure 35. Cumulative scores for each market model against the chosen criteria:


0

1 000

2 000

3 000

4 000

5 000

6 000

EURO MODEL PJM BIL CLASSIC BIL AUCTION


Transparency

Efficient Utilization of T&G


Market Price Reference

EU Mainstream


Security of Supply


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8.2 Recommended Conceptual Design

Deregulation of the SEE wholesale electricity market aims at increasing efficiency and promote investments in the power business in the region. Integration with other European power markets will be to the benefit of the region and each of the countries and for this reason a wholesale market design that facilitates this integration has been a prerequisite for the Consultant when proposing the market design.

Figure 36 illustrates the recommended conceptual design.

Figure 36. Conceptual market design

Basic elements are:

1. Local Day Ahead Markets (DAM) combined with bilateral trading and physical forward markets organized by local Market Operators.

2. Implicit auction of cross border capacity

3. Balancing responsibility for wholesale market participants

4. Real Time Balancing Market

5. Transparent Market Data

6. Market Surveillance

7. Intraday Market

8. Capacity Reserve Market

9. Financial Electricity Market

During the initial phase of the wholesale market opening efforts should be focused on the 6 first points.

SEE Regional Power MarketOrganized and bilateral market

one day ahead- auction trade -

Derivatives

Additional Services

Security - Margins - Business reports

Mark-to-Market, Risk Management

Clearing of Bilateral Derivatives

Physical &

Financial markets

Clearing house

Market Operator

DAM

Marketequilibriumhours ahead

- cont. trade -

Hedging

1 day - years ahead- continuous trading -

Balancing

generation

and consumption

in realtime

Services

during the Real-

Time-Operation:

Controlling

frequency and

voltage etc.

BalancingPowerMarket

SystemOperation

Real-TimeOperation

Intraday

FuturesDays Weeks

ForwardsMonths Quarters Years CfDs

Common SEE


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A detailed description of the market design is given in Chapter 9.

The most important tool (based on experience from other markets) to ensure a successful wholesale market opening, is to establish a liquid DAM (Day-Ahead Market). This is the central building block in a sustainable market design based on transparency and equal access.

Initiating wholesale market opening solely by further improving bilateral trade will, at its best, be a very time consuming process and will just involve the big market participants. A DAM will accelerate the process. But, as stressed several times in the report, it is important that both DAM and bilateral trade co-exist. They will allow a market participant to operate its portfolio with the required hedging instruments.

Further development of bilateral markets will be driven by market participants as a response to DAM opening. Auctioning of bilateral contracts rather than negotiations should, however be considered to increase transparency in mid- and long term markets.

DAM liquidity is the key to a successful wholesale market opening. In a region with low regulated prices and possibility for eligible customers to stay under regulated prices, transitional incentives to trade at DAM have to be established by authorities.

Eligible customers can be encouraged to trade at DAM in different ways.

Local markets that allow eligible customers to stay under regulated prices can negotiate special base load contracts – with reduced volumes year by year - for eligible customers if they accept to take the remaining volumes from DAM. In this way eligible customers will have predictability over the transitional period

Local markets that have decided to exclude eligible customers from tariff prices, but experience that competition is not working - might as well offer base load contracts to eligible customers given that they take remaining volumes from DAM.

Other incentives to support DAM liquidity might be

Public Suppliers purchasing parts of tariff customers‟ consumption from DAM

TSO purchasing main grid losses from DAM

During the transitional period volumes at a regulated and favourable price will be gradually reduced. The local authorities must decide on the duration of the transitional period.

The most important decision to secure DAM volumes will be to cancel Incumbent Generators‟ commitment to serve tariff customers directly or through full supply contracts with Public Suppliers (ref. chapter 1.4).

The Consultant recommends a day-ahead market solution for SEE, especially when considering that electricity business in Europe has become pan-European and the involved companies are seeking for markets with equal organization as the main or home markets (e.g. Nordic, Germany, UK, France, Romania, Italy and Spain).

In DAM hourly power contracts are traded daily for physical delivery the next day 24-hour period. DAM handles bids for purchase and sale of power contracts of one hour duration in the defined bidding areas in the region. The price is determined as the balance between the bids and offers from all market participants at the intersection point between the accumulated market supply and demand curves.

It is important to highlight that the introduction of a DAM does not imply removal of bilateral contracts. While bilateral contracts represent the more long-term spectre of electricity contracts the DAM is better suitable for the short-term spectre.


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Existing markets have in this question already clearly stated that day-ahead trading is the preferred trading horizon. Day-ahead trading not only allows a suitable balancing of commitments and available resources with contracts, but is also the preferred source for determination of the reference price for energy. This allows the usage of derivatives for Risk Management and the replacement of traditional long-term bilateral contracts with physical delivery.

The traditional long-term contracts were developed as a product for risk management of both price risk and volume risk. After the implementation of day-ahead markets the experience shows that participants experience a minimized volume risk due to liquid DAMs and price risk is handled more efficiently in liquid derivative markets than in traditional inflexible bilateral contracts. The trading horizon – or risk management horizon – is in today‟s European electricity business reduced to some few years ahead. This is in line with other businesses. Until financial markets are developed within SEE, long term bilateral contracts will be important in order to support investments.

A market based solution which combines transparency and (minimum) liquidity is much to prefer rather than mandatory schemes. The Consultant recommends authorising local Market Operators to set up physical forward markets within their jurisdictions with local Incumbents as market makers. Physical forward markets will soon be changed into financial forward markets, which are much more flexible. This process will be driven by market participants.

However, short, mid and long term bilateral contract will still be important for the market participants in order to hedge their positions and secure their business.

In the SEE region Public Procurement Laws (PPL) require that public companies issue tenders when intending to purchase electricity. The Law shall secure that public interest are protected. Questions have been raised if PPLs prevent Public Suppliers from participating in organized markets like a DAM. Daily bids submitted to a DAM and the resulting procurement of energy is to be considered as a public tender process, thus participation of Public Suppliers must be encouraged.

8.3 Transition Periods, local markets

Exposing eligible customers 100% to market prices from day one of the wholesale market opening will meet hindrance in most countries due to uncertain market prices and their volatility. Political goals to protect vulnerable customers have to be respected. For this reason, the Consultant in this chapter propose transitional schemes by which DAM will work on minor, but sufficient, volumes from day one of market opening and thus quickly provide market based hourly price references.

The need for such schemes will vary across the region, because each jurisdiction has different starting points. The transition period up to full exposure of market prices is to be decided by local authorities.

Some jurisdictions have already taken steps to expose eligible customers to market prices. In general a transition period with steadily decreasing contract volumes at regulated prices is recommended to gain acceptance among market participants.

If eligible customers are allowed to stay under regulated, low tariffs, they will not come to the market. Local authorities can decide, in order to secure DAM liquidity, to grant customers, energy intensive industry in particular, temporary base-load contracts at attractive prices if the customer sources the remaining demand from the DAM.


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Step one in the local wholesale market opening will be to abolish Incumbent Generators‟ commitment to serve tariff customers, directly or through Public Suppliers. Such full supply contracts kill market liquidity and prevent potential market participants to respond to market prices. They should be replaced with standard fixed MW and GWh (base load) contracts between Incumbents and Public Suppliers covering a certain percentage of tariff customers‟ yearly consumption. The remaining part of tariff customers‟ load (variable part) should be purchased by the Public Suppliers from DAM. Full supply contracts between Public Suppliers and customers are, however acceptable. In this situation expected (hourly) consumption will contribute to DAM demand and not stay captured within the Generators‟ portfolio.

Suppliers and Eligible Consumers must be Balance Responsible Parties.

The following two figures illustrate how this downsizing can work.

Figure 37 Transition Period: Market and Regulated Prices Eligible Consumer and Supplier

Public Suppliers and Eligible Customers will – through this design – have a contract at regulated price with Incumbent Generators. The contract volume will be lower than their consumption and preferably base load. This will stimulate efficient use of electricity since DAM will make market prices transparent from day1 and marginal consumption has to be bought at these prices. Incumbents will have no reason to exercise dumping. In a deficit market they can always sell the volumes that are not linked to tariff customers (through base load contracts with Public Supplier) at market prices. And they will have incentives to invest in new production units and upgrade old production units if the market price justifies investment cost.

Such contracts should be signed prior to market opening in order to provide predictability to the suppliers and eligible consumers. Suppliers will thus also be able to publish expected tariff prices to their customers over the transition period if parameters t1, t2, t3 are announced. Suppliers and eligible consumers will purchase the difference between expected consumption and contracted volumes (at regulated prices) in the wholesale market. Bilateral contracts and DAM sourcing will be their options.

It is also recommended to allow consumers – energy intensive industry in particular - to resell volumes contracted at regulated prices. This will enable them to respond to price peaks (demand side response) with large volumes and will provide TSOs with peak hour

Estimated consumption

in t0MW

h/h

timet0 t1 t3t1, t2 and t3 to be decided by Authorities

demand response

Volume purchased atmarket price

t2

Volume purchased at regulated price from generator or supplier


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reserves. This is a good solution for the Generators as well compared with the current situation. As long as they have commitment to serve customers on full supply basis, demand side flexibility will not be exploited. Without resale possibility the customer will operate normally even during extreme peaks and his Generator has to use expensive resources (own production or purchased power) to maintain contractual supply.

Figure 38 Transition Period: Market and Regulated Prices; Generator

Generators will at t1 have capacity available for the wholesale market since full supply contracts will be abolished and volumes sold at regulated prices are below generation capacities. They will have incentives to develop new projects and upgrade old capacity for sale in the wholesale market. Reservation of import capacity to secure public supply obligations will be redundant.

The control parameters (MW, t1, t2, t3 and the level of the regulated price) have to be fixed by local authorities. Regional consensus is not required. This approach leaves local authorities with full control over the transition period and allows a steadily increasing exposure to market prices. Customers will be motivated to adapt to market prices and prices “penetrate” from day one.

Generation output

MW

h/h

timet0 t1 t3

Increased efficiency and/or new generation capacity

Volume sold atmarket price to EC and Suppliers

t2

Volume sold at regulated price to EC and Suppliers

t1, t2 and t3 to be decided by Authorities


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Figure 39 Regulated tariffs and market prices

Public Suppliers and eligible customers will approach the market through increasing volumes over time, building demand side at the DAM from day one1. The MW level of base load contracts at t1 may exceed customer‟s lowest hourly consumption. If so the customer will be a seller in the market for some hours.

This mechanism – buying parts of the volumes for tariff customers at market prices – exposes Suppliers to risks. In order to eliminate this risk, Suppliers must be allowed to adjust (up and down) the tariff price once or twice a year if market prices develop quite different from what was expected when tariffs were fixed.

Another way to mitigate Supplier‟s price/volume risks is to settle deviations from expected cost of “market sourcing” between Generators and Suppliers. With this solution the tariff customers will not be part of the compensation scheme. The Incumbent Generators will have the same economic result as if they have full supply commitment. They now offers volumes exceeding the base load contract to the DAM and Suppliers buy the same volumes (tariff customers‟ variable load) from the DAM.

Consumer’s contract portfolio in t1

Consumer’s contract portfolio somewhere between t2 and t3

Consumer’s contract portfolio in t3


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8.4 Establishment of the SEE Regional market

The proposed Regional Market Design (RMD) presupposes that all participating countries establish local wholesale markets as described in chapter 1.3 and more detailed in chapter 9.

Regional and local processes must go hand in hand when opening the wholesale electricity markets in the SEE region. Local markets are too small and incumbents too dominant for establishing local markets on their own. For this reason expanding the regional activities by linking neighbouring markets through market coupling as soon as they comply with requirements, rather than waiting for local markets to develop is the optimal way to a successful wholesale market opening in the SEE region.

Establishing a regional DAM together with a parallel implementation of local markets, is the pre-requisite for the wholesale market opening. With a carefully designed DAM, liquidity is secured and market participants can respond to market prices from day one of wholesale market opening.

The market model supports cross border trade by integrating capacity allocation and energy trading in an implicit auction. Thereby the market model sets a framework adding services to both the TSOs and the market participants in the region. By using a regional market design with these features all parties can operate an hourly portfolio more efficiently and doing this with less resources and costs. With one active trading period a day the whole portfolio for the next 24 hours will be determined. This will be an efficient tool for the participants to balance their individual portfolio and hence manage risk.

It means that the buyers and the sellers in the SEE Regional Power Market benefit automatically from cross border exchange without the need to explicitly buy the required transmission capacity. Advantages of this mechanism are to maximize the total economic surplus of all participants and adjust prices across the local borders.

Compared to explicit auction of transmission capacities, the market model with implicit auction offers advantages to the participants and is recognized as the best platform for building liquidity and enhance competition a regional market.

The participants trading will generate a common regional physical market for the countries involved and will define a common market clearing price (MCP).

The MCP (system price index) can be used as a reference for medium and long-term physical and financial electricity contracts. The trade of such contracts should be offered to the market participants by the SEE Regional Power Market when confidence is established in the price formation of such an index. DAM and implicit auctions allow supply and demand to set market prices each hour in every bidding area (when grid congestions prevent equal prices) and thus secure correct prices in addition to setting the correct cost for congestion. Market prices will penetrate across the SEE region, bringing transparency (prices and flows) and trustworthy price references to all market participants from day one of the market opening.

The existence of a regional SEE DAM coupled to Central West Europe, bringing transparency and price references, is the best way to foster competition and reduce the potential market power that the local incumbents might exercise. This will bring a close integration with the main European power markets and thus attract investors. The proposed RMD combines DAM and bilateral contracts. Particularly when it comes to large investments, long term bilateral contracts – also including reservations of long term transmission rights – should be an option.


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DAM stimulates competition since market participants are offered an alternative to purchase from incumbents. The RMD can be summarized as follows:

Staged implementation of a regional wholesale market with respect to both participating jurisdictions and market functions

Parallel development of regional and local markets; the high market concentration in each jurisdiction prevents the establishment of independent local markets. It is important to note that this must secure full local control with market development within each jurisdiction but in combination with regional cooperation

A regional wholesale electricity market founded on a regional DAM with local DAMs linked together through implicit auction

Flexible solutions for the local DAMs. Each jurisdiction decides which functions to implement on its own and which functions to purchase from a regional service provider.

Based on the GAP analysis in chapter 10, the Consultant recommends establishing the regional wholesale market from a functional hub adding new participants as soon as they comply with requirements. Romania and Serbia will be the proposed hub. Figure 40gives an illustration of how the regional market can expand through a staged approach.

Figure 40. Possible staged approach for expansion of regional market

Impl. auction

Preparing for impl.

auction

Explicit auction

HU

Candidates

MD

UKR


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8.5 SEE, an integrated part of the European Internal Power Market

Technical operation of the SEE grid system spans 4 control areas within ENTSO-E. Trade across local borders is currently based on bilateral contracts and explicit auctions. SEE Wholesale Market Opening should streamline with European trends with price coupling linking local and regional markets in order to enhance efficiency and transparency.

Regional approaches that choose incompatible solutions would obstruct the process of creating an integrated pan-European power market (ref [12]).

The following figures illustrate how the recommended design complies with current TSO scheduling and ongoing efforts to co-ordinate power trade across Europe.

Figure 41 Information exchange for the scheduling process in the ENTSO-E pyramid (ref ENTSO-E)

No change to ENTSO-E‟s Scheduling and Accounting when introducing DAM. (DAM will replace some bilateral contracts)


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Figure 42 European power market integration, ref. EuroPEX-ENTSO-E, Final Report January 2009

Implicit auctioning fits with EuroPEX-ENTSO-E‟s preferred market coupling mechanisms, ref [12].

Figure 43 European spot prices

Source: EuroPex


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Existing Power Exchanges across Europe bring transparency and predictability to market participants and investors. SEE countries will benefit from harmonization and integration with these markets.

A liquid SEE market coupled to other European power markets and with the same trading regimes will soon establish a reliable and trustworthy price reference for the region and attract investors.

Implicit auctions will link local SEE DAMs to neighbouring DAMs. Transitional solutions with reservation of minor cross border capacities for explicit auctions might be required.

Exchange with neighbouring countries with no DAM will run like to-day, based on explicit auction bilateral trade.

Imbalance handling and settlements must be harmonized according to common rule books.

Integration of European spot power markets made a big step forward when The power exchanges APX-Endex, Belpex, EPEX Spot, GME, Nord Pool Spot, and OMEL 18 March this year announce the creation of a 6 party project aimed at delivering a single price coupling across the Nordic, Central West and Southern European regions, potentially as early as next year. The PCR project will address the implementation of a common price coupling solution through which spot electricity price formation will be coordinated in an area potentially covering approximately 2,900 TWh pa of power consumption. The initiative is open to other power exchanges and market areas joining on fair and equal terms and represents a development towards a truly integrated European spot market for electricity.


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8.6 Requirements

A successful wholesale market opening depends upon engagements and commitments from authorities, market operators and market participants. All stakeholders have to recognize that deregulation of the electricity sector will bring benefits to the region through increased efficiency, enhanced security of supply and climate for investment.

The Consultant has designed a market concept that facilitates a quick integration of the SEE region into European power markets. A number of changes and decisions are required for a smooth transition from the current situation to full integration. These requirements are based upon identified barriers to SEE market opening (chapter 6) such as:

Insufficient unbundling of supply/generation

Deficient eligibility management

Missing systems for imbalance handling

High market concentration

Lack of transparency

To overcome these barriers and secure liquidity in the market place from the start-up a GAP analysis (chapter 10), comparing what the Consultant defines as minimum requirements and the current situation in the SEE region is established and a number of decisions recommended:

Cancellation of incumbent Generators‟ commitment to serve tariff customers. A split of responsibility Incumbents provide public suppliers with base load contracts partly covering tariff customers‟ demand. Contract volumes to be reduced year by year according to a plan approved by local authorities.

Public suppliers purchase remaining volumes from the DAM.

Incentives for eligible customers to source from DAM as described in chapter 1.3 and 8.2. Such incentives bring predictability and prepare the customers for full market exposure.

Mandatory for wholesale market participants to be balance responsible parties – either directly or through traders etc.

Cross border capacity allocated to DAM. In a transitional period it might be necessary to execute congestion management by both implicit and explicit auctions. This can be facilitated by allocating a fixed percentage of cross border capacities, e.g. 50%, to the SEE Regional Power Market for implicit auction, and an equal part for monthly and yearly explicit auctions via the CAO.

VPP (Virtual Power Plants) – auction of generation capacity, volumes decided by the authorities - should be considered if competition is not working satisfactory after market opening. If incentives to trade, as recommended in chapter 1.3 and 8.2, are implemented, VPP auctions will probably be redundant.

TSOs to purchase main grid losses at the DAM

The following are overall requirements applicable to any wholesale electricity market reform:

All participants trade on equal terms, meaning that they follow a common book of rules

Market transparency providing the same information at the same time to all participants

Efficient market settlement and reporting

Market surveillance


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9. REGIONAL MARKET DESIGN

9.1 Introduction

Enabling a liquid regional trade between the local SEE electricity markets will secure an optimal use of the generation (merit order) and transmission resources.

One of the main functions of this regional market design is to provide a transparent day-ahead reference price of electricity and to enhance the trade across the local borders.

The mix of generation resources in the SEE region, between thermal/nuclear and hydro, can be utilized in a more efficient manner if an open regional market is offering day-ahead hourly contracts with full price transparency. This will give both sellers and buyers the opportunity to fine-tune their power portfolios, reducing imbalances and hence financial risks in real-time operation. Establishing a trusted day-ahead price index to be used for settlement of forward financial contracts will also be of benefit for investors in new generation as well as being a hedging instrument for the market participants.

The day-ahead reference price can be published both for specific countries and for the whole SEE-region. Alternatively, there can be specified one reference price only for the SEE region complemented by Contract for Difference (CfDs) between this SEE reference price and area prices in the region.

The proposed market model is dependent on support and commitment by the industry and a stable framework set by the authorities. It is the market participant that will build liquidity by using the market services. This means that the SEE Regional Power Market must be attractive to all participants by adding value, saving cost and thereby open for new services. Market evolution is an important activity and this process must be based on local and regional requirements.

Initially, the SEE Regional Power Market will be focused on physical markets as DAM and balancing markets which are both very closely linked to TSOs system operations. Strong involvements from TSOs in the SEE region are therefore seen as a precondition for the success of a SEE Regional Power Market.

Securing financial viability of the SEE Regional Power Market is vital to attract the necessary investments required to launch and operate the Regional PX.

The different obstacles for a successful market opening are defined in chapter 6.

9.1.1 Definitions

In the description of the Consultant‟s design following in this chapter, there are a set of definitions that will be used throughout the chapter. The most important definitions are listed here:

SEE Regional Power Market – This is the implementation of the RMD for the SEE region.

LMO – Local Market Operator – This is the local market operator for each jurisdiction/contracting party, which is the legal counterparty to all its stakeholders.

Regional PX – This is the regional price setter for the common DAM. This is not a power exchange as such, but the entity that performs the Day-ahead auction on behalf of the LMOs based on an implicit auction. The proposal is that this is performed by a service provider (SEESP). This entity constitutes a cooperation agreement between the involved LMOs and should not be envisioned to be a large organisation, but a body constituting the regional cooperation.


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SEESP – This is the service provider that is responsible for the tasks defined for the Regional PX.

RMD – Regional Market Design.

9.2 General recommendations

In the following sections, the recommendation for the RMD is set out. These recommendations are founded on the requirements set out in the previous chapter and based on the general design features defined further in this chapter.

The Consultant‟s recommendations for RMD are pillared on four core elements:

1. SEE, an integrated part of European Internal Energy Market

Technical operation of the SEE grid system constitutes 4 control areas within ENTSO-E. Trade across local borders is currently based on bilateral agreements and explicit auctions. SEE wholesale market opening should streamline with European trends with price coupling linking local and regional markets in order to enhance efficiency and transparency.

Regional approaches that choose incompatible solutions would obstruct the process of creating an integrated pan-European power market.

2. Flexibility

The key element in the design of a SEE Regional Power Market is the use of flexibility in choosing the level of cooperation between the regional service provider (SEESP) and the LMO in each of the member countries. Depending on size and maturity of each local market, the local market operation can be implemented on an organizational scale from a branch office to a fully decentralized LMO.

In the implementation phase a decision must be made whether to buy facility management services from an existing service provider in the region or to set up a new regional service provider serving the LMOs in the SEE countries.

3. Financial Viability

The only functions that is centralized in the RMD is performing the daily price calculation for the DAM based on implicit auction of cross border capacities and supply/demand bids for hourly day-ahead contracts. This will reduce required investments considerably and secure a financially viable operation of a trading platform for the SEE Regional Power Market.

4. Local Control

Over the last decade, many countries in Europe have chosen to implement a local power exchange, which has resulted in low liquidity and high costs per unit traded.

The RMD recommended by the Consultant will secure a liquid DAM market in a regional context while preserving local control in further development of domestic markets.


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Main Characteristics recommended for the RMD

The Consultant‟s main recommendation for the Regional Market Design can be summarized in the following four points.

Zonal pricing and implicit auction;

Trading platforms for:

Day-Ahead Market(DAM),

Balancing Market(BM),

Intra-Day Market(IDM),

Virtual Power Plant Auctions(VPPA),

Physical Forward Market(PFM), and

Financial Forward Market(FFM).

Ownership in the first 3-5 years of operation is exclusively for the SEE TSOs In the first few years of operations after the implementation of a regional platform, the trade of physical products will be the focal point. These mostly short term products, especially day-ahead, cross-border capacities for DAM and balancing power, are crucial for the TSOs‟ management of security supply issues. It is therefore strongly recommended that the TSOs have an exclusive ownership to the regional service provider and that each TSO owns the local market operator. In the case, services are bought from an existing provider; the TSOs must be the contract counterpart either directly or via its local market operator. At a later stage when the launch of financial electricity contracts takes place, it may be advantageous to introduce additional owners in the regional service provider, e.g. banks and other financial institutions

All TSOs participate from day one in the implementation of the competitive regional market

This follows from 3) above. Ownership and full commitment by TSOs from day one, is the single most important prerequisite for enabling the establishment of a well functioning competitive electricity market in the SEE region.


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Recommended Market Model for SEE

The recommended market model for the SEE Regional Power Market is the DAM concept as discussed in this report.

In DAM hourly power contracts are traded daily for physical delivery the next day 24-hour period. DAM handles bids for purchase and sale of power contracts of one hour duration in the defined bidding areas in the region. The price is determined as the balance between the bids and offers from all market participants at the intersection point between the accumulated market supply and demand curves.

The market model supports cross border trade by integrating capacity allocation and energy trading in an implicit auction. Thereby the market model set a framework adding services to both the TSOs and the market participants in the region. By using a regional market design with these features all parties can operate an hourly portfolio more efficiently and doing this with less resources and costs. With one active trading period a day the whole portfolio for the next 24 hours will be determined. This will be an efficient tool for the participants to balance their individual portfolio and hence manage risk.

It means that the buyers and the sellers in the SEE Regional Power Market benefit automatically from cross border exchange without the need to explicitly buy the required transmission capacity. Advantages of this mechanism are to maximize the total economic surplus of all participants and adjust prices across the local borders.

Compared to explicit auction of transmission capacities, the market model with implicit auction offers advantages to the participants and is recognized as the best platform for building liquidity in a regional market.

The participants trading will generate a common regional physical market for the countries involved and will define a common market clearing price (MCP).

The MCP (system price index) can be used as a reference for medium and long-term physical and financial electricity contracts. The trade of such contracts should be offered to the market participants by the SEE Regional Power Market when confidence is established in the price formation of such an index.


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9.2.1 Overview of business processes

The Consultants proposal is founded on the following:

Each Contracting Party (CP) has its own Local Market Operator (LMO);

Each market participant has an agreement with his LMO;

All bidding, settlement, collateral and participant agreements are made between the market participant and the LMO;

LMO will collect and validate all bids from its participants and creates one Net Export Curve (NEC) combining all the bids from its market participants into one aggregated bid curve (thereby anonymous) that is sent to the SEE Market Service Provider (SEESP) acting on behalf of the Regional PX;

SEESP will collect NECs from all LMOs, and will get ATCs for all interconnections from the CAO. Based on these data, SEESP will calculate a common price index for all areas and price for all individual areas as well as the flow on each interconnection. These values will be returned to the LMOs;

LMOs will have a service agreement with the SEESP for the price calculation as well as with the CAO for the allocation of ATCs to be utilized for DAM;

Prices and volumes for each market participant are calculated by the LMOs.

This design is based on Price Market Coupling as defined in chapter 0.

The business process overview is defined as set out in the figure below:

Figure 44 SEE Regional Power Market – business processes


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9.2.2 SEE Regional Power Market overview

The proposal is based on three main (chronological) processes as indicated in the figure below:

1. ATC – the publication of ATC from CAO (as representatives for the TSOs) to the regional service provider, the Local market operators and the participants.

2. Bidding process – the process where participants submit individual portfolio bids to its LMOs, the LMOs creates NEC curves and submit to the SEESP.

3. Results – where the SEESP calculates area prices and flows based on the NECs and ATC received, send the results to the LMOs and then the LMOs checks results and calculate and send the individual results to the market participants.

Figure 45 SEE Regional Power Market – Local control – regional cooperation

In the following sections as part of this chapter, the details regarding this proposal are discussed.

Market Participants

Bidding

Results/Settlement

NEC NM2

Regional Price Calculation

SEE Service provider

=NEC NM2

+ + ATCall

ATCall

Flowall ICs

Calculation of TC for all interconnections

CAO

Market Operator 1

Scheduling

Bidding process

Create NEC

Bids

ATCall ICs

Prices all areas

Flow all ICsResults

Market Operator n

Scheduling

Bidding process

Create NEC

Bids

Results

NEC NM1

Prices all areas

Flow all ICs

Market Participants

Bidding

Results/Settlement

NEC NM1

Connection flexibilityLocal control –

regional cooperation

1

1

1

2

2

2

2

3

3

3

3

3

3 3

3

2

2


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9.3 Roles and Responsibilities

For the operation of a restructured power market, the following two key organizations should work very closely together.

They are identified as:

The TSO

Market operator

These two organizations will have clearly defined roles and responsibilities along with:

Power industry regulators;

Market participants (power generators, power consumers, traders);

DSOs.

The roles and responsibilities for each of these are described below.

TSO

As a monopoly the grid owner‟s performance and business processes must be monitored by the regulatory bodies.

The TSOs‟ responsibilities as owner of the transmission grid are:

Determine rules and requirements for supply quality and security

Provide routines to maintain short term power reserves

Propose transmission tariffs for the main grid

Manage real time operations and handle unpredictable imbalances and unexpected events

Cooperate with TSOs of interconnected grids

Manage transmission capacity on the neighbouring interconnections for the SEE Regional PX

Manage imbalance settlement and billing

Build, operate and maintain the grid within its defined area

Collect and report metered values

Purchase electricity to cover grid losses

The TSOs play a very important role in deregulated power markets. The TSOs‟ responsibility to operate, maintain the reliability and quality of the power supply will always set the daily framework for the market operations.

Local Market Operator - Regional PX - DAM

A license or cooperation agreement to operate the Regional PX under the framework set by the regulators of participating countries should be issued by the regulator in the jurisdiction where the Regional PX will be located based on the agreement between the TSOs and Regulators in the participating countries.

The Regional PX will operate as a common market place for the whole SEE region and provide services to the LMOs, TSOs and to the market participants, such as generators, consumers and trading companies.


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The core responsibilities are:

Operate a Day Ahead Market for the participating LMOs based on an implicit auction and the market splitting principle. In the future it could also provide services for other related power markets

Provide reference price(s) for energy for the financial electricity market

Use the price mechanisms to alleviate grid congestion through optimal use of available transmission capacity

Act as a reliable counterpart

Report to TSOs, LMOs, participants and to the public required information and data

A power exchange will always facilitate trade, the transparent handling of price sensitive information, support market competition and build market liquidity.

Regulator

Regulators determine guidelines and bylaws for the regulation of monopolies within the power market.

Regarding the SEE Regional Power Market, normally this will cover issues such as inter alia:

Market design and market rules

Harmonisation, definition and approval of guidelines for

power system operation

metering

grid tariffs

etc

Monitoring grid owners and LMOs costs and profits

Provide incentives for eligible customers to exercise eligibility.

Responsibility of Market Monitoring and Market Surveillance both on a local and regional level

Regulator authorities‟ responsibility for guidelines, standards and regulations of the local power system and the power market remains unchanged.

The SEE regulators will play a vital role in preparing and deciding the regional guidelines for the SEE Regional Power Market.

Incumbent producer

Large dominant producers will be important participants in a regional market. They will normally secure their position and further develop their competitive ability inter regionally. An important prerequisite is full competition with respect to allocation procedures of cross-border capacities so that both incumbent and new entrants in generation have equal access to transmission.

Market Participants

Market Participants are legal entities that operate in the wholesale and/or retail markets. They can play multiple roles consisting of one or a combination of the following: generator, consumer, trader, or retailer.


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DSOs

The DSOs will be responsible for measurement within each DSOs distribution area. Metering values for wholesale market participants connected to the DSOs grid have to be sent to the TSO for balance settlement.

9.4 Grid Tariffs

The preferred grid tariff system to facilitate bilateral trade or trade on a power exchange should be characterized by principles that treat all participants on equal terms.

Most important features will be:

Market participants should know the transmission costs at their grid connection point by a tariff set by the grid owner or system operator.

No bilateral negotiations and agreements should be required.

Transmission cost should not be dependent on location of a trade counterpart.

Grid tariffs across the region should be compared and to some extent harmonized to avoid distortions in the markets. Of special concern is, if the variable cost varies both between countries and how these variable costs are allocated to consumers and producers.

The variable cost element in transmission tariffs should be added to the marginal cost for generation when a supplier/generator is setting up their supply bid to a day-ahead market. Similarly for a demand bid the variable transmission cost element should be subtracted in the calculation of bid price.

In some cases the system operators/TSOs are using the variable cost element as a locational signal. When transiting to a regional market these locational signals should be harmonized to avoid sub-optimalization.

Another example is environmental fees that might be placed either on the consumer or producer side in different countries. To avoid market distortion this should also be harmonized among member countries.


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9.5 The relationship between a Regional PX and the Coordinated Auction Office (CAO)

As described in this report, in the final solution when a well-functioning DAM for the whole region is in place, the best solution is that all available transmission capacity is left for the implicit auction (like in the Nordic region) and that in the final solution, long-term transmission capacity auctions will not be needed. However, the main function of the CAO is to provide correct transmission capacities to the market that will be true for any market concept.

As an illustration of the co-existence of CAO and a Regional PX, the following simplified diagram can illustrate this:

Figure 46 Co-existence of CAO and a Regional PX

Dedicating cross border capacity to the DAM is an essential policy decision in order to establish a Regional PX. The CAO will be responsible for determining “tradable” cross border capacities, performing explicit auctions and providing the PX with daily capacities for the implicit auction. In this way the two concepts mutually support each other.

Intraday/

Balancing Mechanism

Long-term auction

(year,quarter,

month, week)(Y% available)

Transfer to DAM(Use It Or Get Paid)(Z)

DAM utilization(TCDAM )

CAO Explicit auctions Day-ahead implicit auction

Calculation of available transmission capacity for DAM implicit auction

(performed at 10:00 D-1):

TCDAM= D + rest of Y + Z + released portion of X

in both directions

The remaining capacity after DAM is available for Intra-day trading

Security margin(X% margin)

DAM reservation(D% reserved)

TSO allocations


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9.6 Details of the Day-ahead Market design

The market design for the SEE Regional Power Market is based on the constant evolution in the power market development in Europe. This has proven to be a competitive market environment where TSOs, the power exchanges, and different kinds of market participants (traders, suppliers, generators etc) have worked together to establish efficient and liquid market places.

The key underlying concept is a physical day-ahead trading and market organization, where the market operations are carried out the day before the traded physical contracts are delivered

This trading method is referred to as the Day-Ahead Market (DAM) auction trading. The price mechanism in the DAM adjusts the flow of power across the interconnectors between the bidding areas to the available transmission capacity given by the system operators.

The DAM provides a neutral reference price for the wholesale and retail markets and for power derivatives trading.

The market is based on portfolio bidding covering products for single bid, block bid and flexible bid. The total geographical regional market can be divided into bidding areas determined by predicted transmission constraints in the meshed electrical grid.

Features of the market concept

Bids submitted from the participants for purchase and sale as price volume pair with linear interpolation between the price points in the price calculation.

Flow-based Available Transmission Capacity (FBATC), must be provided by the TSO in each jurisdiction in cooperation with the Coordinated Auction Office (CAO) to be established in Montenegro, ref previous chapter.

Cross Border Trade, facilitated by day-ahead implicit auction and longer term explicit auctions.

Congestion Management, integrated in the price calculation.

Balance Responsible Party, agreement to control the participant‟s balance within each bidding area defined by the TSOs.

Reporting and Settlement can be handled centrally or locally.

Inter-Coupling or Market Coupling, coupling with another regional or local market by the exchange of Net Export Curves.

9.6.1 Legal and Formal Requirements

The participants in the region will be given access to the SEE Regional Power Market through formal agreements including an acceptance of the book of rules, as well as technical access to the market systems through a technical interface provided by the LMOs for the Local DAMs.

All participants who meet the legal and formal requirements set by the LMOs and the TSO can access the DAM. The formal requirements will be such as agreements with the TSO for establishing a trading HUB and collection of meter values in the area.

As far as the DAM is concerned, the participants will have to accept the book of rules, sign the participant agreement and to document an approved bank account with the required collateral.


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Trading on the DAM will also require that the market participants have a balancing agreement with the respective transmission system operator or through a balance responsible party for each bidding area the participants are actively buying/selling. Such an agreement will regulate the compensation requested for having an unbalance in the real-time operation by each balancing party.

9.6.2 Business Processes

The market model will be managed by the Regional PX operating the centralized tasks for the SEE Regional Power Market. In each Local DAM, a branch office or an already established local market could support the Regional PX by performing tasks i.e. training local participants, marketing, collecting bids, and settlement of trade.

The business process in the figure below is an example with defined local operations. A regional exchange should include the flexibility in business processes and in the IT-Infrastructure to facilitate various degrees of local operations. This can be required due to local legislation, local bank infrastructure and requirements from the local TSO.

Figure 47 Business process example

Local Settlement Service/Bank: The business solution proposed is opening for local clearing and bank services both for a branch office and for a Local DAM. It is important that both the business process and the IT-Infrastructure are flexible in this respect to handle local legislation and currency.

Local Market Operation: Local market operations include handling of all functions that will integrate directly with the participants, TSO and local authorities. It is vital that these functions are facilitated by the SEE Regional Power Market due to different languages, currencies and local legislations.

Bidding

Local Market Operation

Regional Market Operation andPrice Calculation

CAO/TSO

And / or

BalanceResponsible

Company

Cross Borderflow

Capacity

Capacity

Schedules

Settlement

Local Settlement Service / Bank

PricesSchedulesCapacity

ParticipantBalance

Validated Bid

Participant Settlement

MarketParameters

Results

1

1

1

2

2

3

3

4

3

5

0

4

2


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Regional Market Operation: Regional market operations cover all the common operations required to build the Regional PX, market liquidity and establishment of market framework for further business development. The regional operation could deliver services to branch offices and/or Local DAMs after individual agreements.

The SEE Regional Power Market operation and business processes are based on an agreed harmonized market framework.

9.6.3 TSO and Balance Responsible Party

The TSO and the Balance Responsible Party are integrating with the Regional PX through the LMOs. The TSO is submitting the available transmission capacity (flow-based) and is receiving the flow and participants schedules, both individual values as well as aggregated values. The TSO will use these values for planning the daily hour by hour operation.

9.6.4 Market Harmonization Parameters in the DAM

The following market harmonization features are required to facilitate the market model. With a centralized solution these features will be harmonized automatically in the configuration of the market model. With a decentralized or partly decentralized solution these features have to be agreed.

Operational Time zone for the DAM

Timeline for the required market operations

Rules for handling daylight saving time

Gate closure

Master currency

Upper and Lower price limit for bidding (these are technical limits not regulatory price ceilings/floors)

Allocation of transmission capacity for the interconnections made available to the SEE Regional Power Market


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9.6.5 Timeline for the DAM

Below is an example of the timeline for the DAM operations:

Market opening time all business days - 08:00 to 16:00

CAO publishing the transmission capacity for the market - 09:30

Market gate closure - 12:00

LMOs creates NEC curves for each area - 12:00

LMOLMO submits NEC curves to SEESP - 12:05

Market price (and flow) calculation time - 12:05

Market result distribution time from SEESP to LMOs/CAO (flow) - 12:15 to 12:20

Market result calculation time (LMOLMO creates participant results) - 12:20 to 12:30

Market result distribution time from LMOs to participants - 12:30 to 12:45

Market dispute time - 12:45 to 13:15

Balance Responsible reports - 13:30

TSO reports - 13:30

Market data transfer to settlement - 14:00

Delivery start for day-ahead contracts for hour 1 - 24:00


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9.6.6 Implicit auction

In theory the liquidity and number of participants that takes part in explicit auctions can be similar to the number of participants in implicit auctions. However, participants in DAM represent both the demand side and supply side and are experienced to include far more participants than an explicit auction. This is important for price determination.

Explicit auction involve mainly medium and long term capacity rights. The administrative challenges to utilize the capacity also on short term can be too complicated. Therefore maximum utilization of available capacity on interconnection can not be achieved without involvement of implicit auction.

Implicit auction include netting of trade contracts. It is the netted contact volume that decides on congestion not the gross volumes.

Implicit auction will always lead to contractual flows in direction towards high price area. Negative impact of bilateral contracts in the opposite direction is reduced through increased capacity in the correct direction.

Implicit auction will reduce the need for wheeling of bilateral contracts through different control areas. Without implicit auction the number of international bilateral contracts may be very large and involve a considerable volume of data to be exchanged between control areas. Bilateral contracts should as far as possible be financial only.

Implicit auction is flexible and can easily take care of capacity not used by the participants:

The principle of “use it or loose it” - The power exchange can take over not used capacity with no compensation paid to the holder of the right and apply the capacity in implicit auction.

The principle of “use it or get paid for it” - The power exchange can take over the capacity and apply this in implicit auction. The holder of the capacity is paid a share of the capacity income in case the capacity rights were in direction towards a deficit area. If the direction of the rights is in the opposite direction there will be no payment.

9.6.7 Areas in the DAM

In the market model the regional market will initially be configured with the defined network topology as fixed bidding areas.

An area in the market model can be a whole jurisdiction or a part of a jurisdiction. This means that a jurisdiction can be split in two or several bidding areas if permanent grid constraints require this. All participants are connected to a trading HUB that is uniquely part of one area.

9.6.8 Products in the DAM

The following products are normally defined in a DAM:

Single bid

Block bid (future)

Flexible bid (future)

In a second phase of the SEE Regional Power Market development, the trade in forward products should be offered. This can be physical contracts initially, and at later stage financial contracts using the SEE Regional Power Market DAM market clearing price as reference price.


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9.6.9 Bidding process

Bids are not related to any specific physical resource. All bids are related to a defined bidding area by a defined trading hub. All bids have the same priority. This is known as portfolio bidding.

The single bid must be monotonously increasing. Each price must be higher than the previous price. The first bid price must be equal to the minimum price limit, and the last bid price must be equal to the maximum price limit.

The block bid for sale or purchase shall contain the same quantity for several hours. The sale bid will contain a price that indicates that if the average market price over the period (block) is lower than this level, the bid is not accepted. The purchase bid will contain a price that indicates the maximum price the purchaser is willing to pay. If the average market price in the period (block) is higher than this price, the bid is not accepted.

The flexible bid is relevant in potential peak-load hours, where power shortages cause high prices. Flexible bids are available for power sales only. Flexible bids consist of a price and a volume; hour is not specified in the bid. The price indicates the lowest sell price, and if any hourly market price exceeds the bid price, the flexible bid will be accepted in the hour with highest price.

9.6.10 ATC allocated to the SEE Regional Power Market

This information shall be provided by the TSO for each interconnection. In the current framework, this will probably be granted through the CAO. The ATC made available to the SEE Regional Power Market for implicit auction will be specified for each direction between the bidding areas.

Features of the implicit auction:

Participants in DAM represent both the demand side and supply side.

Maximum utilization of available capacity on interconnections can only be achieved by using implicit auction.

Implicit auction include netting of trade contracts. It is the netted contract volume that determines whether the transmission capacity is fully utilized, not the gross volumes.

Implicit auction will always lead to contractual flows in direction towards high price area.

Negative impact of bilateral contracts in the opposite direction is reduced through increased capacity in the correct direction.

The principle of “use it or loose it” may be applied. This means that capacity rights not used should be given to the day-ahead market.

9.6.11 Price determination

All the accepted bids are used in the price calculation. The price calculation will follow directly after the market gate closing time.

All the market parameters and the bids for each of the 24 hours determine the market clearing price, the area prices, total sale and purchase volumes and each participant's schedules.


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Linear interpolation

Between the discrete price/quantity points submitted by the participants, the bids will be interpreted as piecewise linear curves. Therefore such a curve will define the bid quantity for all prices within the price interval allowed in the auction.

An example of a bid illustrating the linear interpolation is shown below:

Figure 48 Example of bid with linear interpolation

System price

All bids will be added to an accumulated curve for purchase and for sale. The intersection of these curves will define the equilibrium price where the purchase and sale balance. This price is the unconstrained Market Clearing Price (MCP) and will be the official reference price for all traded contracts in the auction in case of no congestion. The MCP will be calculated for each hour and also published as an un-weighted average price for the 24 hours day-ahead market.

Area price

If the transmission capacity between bid areas for the DAM contracts is not sufficient, congestion management in the implicit auction will be performed in the defined meshed network. If congestion is detected between any areas, the price calculation will continue and compute local prices to relieve detected congestions.


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9.6.12 Market reporting

When the price calculation has been conducted, the SEE Regional Power Market operator publishes the results.

The market model extracts the necessary participant information (electronic address, etc) and transmits the prices, the total sale and purchase volumes, and the schedules to the participants.

The prices and the individual schedules will be published to the participants. The general prices and market turnover is public, while the individual schedules only are sent to the individual participant.

Participants traded schedules will be accumulated by the LMOLMO per Balance Responsible Party and reported to the Balance Responsible Party and to the TSOs. The Balance Responsible Party and the TSOs will get the individual and the accumulated values. Each participant will get his own schedule only.

The TSOs will also get an exchange report for the flow on each interconnection

9.6.13 Settlement

The market model will include a settlement process. The settlement process will read the participants schedules, prices and configuration data and perform a central settlement calculation. Based on this calculation the model will open for a decentralized reporting, billing and credit checking process.

The primary tasks of the settlement process are:

Calculate amounts to be transferred between the LMOLMO and the members, including all trades, fees and VAT.

Calculate security requirements.

Generate and distribute settlement details and invoices that specify in detail the volumes, amounts and fees of each member.

Generate result files to be used for clearing services.

Store information from the settlement process for archiving and auditing requirements.

Interface to a bank.

The market model will keep all required settlement data for audit trail and as long as required for storing of financial data.

The Settlement process will be performed by the LMOs.

9.6.14 Billing

A separate billing interface for the actual invoices of the trades will have to be set up by the LMOs.


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9.6.15 Collaterals

An important task in every market setup where the market is a central counterpart to all trades is to have an efficient and transparent collateral management in place. Based on which party that will be the legal, financial counterpart as well as the timeline for settlement and billing, a regime for this must be set up. This shall be based on a set of generic requirements:

Credit Cover is collateral required to be posted as a guarantee against a Participant‟s Credit Risk in the DAM.

In the event of a payment default, this Credit Cover can be utilised by the LMO to satisfy the Participant‟s outstanding financial obligations in the DAM.

A Participant may meet its Credit Cover requirements by posting a combination of types of collateral accepted by the LMO.

In the event of the failure of a Participant to pay an invoice in full, Posted Credit Cover will need to be accessible in a timely manner such that the LMO can meet all payment obligations of the market.

The actual rules for calculation of the required credit cover shall be created for each LMO in such manner that the market is not exposed to any unnecessary risk.

9.6.16 Jurisdiction specific setup

There are a set of jurisdiction specific parameters that needs to be supported. Many of them concerns the financial transactions as defined above. Some of these jurisdiction specific parameters are, inter alia:

Language support in all interfaces (both user interfaces, user guides, reports and technical interfaces)

Banking interfaces to the local banking partner(s)

Adaptation of local collateral management regimes

Management of local currencies if not a master currency will be used

These parameters will be part of the local operations, at least in the initial phase, and needs to be set up according to the needs of each individual area.

9.6.17 Impact of renewable generation with priority dispatch

RES Directive 2009/28/EC promote renewable energy within Europe. Priority access and guaranteed access for any electricity production will influence market prices independent of market organization.

In a market based system renewable electricity is integrated into the spot market through owners‟ daily nomination and this production is thus guaranteed access to the grid.

If the prioritized volumes are guaranteed and bought at fixed prices by the TSO on a purchase obligation bases, and handled bilaterally outside the DAM, demand nominations at the DAM will be reduced correspondingly. Equal sales and demand volumes are withdrawn from the DAM and the market intersection remains unchanged.

Over time, as renewable incentives work, prioritized production inevitably will influence investments in more expensive generation and market prices will come down if new capacity exceeds increased consumption.


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9.7 Intraday Market

An intraday market is a continuous trade system where participants may place orders/bids on purchase and sale of spot contracts continuously throughout the opening period each day. A trade agreement is made whenever two participants meet on price. Unlike an auction trade where all trades are based on the same price, trades in a continuous trade system are based on different prices for each trade. The official price is in most cases based on an average price of the last traded volumes before the DAM closes down.

When the DAM closes there is a lengthy time span (24 hours the day of delivery + the hours between the time for price fixing and 24: 00 the trading day), when participants no longer can improve their physical electricity balance. An Intraday Market is an after market to the DAM that enables actors to refine their wholesale power portfolios up to a point closer to real time.

For hydro power producers whose variable costs for increasing or reducing the output are low, an intra-day market is not as critical as it is for e.g. combined heat and power plants that face high variable costs.

The product characteristic of an Intraday Market is quite simple. For each and every hour of the day there is one power hour contract quoted. Minimum contract size is 1 MWh/h.

The Intraday Market trading System automatically control the cross-border capacity, which is given when the deadline for filing complaints on the DAM has elapsed and the cross border capacity that is left after DAM is known. Using an example from Nord Pool, if there is no capacity from Finland to Sweden the participants in the Swedish and the Eastern Danish market area cannot see the sale bids placed by participants in the Finnish market area in their intraday market price information window. If the bids are inside the given cross border capacity the different market areas are treated as one.

An Intraday Market provides a service to market participants to adjust their balance before the operational hour. This will reduce the balancing actions to be carried out by the system operator in real time.

Intraday market can be used to re-balance a portfolio:

If there is a deviation between predicted forecasts and current loads.

If there is a technical event causing an imbalance after the Day Ahead Market is closed.

To avoid paying a high penalty for having an imbalance in the real time balancing market.


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9.8 VPP Auction

When purchasing a Virtual Power Plant (VPP) capacity, the buyer has a right, but not an obligation to purchase power at a fixed price. The company that buys VPP capacity obtains the right to deliver power as if the company owned a power plant. The power plant is virtual because the producer company still owns the plant and is responsible for the actual power supply.

The purchase of VPP capacity represents a supplement to the purchase of power on power exchanges or from OTC suppliers.

The VPP capacity is sold for predetermined periods at an "option price". The option price is set in an auction prior to the period. For each hourly period in which the option is exercised, a pre-determined fixed "energy price" is paid for the actual quantity of power sold. The total payment for the use of the virtual power plant thus consists of an option price plus and an energy price.

The VPP auction will reduce the dominance of large incumbents and open up the power market for increased competition.

Cancellation of Full Supply contracts and introduction of ordinary contracts between Generators (incumbents) and Public Suppliers and Eligible Customers in the transitional period – as described in 10.2 - has the same effect on market concentration as VPP. Both solutions reduce incumbent‟s dominant market position. A VPP gives the buyer capacity based on an auctioned price while a “transitional” contract gives the buyer a capacity at a price determined by Local authorities. The latter price has to be low in the transitional phase in order to encourage Eligible Customers to exercise their eligibility. They will not switch unless the mixed sourcing – market and transitional contract – gives lower price than tariff prices.

For this reason, the Consultant does not see the need for VPP auctions from day one of market opening. VPP auctions might be considered later when downsizing of volumes for tariff customers has “strengthened” incumbents‟ potential dominant market position.

VPP Auctions serve however other important missions: They bring transparency to the forward market and offer hedging instruments to market participants.

Auctioning of bilateral contracts brings transparency, but volumes are not guaranteed unless local authorities come up with special regulations.

A market based solution which combines transparency and (minimum) liquidity is much to prefer rather than mandatory schemes. The Consultant recommends a solution in which local Market Operators set up physical forward markets within their jurisdictions with local Incumbents as market makers.

Physical forward markets will soon be changed into financial forwards as this is a much more flexible solution. This process will be driven by market participants.


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9.9 Market Information

All relevant market information must be available to all market participants at the same time

The SEE Regional Power Market in cooperation with system operators, LMOs, generators and other power industry associated companies, collects and distributes price sensitive market information based on the following principles:

The information comprises data from events that can influence prices.

The information shall be aggregated and be presented in a way for everybody to read and understand. For the SEE Regional Power Market this might mean that distribution of market information must be published in both the chosen official business language and also the local language.

The information must be distributed at the same time and with same method to all participants.

Energy markets are complex because of the inherent interaction of physically traded commodities, highly technical fundamentals and financial contracts. In order to succeed in the market, market actors need access to accurate and reliable market information. Hence, to provide comprehensive market data service (MDS) of high quality is an important task for the market operator and for the TSO. Examples on market information could be:

Real time feed - Real-time access to prices and operational data in the power and emissions markets including Urgent Market Messages (UMM).

FTP statistical database - Historical database which contains information from the market operator and TSOs.

Reports - Various weekly reports containing operational and physical market data.

Mobile market data (SMS/WAP) - Get daily spot price update via SMS text-messaging or WAP.

9.10 Market Surveillance

To build a trust in the market model and in the SEE Regional Power Market and to develop a good functioning power market in terms of size, liquidity and transparency, the participants must have confidence in the markets price mechanism, its integrity and the market information transparency

Market surveillance has an important role in establishing and maintaining this confidence and integrity by having a strong and visible presence in the market.

Market surveillance continuously monitors the market conduct of trading participants, and investigates possible breaches of the trading rules or applicable laws.

The SEE Regional Power Market will be under the jurisdiction of the jurisdiction of location. Market surveillance issues reported to the Local authorities of location should therefore be discussed in the ECRB where regulators from all member countries are participating.


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9.11 Inter-Regional Market Coupling

The market model, market management and the IT-Infrastructure should facilitate an Inter-Regional market coupling to utilize the transmission capacity between neighbouring regional exchanges.

The following figure describes the concept.

Figure 49 Inter-Regional Market Coupling

Business Process and Harmonization for Inter-regional Operation

Market coupling is a method for integrating electricity markets in different areas. With market coupling the daily cross-border transmission capacity between the various areas is not explicitly auctioned among the market parties, but is implicitly made available via energy transactions on the power exchanges on either side of the border (hence the term implicit auction).

It means that the buyers and sellers on a power exchange benefit automatically from cross-border exchanges without the need to explicitly acquire the corresponding transmission capacity.

The main purpose of this mechanism is to maximize the total economic surplus of all participants: cheaper electricity generation in one jurisdiction can meet demand and reduce prices in another jurisdiction. Prices will equalize across adjacent countries where there is sufficient transmission capacity. Coupling more than one exchange also leads to a more efficient use of the daily capacity of the interconnections.

SEE Regional Market Service Provider

ParticipantBidding

Market Coupling

Coordination

Settlement

Capacity

Capacity

SchedulesPrices

PricesSchedulesCross Border Flow

Capacity

Net Export curves


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The market coupling is designed to enable different power exchanges to be coupled in a manner that requires them to make minimal changes to their market rules. For the members of the individual power exchanges, bidding methodologies remain practically unchanged. The involved Power Exchanges continue to exist as legally separate markets, with their own clearing and settlement arrangements.

This method is successfully used and planned used between various markets in Europe.

The business process for inter regional market coupling is based on exchange of bids defined as Net Export Curves (NEC) and the individual block bids.

The following market harmonization rules are required to facilitate the inter-regional market coupling.

Choice of time zone

Rules for handling daylight saving time

Gate closure

Master currency

Upper and Lower price limit for bidding

Decimals represented in transmission capacity and flows on the interconnections

Any deviation from these rules can create price differences in the market result.

Market coupling models

There are two main types of market coupling implemented:

Price coupling

Volume coupling

The business processes are almost the same. The main difference is that in price coupling, it is the central market coupling service provider who calculates both prices and flows, and the Local market operators will use this price to create the schedules for their participants.

In volume coupling, it is only the flow on the interconnections between the areas that are sent to the LMOs, and a local price calculation will be performed by each LMO.

TLC (Netherlands, Belgium and France) is an example of a price market coupling solution. The recommended design for SEE is very close to the current TLC market.

EMCC (between Denmark and Germany) is an example of a volume market coupling.

The price coupling is considered the best solution as it ensures the best economic result for all parties. In volume coupling, there is a risk of discrepancies as there is a possibility of getting different results based on the local price calculations performed by each LMO compared to a central calculation. The experience from EMCC has proven this fact.


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Net Export Curve (NEC) definition

A general definition of the NEC for hour h is that it gives the potential net export of a market Q(h), based on hourly orders, as a function of an imposed MCP(h), i.e. the difference between total hourly sales and total hourly purchases at that price. The figure below shows a stylised representation of how the NEC is derived from aggregate purchase and sales curves.

Figure 50 Generation of NEC – an visual example

9.12 Real-time Balancing Market

The System Operator is responsible for balancing the supply and demand in real-time, by keeping the frequency within acceptable deviation from the set point of 50Hz. In order to manage the balancing, the System Operator will call upon various ancillary services offered by the market participants. These ancillary services are made available to the system operator by either contractual obligations or through organized markets for these services.

Initially, only tertiary response will be procured in an organized market. Tertiary response services are balancing services that the system operator can use to rebalance the system from 5 minutes ahead and up to the end of the day. This market is called the Real-Time Balancing Market (RTBM).

Primary and secondary response services are initially made available to the system operator through long-term contracts. However, in the future organized markets may be set up for these services.

The Real Time Balancing system solution shall allow for market solutions for procurement of additional ancillary services apart from RTBM.


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9.12.1 Participation in the RTBM

The RTBM shall in principle be available for all market participants – including demand side assets - that comply with the rules for the market. The requirements for participation in the RTBM shall include, but not be limited to:

Balancing services shall be associated with physical facilities for generation or consumption of electricity.

The facilities shall be properly metered.

The facility operator shall react and comply with the dispatch instructions submitted by central dispatcher by either automated dispatch or manual dispatch as specified later in this document.

9.12.2 System Operation

The principles of operation of the system by the System Operator are:

The System Operator may prepare total system load forecast on a daily basis or receive load forecasts from DSOs or from Balance Responsible players.

The System Operator will receive the market participant‟s balanced schedules from DAM schedules.

The System Operator will receive all import/export schedules.

The System Operator will receive notifications of physical bilateral contract schedules from the market participants.

The System Operator will operate the RTBM for balancing services.

The System Operator will have contracts for access to all other required ancillary services.

In real-time, the System Operator will monitor the system frequency. In case of deviation from set point, the system operator will use primary and secondary reserves to rebalance the system. If this is not sufficient, and in order to free primary and secondary reserves, the System Operator will start dispatching balancing power from the RTBM to balance the market.

The System Operator is responsible for ensuring that the total capacity reserve at any time is within the limits defined in the system operation procedures.


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9.12.3 Bid Structure

The System Operator operates the RTBM – the purpose of which is to create a stack of generation and demand side offers to increase or decrease their energy to the market as the System Operator sees necessary to balance the market in real-time.

The Real-Time Balancing Market is open each day after the DAM is closed and the DAM prices and schedules have been published to the market participants. The market participants will at that time know their energy schedules for each facility for the next day, and can determine the balancing power available to be offered to the RTBM.

The market participants (generation and demand side) submit an upward regulation offer (price/MW and volume in MW) and a downward regulation offer for each physical facility 44 and for each hour of the following day. The upward and downward offers may have different prices per unit.

The offer prices are related to the spot-price; in other words a decrement price reflects the price reduction relative to the spot price a participant is willing to reduce his generation for; and the increment price an participant is willing to increment his generation for (similar for load). See illustration below.

Figure 51 Bids at Real-Time Balancing Market

The offers for increments and decrements of generation and load are submitted to the System Operator though the RTBM Bid Tool.

The bids are arranged in merit order of price.

The RTBM participants will, as part of their registration process, submit information about the physical properties of the assets – such as ramp rates, run times, no-run costs etc.

The System Operator will use an automated dispatch optimization tool or a decision support tool to dispatch the assets it needs for real-time balancing. The automated dispatch

44 Note that the offers to the BM is facility oriented – as opposed to the portfolio oriented

DAM. This implies that the market participants shall also register operational and cost related facility data to the System operator.

Downward

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optimization tool will use a computerized algorithm that will find the optimal selection of regulation dispatches whereas the decision support tool will provide to the human operator sufficient information (like the bid stack and asset parameters) in order to make the optimal selection of regulation dispatches.

9.12.4 Real-Time Market pricing methodologies

Real-Time market pricing can be calculated in a number of ways, and the various markets worldwide have different methodologies. Two examples are presented below:

The single-price method:

In the single-price method only one real time price is defined for each hour. The price is defined as follows:

In hours with only upward regulation the real time price is equal to the highest offer called to dispatch.

In hours with only downward regulation the real time price is equal to the lowest offer called to dispatch.

In hours with both upward and downward regulation the predominant direction of the regulation defines if it is upward or downward.

If there is no regulation within the hour the real time price is equal to the spot price.

The two-price method:

Pricing of imbalances is based on real time prices. The upward regulation price is equal to the highest offered price called to dispatch and the downward regulation price is equal to the lowest offered price called to dispatch.

There are two prices, one for upward and one for downward regulation for each hour.

In hours with only downward regulation the upward regulation price is defined to be the spot price (or any other reference price if there is no spot market implemented).

In hours with only upward regulation the downward regulation price is defined to be the spot price.

If no regulation within the hour both upward and downward real time prices are equal to the spot price.


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Pricing and Calculation of Imbalances

When metered data are processed imbalances are calculated. The imbalance for an hour is the difference between contracted schedules and actual metered volumes.

If the System Operator can manage to rebalance the system within an hour using the primary and secondary ancillary services, the System Operator will not need to dispatch any resources from the RTBM. The Real-Time Price will then be set equal to the Day-Ahead spot price, and there will be no imbalance settlement for the market participants. There is, however, a cost of using these primary and secondary resources incurred by the System Operator, and recovery of this cost will be socialized through the System Operation Tariff.

If the System Operator needs to call upon the RTBM resources to balance the market, the Real-Time price(s) will be calculated as the marginal price(s) of the RTBM.

Imbalances may be positive or negative. Positive imbalance means actual resources are more than the commitments for the specific hour. Negative imbalance means that actual resources are less than commitments for the specific hour.

Cost of imbalance in markets with one real time price:

The participants are credited and debited based on the same Real-Time Price. Negative imbalances are charged for and positive imbalances are credited. Imbalances may represent a profit or a loss. This method is simple and the risk for losses is assumed to be sufficient financial incentive for market participants to carefully balance their schedules.

Costs of imbalances in markets with two real time prices:

The general rule is that participants are credited and debited for both positive and negative imbalances for the less favourable of the two prices. However, if the imbalances is “helping the system” i.e. in the same direction as the total system requires, the participant is charged and credited based on the spot price. This means the participant has no losses or profit on the imbalances compared to trade in perfect balance in the spot market. This model for pricing of imbalances and implies a stronger financial incentive to operate with balanced schedules and are implemented in most of the restructured markets.

In principle, the market participants shall be encouraged by the real-time imbalance penalties to minimize the imbalances they impose onto the system. They will mainly use the Day-Ahead market to trade themselves into balance, and will be more cautious in their real-time facility operations if they are aware of the imbalance penalties.

On the other hand, if the imbalance penalties are severe, some participants, especially smaller auto-generators, renewables with uncontrollable generation and demand side may not be willing to take the risk of the severe penalties of imbalances, and will redraw from the market and become self-scheduled participants.

The RTBM system solution shall support a Real-Time Pricing mechanism that gives the market participants the right incentive to avoid imposing imbalances in the real-time market, but not impose so strict penalties for imbalances that it discourages the market participants from participating in the market.


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9.12.5 Capacity Reserve market

There are set predetermined minimum requirements for capacity reserves in SEE. These requirements may change over time and location and shall be system parameter in the Balancing Mechanism.

The total aggregated stack of offers to the RTBM is in effect the available Capacity Reserve market, since the stack represents the total capacity that the market participants makes available to the system at any time.

However, it is likely that the total stack of RTBM offers does not fulfil the minimum reserve requirements. The reason is that market participants has not direct incentives for holding capacity back from the energy markets (Day-Ahead and bilateral) in order to offer them into the RTBM. The offers to the RTBM will be for extra “top-up” energy that is not fuel efficient, and these offers will typically drive the Real-Time prices up. On the demand side, there is no direct incentive for the consumer to enter “stand-by” offers to reduce load.

In order to encourage suppliers and demand to offer sufficient capacity into the RTBM, incentive arrangements such as a capacity availability payment have to be put in place.

This capacity reserve payment can be structured several ways. Two structures are presented below as examples:

1. A regulated availability payment price. The System Operator will set the regulated price to a level that ensures sufficient incentives for participating in the RTBM, and will adjust the price at a regular interval.

2. A market determined availability payment price. In this case, market participants will submit bids for their willingness to offer capacity into the RTBM. The System Operator will pick the cheapest bids until the capacity reserve requirement is met. The availability payment price is set to the equal to the last bid accepted. This selection process could be on an hourly basis, or for longer terms – for example weekly or monthly.

The RTBM system solution shall support a capacity availability payment arrangement, which provides incentives for ensuring a sufficient capacity reserve.


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9.13 Financial Market

One of the inherent and unavoidable features of any physical electricity market design are unpredictable and volatile prices. Introduction of a regional physical day-ahead market will presumably lead to increased volatility in both the DAM and also in the short-term bilateral market, since market participants is expected to arbitrage 45 between these two markets. In this report, the focus is on this combined wholesale market and the short-term wholesale prices emerging from those.

It is at this stage important to note that wholesale electricity is traded through various methods and at various price determinations in SEE:

Long-term bilateral contracts which today represents the bulk of the wholesale market is subject to regulated and/or contracted prices and do not represent much uncertainty (volatility).

Short-term trading; through bilateral contracts and in near future, through DAM; represents much higher volatility, since these prices are not to (or should not) be regulated and are typically derived from the equilibrium between supply and demand at any moment of time46. Both available supply and demand will vary significantly over time and thus introduce high volatility.

Real-time “trading”. In this context real-time “trading” is represented by the balancing mechanism, where real-time imbalances are in effect “sold” and “procured” by market participants using a balancing power market and also the connected imbalance pricing.

The focus in this chapter is on the short-term wholesale market and the prices derived from that market. As mentioned before, it is expected that even if there are concurrent bilateral and PX short-term markets, the prices in those markets should be closely correlated. We shall therefore refer to the short-term hourly price as the Market Clearing Price (MCP), representing the price that is derived from the equilibrium between supply and demand in the short-term markets.

The purpose of an SEE Electricity Derivatives Market shall therefore be to provide an “instrument” or “tool” to “hedge” (i.e. offset risk) against the MCP price volatility derived from the PX and short-term bilateral markets.

The most effective and common arrangement for handling price risk in electricity spot markets is electricity derivatives contracts markets.

The term “derivative” is used in the context of commodities trading as a financial product (contract) that derives its value (i.e. its payoff) from the price of an underlying commodity. In this context, the “derivatives” in the SEE market will derive their values from the PX‟s Market Clearing Price.

In the chapter for the Regional market design the topics of market splitting and zonal prices has been presented. That means that there typically will be several and potentially very different clearing prices in the various SEE countries. Ideally one may develop different electricity derivatives contract for each of these countries, but that may dilute the liquidity and increase the complexity of the SEE derivatives market and should at least initially be

45 It must be expected that traders will take positions in both the bilateral and PX short-

term markets and look for best trading opportunities in both. This will lead to convergence of prices in these markets.

46 Actually the supply/demand equilibrium for each trading interval one day ahead (or longer for bilateral contracts).


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avoided. We therefore assume a single reference price that typically is the so-called “unconstrained market clearing price” (UMCP) for the entire SEE market.

It is important to not confuse physical forwards contracts with financial derivatives contracts.

Physical forwards contracts are simply agreements of a future delivery of some commodity (e.g. electricity) at volume, price and delivery terms agreed in advance. As the name indicates, this implies obligation of delivery of the commodity. All long-term and short-term bilateral contracts traded in SEE and other places can be regarded physical forward contracts. Day-ahead market contracts as stipulated in the PX model proposed by the Consultants should also in this context be regarded as physical forwards (one day ahead).

Financial derivatives contracts, on the other hand, do not imply physical delivery of the commodity, but rather a cash exchange based on the price/cost of the underlying commodity. The term “delivery” and “delivery period” for a financial derivative is therefore somehow misleading, as it refers to the delivery of the underlying commodity and not the derivative itself (unless one want to think of “delivery” of cash over the settlement period).

A physical forward is therefore a guarantee for delivery of the commodity, while a financial Forward does not guarantee the physical commodity, but rather a guarantee on the price for the commodity – whichever way the buyer obtains the commodity. This difference is important with respect to e.g. scheduling and Clearing.

One working assumption is that most participants in the SEE electricity supply and distribution industry are risk averse in the sense they will prefer some degree of price security and are willing to pay a (small) premium to avoid high volatility.

The Consultants therefore assume that as the SEE electricity market becomes more competitive and efficient, one must expect:

increase in price uncertainty to short term electricity trading, which will introduce financial risk for the market participants

increased requirement for financial instruments to handle these risks, and

Increased requirement for a derivative market in SEE.

It is important to keep in mind the discussions provided in this report are mostly relevant in a scenario with an operating PX similar to the model proposed by the Consultants.

Derivatives will enable the SEE Regional Power Market participants to manage the price risk, which is the second largest risk in electricity business. They will be able to hedge against price risks as far as needed into the future. Along with derivatives the third largest risk – the counterpart risk – becomes manageable through the establishment of a clearing solution. Clearing services will reduce this risk to a minimum and allow the participants to concentrate on efficiency – which again results in cost reduction and optimized resource usage.


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9.14 Organization of the SEE Regional Power Market

9.14.1 The Power Exchange Concept

The SEE Regional Power Market organization must have flexibility and a structure to facilitate cooperation across Local borders. The SEE Regional Power Market will be the body for development of the regional market concept. This requires an organization of the market places that is able to include in the business process Local features and requirements adapted and harmonized to the regional concept. It is vital that regional agreements related to ownership, legal framework, localization and harmonization issues are developed in close cooperation between all the parties involved.

Figure 52 Power Exchange Concept

9.14.2 Organization and Supporting Roles

Ownership: In the first phase of the SEE Regional Power Market establishment it is vital that the TSOs in the region play an active part. The SEE Regional Power Market business processes will provide services for the TSOs and the TSOs will define framework for the exchange. The interest for both parties can best be executed by the TSOs taking an ownership of the implementation of the SEE Regional Power Market. This should be an option for all the TSOs in the region.

Ownership should also be open for LMOs in the region to ensure that framework for the SEE Regional Power Market is supported by all parties.

Strategic Partner: In the starting phase it will be recommended that an experienced market operator with competence regarding the market concept, market operation and market IT-

Other PX-1 TSO-1 TSO-nPX-n

SEE

Regional Market Service Provider

Market liquidity

Ownership

CAO Information

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Regional market:• Management• Price Calculation• Transparency

• Testing• Training

• Information• Documentation• Development

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Infrastructure is playing an active part in the process. It will shorten the time to market to have this support from an experienced partner.

SEE Service Provider: The service provider can deliver IT-Infrastructure and other services as distributing market information, training and technical IT-Infrastructure development in the region. It will be an advantage for the regional market development that this provider is located in the region. This will build competence and know how in the region and set a good platform for market evolution and development.

Coordinated Auction Office (CAO): Allocation of capacity for the exchange can be provided by an “Auction Office” as an entity running and coordinating services for the TSOs in the area. Please refer to previous chapter on CAO.

9.14.3 Ownership

The SEE Regional Power Marked should be organized in a flexible manner, which means that participating countries can choose the degree of decentralization from a branch office to a more decentralized link with the regional entity.

The question could be raised if a branch office establishment in each participating Local market is necessary. As an example the expanding regional reach of the German power exchange EEX (now part of EPEXSpot) could be used, where this exchange offers DAM services to both Austria and Switzerland without a local presence represented by a branch office or a similar service.

This is, however, an exchange operation that does not offer a market coupling or market splitting implicit auction of border capacities. The Austrian electricity market is fully integrated in the German bidding area, and no area price for Austria is ever quoted. In the case of Switzerland a totally separated DAM operation and a separate price (Swissix) is quoted on an hourly basis, operated by EEX as a separate instance.

In the Nordic market, Nord Pool Spot AS has established a subsidiary both in Finland and Sweden and a branch office operation in Denmark to take care of various activities linked to each Local market.

For the trilateral market coupling between France, Belgium and the Netherlands each Local market is being served by the Local power exchanges Powernext, BelPex and APX respectively.

Another example is the regional operation for the Iberian electricity market. The operation of the market has been divided between Portugal and Spain. A regional day-ahead market with implicit auction/market splitting is operated by Spain, while the trade in electricity derivatives is executed from Portugal. This ensures a local presence in both countries.

The SEE Local markets are characterized by:

Local regulatory framework to hold and operate a license

Different languages

Different degrees of maturity with reference to market development

The Consultant therefore strongly recommends, at least initially, a decentralized solution where at least a branch office is established in each local market performing as a minimum the following services:

Customer support in the bidding process

Arrange required training seminars in the Local language


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Sales and marketing of power exchange services

Settlement of DA contracts in cooperation with local banks

Providing all relevant market information in the Local languages securing full transparency

Figure 53 Regional Power Market

The flexibility with respect to participation in the regional exchange is illustrated in the figure above.

Centralized Market Operations

In this alternative no Local organization is required. All communication on market issues will be between the regional power exchange and Local market participants. It is assumed that Local authorities and the regional power exchange in most cases will prefer to establish a small unit (a branch office) to take care of marketing, communication with local authorities and general distribution of information.

For all participants the cash flow will be between the participants‟ accounts and an account owned by the regional power exchange.

This solution is not recommended for the SEE region at least in the short term.

National Market 1

National Market 2 National Market 3 National Market n

National PX National PX

centralized

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Partly De-centralized Market Operations

Partly de-centralization can include de-centralization of all tasks that can be characterized as service tasks and tasks that do not require any activities during holidays or stand-by arrangements.

The main tasks that remain as centralized operations are spot price calculations, operation of the trade system, and operation of the settlement system.

Also in this system all cash flow will be between the participants‟ accounts and an account owned by the regional power exchange.

The present Nord Pool model may be characterized as a “light partially de-centralized” model.

De-centralized Market Operations

In de-centralized market operations the participants will communicate with the Local power exchange in all daily operations. Monitoring of bids, control of trade notification, risk management and financial settlement of physical contracts will be carried out by the Local power exchange.

The LMOs must operate on all calendar days and have stand by arrangements.

The cash flow in the settlement will in this case probably be between the participants‟ accounts and an account owned by the Local power exchange in cooperation with a local bank.

There will be an additional settlement between the Local power exchange and the regional power exchange that involve the net trade surplus/deficit between the Local power exchange and the remaining part of the regional market. Hence in a de-centralized operation the risk management (calculation of collaterals, invoicing, settlement etc.) can be carried out separately for each jurisdiction.

Regarding ownership it must be underlined that the SEE Regional Power Market will, in its first mode of operation, only cover the physical short-term markets. This will be very closely linked to the TSOs real-time market operation.

It will be an advantage for the market development that the TSOs play an active part in setting the required framework. It is therefore recommended that the TSOs can execute this both through a direct ownership in the exchange and also as an active member on the board.

There may be Local markets that only require a small office dealing with market operations to maintain the required minimum communication with the Local market participants. This alternative is referred to as “centralized operation”.

It is assumed that most Local market will require some activities allocated to the Local level. This alternative is referred to as “partly de-centralized operations”.

In the fully de-centralized operation all activities that are possible to de-centralize are moved to the Local power exchange.

It is at this stage assumed that most of the Local markets within the SEE region will operate as decentralized markets. The Local markets will in this alternative to a large extent operate as an independent Local power exchange and interface the SEE Regional Power Market only in issues necessary to form one common regional market. This alternative is referred to as “de-centralized operations”.


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There is only one task that must be carried out on regional level:

Operation of the trade system: Calculation of unconstrained regional market clearing price and area prices in case of congestion and calculation of trade schedules for all regional participants.

Tasks that can be de-centralized are mainly:

Marketing on Local levels

Support and service to Local participants

Monitoring bid collections and validation of bids for both DAM and ID

Dispute Management for trade notifications

Financial settlement of traded contracts and risk management (collaterals)

Training of participants

Entry of new participants

Exit of participants

9.15 Legal issues

9.15.1 The Energy Act

The establishment of the SEE Regional Power Market requires support from the Local authorities in each jurisdiction.

The following items are of crucial importance in this context:

Unbundling of transmission and supply/generation.

Full transparency requirements regarding essential market data.

Allocation of all or part of the cross-border capacities to the Regional PX.

Details regarding operational procedures for the LMOs as well as the SEE Regional Power Market should be handled in close cooperation with the ECRB, the Local regulators and wholesale market participants, and not regulated in the Energy Act.

9.15.2 Legal infrastructure – required agreements

The figure below is displaying the required legal infrastructure.

The legal infrastructure will be harmonized and equal for all market participants, as illustrated in the figure below:


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Figure 54 Legal Infrastructure

With reference to the illustration above, the main agreements for market operation are:

Participation Agreement between participant and LMO

The SEE Regional Power Market - Local PX Agreements

The SEE Regional Power Market – TSO Agreement

LMOs -TSOs Agreement

The Participation Agreement

All market participants within SEE Regional Power Market area shall trade on equal terms. If there are minor differences in the rules between the Local markets these differences must be transparent and included in attachments to the regional spot rules.

However, the participant agreement is signed between the LMO and the market participants in its jurisdiction.

The agreement includes:

All detailed activities related to bidding, price determination, verification of trade schedules, and submission of trade schedules to TSOs.

Commitments by the parties related to collections and distribution of neutral market information.

Time line for all settlement activities of spot contracts and requirements regarding security amounts and accepted collateral types.

National market participants Participant of National TSO’s

Market Operation Grid and System Operation

TSO-1

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The above rules are often included in one agreement and referred to as Accession Agreement, Participation Agreement or The Rule Book for Spot.

The SEE Regional Power Market – Local PX Agreements

These agreements will vary depending on the degree of integration. In the most de-centralized alternative the agreement will include nearly all issues related to trade and financial settlement:

Careful specification of the share of responsibility between the SEE Regional Power Market and the LMO.

Full de-centralization will require a financial settlement between the LMOs and the SEE Regional Power Market. Rules for this settlement have to be defined in the agreement:

Format for bid-data

Procedures and timeline for submission of bid-data

The only process that will be fully centralized in all forms for integration is the process of price determination, calculation of trade schedules and distribution of neutral market information.

The Regional PX –TSOs Agreement and the LMO-TSO Agreement

The two agreements will cover much the same issues and may be replaced with one agreement between the parties: the SEE Regional Power Market, Local PX, TSOs.

The agreements regulate all mutual responsibilities and information flow between the SEE Regional Power Market and the respective TSOs. One identical agreement towards all interconnected TSOs is to be preferred. However, there will probably be required to diversify on some issues. This can be made in attachments for each TSO concerned incorporated in the agreement. Only one agreement with attachments for each TSO makes a transparent agreement where diversified rules are easy detected for all.

For all TSOs the agreement must include:

Daily reports to the Regional PX/LMOs on allocation of capacity on interconnections to be used for implicit auction. In the first phase of operation of the SEE Regional Power Market, only a part of the available capacity might be given to the exchanges for implicit auction, the remainder part might be offered on monthly and yearly capacity contracts for explicit auctioning.

Reports to the TSOs on traded spot contracts.

Acceptance of the principle of self dispatch of traded spot contracts.

The SEE Regional Power Market should serve as a platform for collection and distribution of relevant neutral market information. TSOs are important sources for such information. The agreement must include the parties‟ commitments in distribution of information.

Principles for collection and distribution of information

TSOs must consider traded DAM contracts as firm contracts that cannot be changed or curtailed after the trade is terminated. This means that contracts that is not delivered in the internal Local market is handled as imbalances by TSOs. Non-delivery caused by default on interconnections is managed by the TSOs involved in their respective balancing mechanisms.


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Management of imbalances caused by default in trade operations made at the SEE Regional Power Market.

Market Coupling Agreement

The SEE Regional Power Market will interface other independent regional or Local market in the same manner as for instance between the EEX and Nord Pool through EMCC.

9.15.3 Market Operation

Market operation is the daily operations and routines to determine the DAM and settle the market result. This includes interaction with all participants, balance responsible parties, TSOs, clearing services and banks. When the market is closing its operation on a trading day all the power and economical transactions have to be settled.

Agreements and detailed daily routines have to be specified and settled.

It will be the SEE Regional Power Market that will define the main body of the book of rules, daily routines and agree this with the system operators holding the different roles in the market area and the local variations will be maintained by the LMOs.

Even with a decentralized solution, the SEE Regional Power Market must set up the same framework for operation. Some of the regulatory issues will be handled locally by the LMO.

9.15.4 Interface to the TSOs

TSOs will have a role initially clearing new participants for trade in the DAM concerning meter values, agreement with a Balance Responsible Party and signing of necessary legal documents.

The interface to the TSOs will for the daily operation include the following tasks:

The TSOs submitting available capacity on the interconnections to the power exchange.

In the SEE region it will be set up a CAO (Coordinated Auction Office) in Montenegro, which intends to offer transfer capacities on Local borders explicitly and according to a flow-based method.

Facilitation of SEE Regional Power Market operations requires that the TSOs give some or all of the border capacity to the SEE Regional Power Market. The split of border capacity between the CAO and the SEE Regional Power Market should therefore be part of the interface arrangement with each TSO.

The SEE Regional Power Market delivering data for flow on the interconnections.

The participants‟ traded schedules.

The exchange of data will normally be based on xml-files and structured according to the ETSO standard.


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9.15.5 Settlement and Billing

This is the final settling of all the trades in the DAM. The settlement with calculation of the traded amounts and fees is a daily operation, while invoicing and billing should be open for configuration for a certain period.

To reduce requirements for collaterals, invoicing both for power and fees should be done on all open banking days.

Settlement and billing is a central operation calculating all the settlement data, while reporting, invoicing and credit checking can be a central or local operation.

Invoicing and billing require an electronic interface to the bank infrastructure sending a file with all billing instructions and receiving from the bank a file with the account balance.

Centralized Market Operations

For this solution all settlement operations, bank interfaces and credit checking is done centrally. The regional exchange must either set up an interface to a central bank that can handle all account transactions for all currencies or set up an interface to all local banks operating with participants‟ accounts in the market area. This requires that the exchange centrally holds all detailed information concerning the different local bank procedures.

Decentralized Market Operations

Basically this will include the same set of functions, but each branch office/LMO will normally handle the local bank interface either directly or using a local clearing house.

This is the recommended solution.

9.15.6 Transparency of relevant Market Data

Full transparency is a required part of the market reform whatever market design is chosen.

The number of participants at the power exchange, and traded volumes, can only grow if existing and potential members feel secure that all relevant market information is given to all participants at the same time and to the same cost.

As a minimum, real time access for all participants to prices, operational data, and grid maintenance information in the power market must be provided. In markets where hydro power constitutes a significant share in the energy mix, reservoir data should be provided. To further increase the transparency, frequent reports containing operational and physical market data as well as a statistical database could be developed.

To secure that relevant market information is provided to the market participants at the same time a system for short term information release must be developed. The information published in such a system is based on information provided by the system operators and the participants in each participating jurisdiction to the SEE Regional Power Market.

For the TSOs all aspects regarding disclosure of information should be regulated by a unified publication agreement between the various TSOs, the SEE Regional Power Market and the LMOs. For the market participants the regulation of information disclosure should be defined in the rulebook(s) for trading.

In order to reach all participants, the information tool should be available as a web based system of the SEE Regional Power Market with an interface for entering information and viewing information and data. All information must be displayed at least in English, but


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preferably also in the local language of the jurisdiction from where the information is originated.

The rule book must address routines for information disclosure in the market.

The information disclosure procedures must be addressed and harmonized in each local LMO‟s rule book.

9.15.7 Market Surveillance

The market surveillance function will in principle be identical independent of the choice of market design. Basically this is a centralized function operated by the Regional PX in a separate department, reporting not only to the top management of the exchange, but also to regulatory authorities in each of the member countries. The latter might require harmonization across the region and full compliance with EU directives related to market conduct.

To support the proposed market model for the DAM and to develop a well functioning exchange in terms of size, liquidity and transparency, the participants must have confidence in the markets price mechanism, its integrity and the market information transparency.

Market surveillance has an important role in establishing and maintaining this confidence and integrity by having a strong and visible presence in the market. Market surveillance continuously monitors the market conduct of trading participants, and investigates possible breaches of the trading rules or applicable laws.

The function will be operated as a separated entity connected to the SEE Regional Power Market. ECRB could be used for this purpose. The objectives will be to establish the department with the required rules, procedures and most importantly; sufficient authority given by the regulators in each of the countries allowing a well-functioning market surveillance role.

In addition, a local surveillance of the local LMOs must be in place. Also for this alternative the surveillance function will be managed by the local regulator with the same reporting requirements as for the centralized alternative.

The main tasks of the market surveillance will be to monitor nominations of each market participant and detect possible changes in bid “patterns”. Market surveillance must have access to nominations and check that market participants do not withhold market sensitive information. Handling of black outs, load shedding, force majeure etc. are regarded as operational issues and not subject to ordinary market surveillance issues.

9.15.8 Trade System

As previously discussed it will be vital for a Regional PX to implement a day-ahead system that in the first phase must facilitate the basic needs and have the features to adapt to future business requirements by use of configuration and system parameters. Proven technology, system modularity, parameterization and low costs is key factors that should be considered for a modern day-ahead market IT-System.

For both a branch office and a decentralized solution the trading system must hold the same functions, but implementation and functionality may differ for the two solutions.

This is an implementation were all data processing is done centrally, but includes functions that open up so LMOs or branch offices can handle interfaces to the participants, balance responsible parties, TSOs, clearing houses and local banks.


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10. ACTION PLAN

Based on the descriptions in the previous chapter, it is the Consultants clear recommendation that SEE has to merge to a regional electricity market producing a SEE regional reference price for energy.

10.1 Introduction

This chapter is a further update of the gap analysis now including both a regional action plan and a specific action plan for each contracting party, Bulgaria, and Romania.

10.2 Regional Action Plan

The regional action plan contains the following summary activities:

Review and Acceptance of Market Design

It is estimated that the review of the final report and the acceptance of the proposed market design for the SEE wholesale market can be completed by June 30th 2010

Project Establishment

Following the acceptance of the market design the regional project can be initiated with the following actions:

Select Regional Project Manager (PM)

Establish detailed project plan, budget, and financing plan for SEE Wholesale Electricity Market Opening project

Approve project plans, budget and financing

Appoint project members from each CP/Stakeholder to form the Regional Project Team

Arrange kick-off meeting at the end of August 2010

Regional Activities

It is recommended that the project is organized as part of the EC/Athens Forum process and that the PM reports status to ECRB/PHLG four times annually

Legal

A number of agreements have to be negotiated at the regional level. This will entail at least the following:

Agreement Regional Market Operator – Regulators for Contracting Parties

Agreement Regional Market Operator - TSOs for Contracting Parties

Agreement Regional Market Operator - Market Operators for Contracting Parties

The regional entity has been termed Regional Market Operator. This can be established as an agreement only between participating contracting parties. Alternatively a more formal legal entity can be incorporated being the legal counterparty to market operators in all Contracting Parties.


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Establish wholesale SEE regional market frameworks and detailed design

Based on the accepted SEE market design and relevant EU directives and regulations, the frameworks and detailed specification for the SEE regional market must be established

Coordinate project activities in Contracting Parties

The Regional Project will be responsible for coordinating the activities including the necessary harmonization of market and grid codes in each Contracting Party

Procurement/Implementation/Installations/Testing of Regional IT systems

This activity must be coordinated with a similar activity for each of the local markets.

Trials and Operations Regional DAM

Regional Market Trials must be run prior to going live with DAM trades. This will be a common activity involving the participating market operators and stakeholders in all the Contracting Parties, Bulgaria and Romania

Go Live SEE Regional Power Market (DAM)

It is stipulated that the Regional DAM can go live January 2012.

Physical/Financial Forward Electricity Market

As soon as a DAM price is established, financial electricity products should be offered in line with requirements from all local participants and international traders.

Figure 55 shows a detailed Gantt diagram for the regional project. The duration of this project will span from start–up in mid 2010 to the end of 2014.


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Figure 55.Gantt diagram for Regional Action Plan:


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10.3 Methodology to Establish Action Plans for Contracting parties, Bulgaria, and Romania

The methodology to establish these Action Plans is shown in the figure below.

Figure 56. Illustration of methodology to establish these Action Plans

First the minimum requirements for each jurisdiction to enter the open regional wholesale market are defined. The current status for all contracting parties plus Bulgaria and Romania is analysed for the areas of the minimum requirements. The Consultant‟s information on the current status was sent to regulators in each jurisdiction for verification.

The difference (gap) between the minimum requirements and the current situation is shown with traffic light symbols for each area.

Red colour indicates that there is a large gap and green colour indicates that there is no gap. Three alternatives in between red and green are used, as shown in figure above.

The gap analysis will form the basis for the development of the action plan for each jurisdiction, Bulgaria, and Romania.

10.4 Minimum Requirements

The following requirements are minimum requirements for each jurisdiction to participate in the open and harmonised regional wholesale market.

TSO unbundling

Functional and legal unbundling of TSO/ISO

Distance independent transmission tariffs established (point-of-connection or post-stamp tariff)

Albania

• TSO unbundling

• Supplier unbundling

• Eligibility

• Balance responsibility and balance mechanism

• Market concentration

• Transparency

• Establishment of DAM

Albania Albania Albania

CPs

Bulgaria

Romania

Current status

GAP

analysis

Large gap

No gap

Minimum requirements

Albania Albania Albania Albania

CPs

Bulgaria

Romania

Action Plans


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Supplier unbundling

Public Suppliers have fixed base load power contract terms, with Generator for tariff customers (not “Full supply” contracts)

Public Suppliers required to purchase rest of supply from DAM or bilaterally at market price

Plans are established to reduce contract volumes between Public Supplier and Generator

Eligibility

Large customers are legally eligible and a clear definition of eligibility criteria are established (Increasing number of eligible customers over time by decrease of threshold for eligibility)

It is practically possible for eligible customers to enter the market, i.e., necessary hourly metering, settlement and separate network tariff are established.

Strong incentive or mandatory for eligible customers to purchase on the open market

If not mandatory: Possible to offer base load contracts (fixed hourly power) to eligible customers on favourable tariffs (current level), but with a year by year reduction of contracted volumes

Balance responsibility and balance mechanism

Rules for balancing, hourly metering and settlement established for eligible customers, traders, suppliers and producers

Balance Responsible Parties (BPR) have to be assigned for each network connection

Market concentration

Size of 3 largest generators less than 50% of wholesale market capacity

Size of import/export capacity more than 20% of the incumbent‟s capacity in the market for each contracting party, Bulgaria and Romania

Transparency

Plan established to publish wholesale prices and make them easily available for market participants

Plan established to publish available cross border capacity and flows and make them easily available for market participants

Plan established to publish planned maintenance for generation and transmission and make them easily available for market participants

Plan established to publish generation and transmission outages (urgent market messages) and make them easily available for market participants

Establishment of regional DAM

There is a political support to establish a regional DAM

It is legally allowed to establish a DAM

The responsibility for establishing a DAM is given to the TSO or another designated party

It is legally allowed for the TSO to allocate cross-border transmission capacity to a DAM


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TSO to buy transmission losses from DAM to enhance liquidity

Responsibility for market monitoring given to the regulator in each Contracting Party, Bulgaria and Romania

Responsibility for market surveillance given to the market operator in each Contracting Party, Bulgaria, and Romania

10.5 Proposed General Decisions and Commitments

To comply with the minimum requirements listed above, some decisions might have to be taken depending on the stage of market opening the actual jurisdiction has reached.

The list of decisions will be tailor made for each jurisdiction within the following areas:

TSO Unbundling

Supplier Unbundling

Eligibility

Balance Responsibility and Balance Mechanism


Transparency


10.6 Template for the Action Plans

A template for the specific action plans has been designed, and is shown below

This template is applied when specifying for each jurisdiction its action plan in the following chapters.

Based on the gap analysis, these action plans will be adjusted, especially with respect to specifying some activities as completed or an estimated % complete.

The plan consists of five main sections (summary activities):

Legal, Market Structure, Establishment of DAM, Market Integration, Procurement/Implementation of the IT-System for the local Market Operator, and the Market Participants

Below each section and its sub-activities are described:


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Legal

Energy Act

An Energy Act is the key legal instrument for any market embarking upon a deregulation process of its local energy market. For all contracting parties in the Energy Community, and for Romania and Bulgaria, such an Energy Act is enacted and will form the basis for how each energy market will develop over the next decade.

The implementation of a regional electricity market for the SEE region might require some amendment to local legislation. An example of such necessary revision is the ongoing work in Serbia which is estimated to be completed in 2010.

Legal Revision of Eligibility Guidelines and Incentives

Securing liquidity in a marketplace is of paramount importance. Providing incentives for larger consumers, so-called eligible customers, to gradually transit to an open market is one necessary measure to attract volumes to a new Day-Ahead market-place. This is described below under the market structure section. It is also included under the legal section as it might require legal revision of terms either in the Energy Act or in decrees under the Energy Act.

Agreement Market Operator - TSO

Agreement Market Operator - Market Participant

Agreement Market Operator - Regional Market Operator

A number of agreements are required between new institutions as listed above.

Appoint Market Council in each jurisdiction

Appointing members from key stakeholders early on in the implementation process is important to enable sound advice in developing market procedures and products to be offered at the DAM.

Licensing of International Traders´

A requirement for establishing legal entities in each jurisdiction where an international

trader wants to participate is seen as a barrier for increased trade and liquidity, and such

requirement should be removed. A pan European incorporation ought to be facilitated.


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Market Structure

Unbundling of TSOs/Generation and unbundling of Supply/Generation are the key elements in introducing a market structure supporting a competitive wholesale market

Unbundling TSO/Generation

TSO to buy losses from DAM: Instructing TSOs to buy losses with price-independent bids from the DAM will contribute to increased liquidity when commencing trade in a regional day-ahead market.

Point of Connection Transmission Tariffs: DAM operation requires a point of connection tariff for both sellers and buyers. This implies that trading is independent of location and that the distance element in transmission tariffs is removed.

Balancing Responsible Parties/Balancing Mechanism: Market Participants are obliged to, either directly with the TSO or indirectly via another balance responsible party, maintain a balance between its commitments and resources made available. Imbalances will lead to a financial settlement based on a reference price equal to the day-ahead price

Unbundling Supply/Generation > 100.000 customers (Public Suppliers)

Design tariffs and volume reductions for transitional base load contracts

Implement transitional base load contracts

Another measure to enhance liquidity on the DAM is to give incentives to Public Suppliers to enter into a transitional scheme where volumes under regulated tariffs are gradually decreased year by year. These volumes are base load physical deliveries that need to be supplemented from the DAM to match the load profile each Public Supplier has towards its customers.

Unbundling Supply/Generation, Eligible Customers

Design tariffs and volume reductions for transitional base load contracts

Negotiate transitional base load contracts

A similar arrangement is envisaged for industrial customers, where incentives are offered for executing eligibility in transitional periods over some years where volumes from base load contracts are reduced

Establishment of local DAM

Detailed Market Design

Market Rules/Codes

Establish Procedures for Transparency

Establish Procedures for Market Monitoring/Surveillance


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Market Integration

Commitment to join regional market

Define allocation rules : ATC to Regional DAM for implicit auction

It is assumed that all contracting parties, Bulgaria, and Romania have made a commitment to be part of an integrated SEE electricity market

Facilitating an efficient cooperation requires optimal use of cross-border capacities between these parties. It is assumed that this will be taken care of in the ongoing CAO project. In the specific action plan it has been defined an activity where it is expected that clear allocation rules are established and that at least a major part of the ATC is allocated to the regional DAM operation.

Procurement/Implementation of IT-system for the local Market Operator

Procurement process

Implementation of IT-System

Acceptance testing

Training (workshops, market simulations, dry-runs etc.)

Operational organization start-up

Participate in Regional market Trials

The template is show below as a Gantt diagram.

It is important to note that the Gantt diagram displays duration in number of days for activities. It is not an indication of the required man-days to complete an activity


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Figure 57.Gantt Diagram for Action Plan Template.

Completed activities are marked as milestones per Jan 1st 2010 and with green text.


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10.7 Action Plans for Contracting Parties, Bulgaria, and Romania

10.8 Albania

10.8.1 Gap Analysis

TSO unbundling

Albania has established a legally unbundled and independent TSO (OST).

Distance independent transmission tariffs established.

KESH obliged to sell ancillary services and electricity to cover transmission losses to TSO at regulated price.

Supplier unbundling

A wholesale public supplier exists with the responsibility of buying electricity and to provide sufficient supply to the retail public supplier.

The retail public supplier sells electricity only to tariff customers, under terms and conditions approved by the regulator. Full supply contract.

The dominant generator, KESH Gen, is obliged to sell electricity to the wholesale public supplier at regulated prices. Full supply contract.

No plans are established to reduce contract volumes between Public Supplier and Generator.

Eligibility

All non-household customers can apply to become eligible.

Necessary hourly metering and settlement systems established for eligible customers.

Separate transmission and distribution tariffs for eligible customers are established for customers connected to the distribution network.

Regulated prices for the existing domestic hydro generation are below market prices, making it non-economical for customers to purchase on the open market.

Currently only 1 customer is exercising eligibility.


Hourly metering for large customers established.

Regulation for balancing mechanism decided.

Balancing mechanism is not yet implemented, expected to be implemented by end of 2010.


KESH stands for 99% of generation.

Between 60% and 70% of the demand was imported in 2007, but in general only 30-40% of the demand is imported.

Import capacity 40% of capacity of incumbent. (Data from 2007: Peak capacity 1 686 MW, Average import capacity 675 MW, incumbent 99%).


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Transparency

Wholesale prices for imported power are not published and easily made available for market participants.

Available cross border capacity and flows not published and easily made available for market participants.

Planned maintenance for generation and transmission are not published and easily made available for market participants.

Generation and transmission outages not published and easily made available for market participants.


There is a political support in Albania to establish a regional DAM.

The actual market rules need to be modified in order to authorize the TSO to allocate cross border transmission capacity to a DAM (local or regional).

There are no legal barriers to establish a DAM.

Responsibility for establishing a DAM not allocated.

Responsibility for market monitoring and surveillance not allocated.

10.8.2 Proposed Decisions and Commitments

TSO unbundling

No decision required.

Supplier unbundling

Abolish Full Supply contracts between KESH Gen and Public Supplier.

Replace Full Supply contracts with base load contracts gradually reduced year by year supplemented with DAM trade.

Eligibility

Cancel tariffs for eligible customers or offer eligible customers base load contracts at current tariff (level) gradually reduced year by year in a transitional period.


Make balancing responsibility mandatory for wholesale market participants.


Provide competition to the Incumbent by joining the regional SEE electricity market.

Transparency

Publish required wholesale market information and make the information easily available to market participants.


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Commit to join the regional DAM.

Instruct the TSO to establish the market operator.

Instruct the Regulator to organize market monitoring and surveillance functions.

Authorize the TSO to allocate cross border capacity to DAM for implicit auction.

Instruct the TSO to purchase main grid losses from DAM.


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Figure 58. Action Plan for Albania

Completed activities are marked as milestones 01.01.2010 and green text


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10.9 Bosnia and Herzegovina

10.9.1 Gap Analysis

TSO unbundling

Independent System Operator in Bosnia and Herzegovina (ISO BIH) operates the transmission system and balancing market is legally unbundled.

A single company for transmission, TRANSCO, of electricity in Bosnia and Herzegovina (Elektroprenos Bosne i Hercegovine, Banja Luka) is legally unbundled.

Distance independent grid tariffs established.

Transmission losses purchased by balancing responsible parties (BRPs). BPRs schedule (day ahead) additional MW(s) in order to cover for transmission losses. Based on the historical data (consumption/generation) ISO BiH determines the level of the additional MW(s) to be generated for each BRP.

Supplier unbundling

Utility in RS has legally unbundled generation from distribution and supply (not unbundling between distribution and supply).

Both utilities in FBiH are not yet legally unbundled.

Full Supply contracts between Public Supplier and Generator in all 3 utilities.

No plans are established to reduce contract volumes between Public Supplier and Generator.

Eligibility

All non-household customers can become eligible, but they can stay under regulated tariffs and no one executes eligibility.

It is practically possible for large eligible customers to enter the market, i.e., necessary hourly metering, settlement and separate network tariff are established.

Separate grid tariff has been established for customers connected to the distribution grid.

It is not economically interesting to purchase on the open market due to more favourable regulated prices.

One major customer, Aluminij JSC Mostar accounts for about 20% of total consumption and it obtained eligible status in 2007.


A balancing mechanism is in place (responsibility of the ISO).

In phase 1 of market opening only the three utilities are balance responsible parties (no other market participant may be a BRP). Each market participant will have to register and be represented by a BRP (signing a standard Balance Responsibility Contract).

Devices for hourly metering have been installed, but metering and settlement system and database are not fully implemented.


Three state owned utilities; EPBiH, EPRS and EPHZHB with 47%, 39% and 14% of generation respectively. Each company is a virtual monopoly within its geographical service territory.


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Import capacity 38% of capacity of incumbent. (Data from 2007: Peak capacity 3 781 MW, Average import capacity 1 455 MW, incumbents 100%. Data not confirmed)

Transparency

Wholesale prices are not published and easily made available for market participants.

ISO BIH publishes all available transfer capacities (ATC) on a monthly and daily basis. However cross border flows not published and easily made available for market participants.




There is political support to establish a regional DAM


There is no legal framework covering establishment of a DAM

The responsibility for establishing a DAM has not been allocated

Regulators (entity and state level as well) are responsible for market monitoring and surveillance


TSO unbundling

No decisions required.

Supplier unbundling

Abolish Full Supply contracts between incumbent Generator and Public Supplier.

Replace Full Supply contracts with base load contracts gradually reduced year by year supplemented with DAM trade.

Eligibility

Cancel tariffs for eligible customers or offer eligible customers base load contracts at current tariff (level). Contracted volumes to be gradually reduced year by year in a transitional period.


No decisions required, only IT systems for settlement lacking.


Import capacity sufficient to balance incumbents.

Transparency



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Adequate legal framework should be developed to establish the market operator.

Strengthen capacity of the Regulators in market monitoring and surveillance functions.




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Figure 59.Action Plan for Bosnia and Herzegovina

Completed activities are marked as milestones 01.01.2010


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10.10 Croatia

10.10.1 Gap Analysis

TSO unbundling

TSO (HEP Transmission Ltd) is legally unbundled but part of the HEP group.

The market operator (HROTE) is 100% state owned and legally unbundled. HROTE has responsibility for the adoption of market rules, organising the market and settlement of balancing energy.


HEP-GENCO is responsible for covering the transmission losses. TSO to buy losses is under consideration.

Supplier unbundling

Supply unbundled from distribution.

HEP Generation serves household customers through Suppliers. In 2011 the regulator will make a public procurement for all household customers for a five year period. One contract for the whole jurisdiction.

Eligibility

All non-household customers are eligible. They must buy on the open market.

Separate grid tariffs in distribution grids.

Necessary metering and settlement systems established for all non-household customers.

Since it is mandatory for all non-household customers these customers can not resort to a more favourable regulated tariff.


Rules for balancing, metering and settlement established, but some changes are required to make balancing market efficient.

Hourly metering or load profiles are used.


HEP stands for 90% of generation and supplies all tariff customers

Import capacity 60% of capacity of incumbent. (Average import capacity 2 400 MW, Capacity of incumbents 4 000 MW)

Transparency

Wholesale prices are not published and easily made available for market participants

Available cross border capacity published and easily made available for market participants. Flows not published and easily made available for market participants

Planned maintenance for generation and transmission are not published and easily made available for market participants



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There is a political support to establish a regional DAM


It is legally allowed to establish a DAM

The responsibility for establishing a DAM has not been allocated

Responsibility for market monitoring and surveillance has been allocated to HROTE and HERA


TSO unbundling


Supplier unbundling

Abolish Full Supply contracts between HEP Generator and Public Supplier

Eligibility

In order to exercise eligibility and promote liquidity in the local DAM, the Consultant recommends that contracted volumes should be gradually reduced year by year in a transitional period.


No decisions required, but mechanisms need to be improved.


Provide increased competition for HEP Generation by joining the regional SEE market.

Transparency






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Figure 60.Action Plan for Croatia



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10.11 FYR of Macedonia


TSO unbundling

The TSO and market operator (MEPSO) are legally unbundled.

Distance independent transmission tariffs established (post-stamp tariff).

Supplier unbundling

Distribution company (EVN) ownership unbundled (owned by Austrian utility EVN - 90% and 10% -state owned)

Full supply contract between generator (ELEM) and distributor (EVN). EVN, as a supplier, can purchase from other producers and/or traders if the market conditions and price are more favourable than from the regulated generator. The purchase by EVN will be made on transparent, non discriminatory and market based principles. EVN, as DSO, purchase electricity on the open market to cover losses above approved levels (11%) by the regulator.

Plans to reduce contract volumes between Public Supplier (EVN) and Generator (ELEM) will be established with the changes of the Energy Law.

Eligibility

It is practically possible for eligible customers to enter the market

All customers connected on 110 kV level are eligible (mandatory). 9 eligible customers representing 30% of the market in 2008. Next steps for liberalisation of the electricity market are envisaged within the Action plan for further implementation of the EU acquits, adopted by the Government of the Republic of Macedonia

Necessary hourly metering and settlement systems for eligible customers are established

It is mandatory for eligible customers to purchase on the market


Balancing mechanism under establishment. Will be included in new Market Code which is expected to be approved by the Energy Regulatory Commission in March 2010.

Necessary hourly metering for eligible customers are established.


Two state owned generators, ELEM (with 2 TPP coal-fired and 7 HPP) and Negotino (with fuel oil fired generation). Market size of these two generators around 90%.

Seven of the small HPP are operated by a private entity Makhydro Proekt under the Rehabilitation Operation and Transfer (ROT) Model.

Import of electricity was about 32 % of demand in 2008.

Import capacity 27% of capacity of incumbent. (Data from 2007: Peak capacity 1 557 MW, Average import capacity 375 MW, incumbents 90%)

New interconnectors to Serbia have started with preparation in 2009 and there have also been discussions about a new line to Albania


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Transparency

Regulated prices are approved and published by the Regulator. Yearly average prices by trader are published in yearly reports.

Available cross border capacities and flows are published and easily made available for market participants. Cross border allocation of capacities is performed on each border. On the interconnections with Greece, Serbia and Bulgaria there is dividing of capacity (NTC) in 50:50 and applying explicit auction on the FYR of Macedonia part of the capacity. There is no reserved capacity for the supplier of electricity of tariff consumers through already given capacity (AAC). The rules for allocation of capacities on FYR of Macedonia-Greece, FYR of Macedonia - Serbian and FYR of Macedonia-Bulgarian borders are announced on the web – page of JSC MEPSO, as well as the results of auction.

Planned maintenance for generation are not published and easily made available for market participants. MEPSO published Plan for maintenance schedule for transmission for 2009 available on the web site: www.mepso.com.mk

Generation and transmission outages not published directly to market participants, but in media.


There is a political support to establish a regional DAM. Republic of Macedonia is contracting party of the Energy Community Treaty and generally supports initiatives and projects that lead to establishment of the regional energy markets and particularly electricity markets. In this respect the Government of the Republic of Macedonia has supported the establishment of Coordinated Auction Office in South East Europe. In Republic of Macedonia currently is implemented broad programme for further liberalisation of electricity markets which leads to further implementing the acquis in electricity. This also takes into account responsibilities and obligation of the TSO and DSO and the generators and suppliers as well. Also the attention is focused on the Energy Regulatory Commission and its tasks in market monitoring.

It is allowed for TSO to allocate cross-border transmission capacity to a DAM.

It is legally allowed to establish a DAM.

The responsibility for establishing a DAM has been allocated.

Responsibility for market monitoring and surveillance has been allocated.


TSO unbundling

No decisions required

Supplier unbundling

Abolish Full Supply contracts between incumbent Generator and Public Supplier

Replace Full Supply contracts with base load contracts. Contracted volumes gradually reduced year by year supplemented with DAM trade.

Eligibility

In order to exercise eligibility and promote liquidity in the local DAM, the Consultant recommends that contracted volumes should be gradually reduced year by year in a transitional period

http://www.mepso.com.mk/


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Will be in place by mid 2010.


Provide increased competition to the Incumbent by joining the regional SEE market.

Transparency




MEPSO established.




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Figure 61.Action Plan for FYR of Macedonia



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10.12 Montenegro


TSO unbundling

TSO is legally unbundled from EPCG (national electricity utility) and exists as a separate joint venture company

Distance independent transmission tariffs are established. The decision on regulatory revenue of TSO is done in completely separate process from the tariffs for EPCG

Supplier unbundling

Distribution functionally unbundled from Supply within EPCG.

EPCG is at the same time Public Supplier, no supply/generation unbundling

Eligibility

All non-household customers are formally eligible, but there is only one supplier. Traders do not have access to the final customers because they need to obtain supply licence.

Regulator issued one more supply licence to some private company, but they do not operate yet.

One large consumer, an aluminium factory, will be fully exposed to market prices in 2010. The latest decisions of the Agency provide for market opening for all eligible customers, including largest consumers, but there is still no one supplier that operates in Montenegro at the moment (except EPCG)

Distribution tariffs are presented as part of tariffs for EPCG, but part of the tariff for use of distribution network and part for losses in distribution are clearly separated from the other tariffs for EPCG


According to the Market Rules the balancing responsibility is established. Balancing mechanism is also established through the Market Rules, but balancing price is not established yet.

Hourly metering is in place to serve the wholesale market (invoicing of trade and imbalances)


The state owned power company (EPCG) holds 100% of the production capacity.

Import covered 40% of consumption in 2007.

A new 400kV power line between Montenegro and Albania is expected to be in operation in 2010.


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Transparency

As there is just one operational supplier at the moment (EPCG), it purchases electricity according to Public Procurement Law. The results (both amounts and prices) are published, but usually through the newspaper and other unofficial ways. This is because there is no real market, so EPCG purchases electricity on one single tender for the whole year.

Available cross border capacities and flows (real time) are published on the web site of TSO: http://www.tso-epcg.com/.


Generation and transmission outages not published, but market participants can get the information easily from the operators.


There is a political support to establish a regional DAM.

It will be legally allowed for the TSO to allocate cross-border transmission capacity to a DAM as soon as the decision to establish a DAM is taken.


The responsibility for establishing a DAM has been allocated to the Market Operator

Regulator is responsible for market monitoring, but responsibility for market surveillance is not allocated. Although surveillance is not defined as a specific task, monitoring covers it as well.


TSO unbundling


Supplier unbundling

Unbundling of supply and generation functions within EPCG.

Establish base load contracts, reduced year by year, between supply function and generation function within EPCG.

Eligibility

Cancel tariffs for eligible customers or offer eligible customers base load contracts at current tariff (level). Contracted volumes to be gradually reduced year by year in a transitional period.


Establish balancing prices in accordance with Market Rules. (planned to be done 2010)


Provide competition to EPCG by joining an organized future regional SEE market.

Transparency



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Instruct the Regulator to organize market surveillance functions.



215



Figure 62.Action Plan for Montenegro



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10.13 Serbia


TSO unbundling

TSO (PE EMS) is totally (legally, financially, functionally, ownership) unbundled.


Supplier unbundling

In Serbia a hybrid market exists consisting of two segments- regulated market and competitive market.

EPS – Trading (under its license for wholesale trade for tariff customers) serves the tariff customers (regulated segment of the market) and has a 95% market share on the wholesale level. EPS (under its license for trade on the free market) and 30 actively participating and obtained EIC code traders are players on the free segment of the market, covering the remaining 5% of the wholesale trade. On the retail level, EPS subsidiaries (operating under PSO) licensed for supply of tariff customers are serving 100% of the market, since no potentially eligible customer switched to the free market due to the fact that regulated prices are lower than the market prices.

EPS generation has full supply contracts with EPS Trading. EPS Trading holds two licenses- for wholesale trade for tariff customers and for trade on free market (includes both wholesale and retail trade, import and export)

The draft amendments to the Energy Law envisage abolition of the right of eligible customers to be supplied under regulated tariffs. If those amendments are adopted, this would lead to reducing contract volumes between Public Wholesale trader for tariff customers (EPS – Trading) and Public retail trader for tariff customers (EPS Supply), relieving thereby significant part of EPS generation which will be directed to the free segment of the market

Eligibility

All non-household customers are eligible, giving a formal market opening of 47%. No one executes its eligibility. 2.4 TWh (10% of total consumption) is directly connected to the transmission grid.

Hourly metering and settlement systems for large customers connected to the transmission system are in place. Customers on distribution level are not metered on hourly basis.

All customers have access to regulated tariffs, which are currently below cost- reflective level.


The market model which is being implemented includes a balancing mechanism, but the balancing mechanism is not yet in place

Today, hourly metering in Serbia is available from all points of connection to transmission grid. Metering data from all these points are aggregated per entity and sent automatically to Market Settlement System, which calculates imbalance of each BRP (Balance Responsible Party). At the moment balancing responsibility is not yet put in place in Serbia and there is no single eligible customer on transmission, as well as on distribution grid in Serbia, so there is no need for distribution utility to send hourly metering of such customers to Market Operator (PE EMS). At the moment there are no links established from distribution utilities to Market Operator dedicated for sending of


217



hourly metering and it is not mandatory by energy law, energy delivery directive, tariff system and distribution code installation of load profile meters for the large customers on distribution grid. With appearance of eligible customers on distribution level, this link must be established and load profile metering should be introduced in such places. Otherwise, utility must profile customer consumption in order to send to Market operator hourly values, which consequently will engage some level of inaccuracy within the settlement process.


State owned PE EPS holds 100% of generation. (Generation separated into 5 generation companies within PE EPS.)

High technical import/export capacity around 2 000 MW

Transparency

Wholesale prices are not published, as there is currently no open wholesale market.

Available cross border capacity and flows are published and easily made available for market participants via PE EMS web site.

Planned maintenance for transmission are published and easily made available for market participants via PE EMS web site.

Generation and transmission outages not published and easily made available for market participants. Transmission outages will be published and easily made available for market participants in 2010.


There is a political support to establish a Serbian power exchange and couple it with the neighbouring markets.

It is legally allowed for the TSO to allocate cross-border transmission capacity to a DAM.

It is legally allowed to establish a local DAM.

The responsibility for establishing a local DAM has been allocated to TSO (EMS).

Responsibility for market monitoring and surveillance in relation to the DAM has been allocated to AERS and market surveillance will be given to JP EMS.


TSO unbundling


Supplier unbundling

Replace full supply contracts between EPS Generation and EPS Trading (under its license for wholesale trade for tariff customers) with base load contracts gradually reduced year by year. Supplementary volumes from future DAM.

Eligibility

Cancel regulated tariffs at first for those eligible customers connected to transmission network, afterwards for those connected to distribution network.


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Define a timetable for implementation of hourly meters in distribution network.

Develop load profiles for non-hourly metered customers in distribution network within the transitional period of implementation of hourly meters.



Transparency

Publish wholesale market information required by transparency guidelines and make the information easily available to market participants.


Establish the local DAM (power exchange).

Define the means of market monitoring and surveillance functions in primary and secondary legislation.

Define how the TSO will allocate cross border capacity to DAM for implicit auction.

Examine the possibility for the TSO to purchase main grid losses from DAM.


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Figure 63.Action Plan for Serbia



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10.14 UNMIK


TSO unbundling

Legally unbundled TSO (KOSTT) established.


Supplier unbundling

Supplier (KEK Supply) buys from producers (mainly KEK Generation) and traders

No plans are established to reduce contract volumes between Public Supplier (KEK Supply) and Generator (KEK Generation).

In 2009, a decision was taken for legal unbundling of distribution, supply and trade from “KEK” J.Sc. The separate company called “DISCO” was established. It‟s expecting that during the year 2010 the DISCO will be fully functional as legal unbundle company with three core license activity: distribution, supply and trade. Public supply functions will be handled by DISCO. The process of privatization of this company is in preparation. Contractual commitments how to serve Tariff Customers (full supply etc.) will be part of these negotiations.

Eligibility

Customers connected at the 10 kV level or above are eligible. Currently two customers are declared eligible

From August 2009 all the non-household customers have the right to obtain the eligible status.

Practical possibilities for eligible customers to enter the market are being developed. To be met by end of 2010.

Eligible customers have the right to be supplied by the supplier of their choice with unregulated prices (contracted) or by public suppliers with regulated price.


Balancing mechanism under establishment and will define which entities will have balancing responsibility.

According to transitional Market Rules, Public Supplier is the only supplier and BRP.

There are no obstacles in legislation of entering of the new suppliers in the market.

Hourly metering and settlement is already done.


KEK stands for 98% of the generation

Main part of KEK generation sold to KEK Supply.

Net import of electricity was 9 % of demand in 2008

The import capacity constitutes more than 43% of the installed generation capacity of the incumbent. Reduced during summer season due to low load and high local generation


221



Transparency

Wholesale prices are not published and easily made available for market participants. Most of the energy on the wholesale level is supplied through regulated prices and these are publicly available.




There is a local support for establishing a regional DAM

Currently the TSO does not allocate the cross-border transmission capacities

There is no legal barriers for the TSO to establish a PX

It is legally allowed to establish a DAM. Establishment of a balancing market is prioritized over establishment of a DAM due to few potential participants at a local DAM.

Market Operator has the responsibility for proposing market design and DAM to ERO. Regulator has the responsibility for market monitoring and surveillance.


TSO unbundling


Supplier unbundling

Supplier and Distribution are unbundled from KEK J.Sc. (generation and mining). They are in process of privatization. The new contracts have to take into consideration the issue of abolishment of full supply contracts and reduction of volumes over time. Pending from privatization package.

Eligibility

Currently the volume contract between eligible customers and Public Suppler are sealed by privatization contract. It‟s expected that after ending this contract and after the privatization of Public Supplier, the new contract will be “base load contract” and this will be required also for coming new suppliers into market.


It is expected that the amended “Market Rules” will define clear balancing responsibility mandatory for wholesale market participants.


Provide competition to the Incumbent by joining the regional SEE market.

Transparency

ERO is authorized by law, and will force the licensee for transparency. It is expected that the wholesale market information will be published soon, by 2010.


222




Energy Regulatory Office has granted license for Market Operator (MO) to KOSTT (Transmission System and Market Operator). The MO is in charge to functionalize market including the DAM.

By functioning of DAM, ERO will instruct TSO to purchase losses from DAM.


223



Figure 64.Action Plan for UNMIK



224



10.15 Bulgaria


TSO unbundling

Legally unbundled TSO.

Distance independent transmission tariffs established (post-stamp tariff).

Supplier unbundling

Plans are established to reduce contract volumes between Public Supplier and Generator.

Eligibility

All customers formally eligible.

Large and medium sized customers exercising eligibility.

It is practically possible for eligible customers to enter the market, i.e. necessary metering and settlement established.

Separate grid tariffs for customers connected to the distribution grid established.


Balance mechanism, metering and settlement established.


State owned utility NEK with small share of generation.

Import capacity 12% of capacity of incumbent. (Data from 2008: Peak capacity 17 034 MW, Average import capacity 1 275 MW, incumbents 100%).

Transparency

Wholesale prices are not published and easily made available for market participants.

Available cross border capacity and flows published and easily made available for market participants.

Planned maintenance for generation and transmission are published and easily made available for market participants.

Generation and transmission outages published and easily made available for market participants.



It is legally allowed for the TSO to allocate cross-border transmission capacity to a DAM.


The responsibility for establishing a DAM has not been allocated.

Responsibility for market monitoring and surveillance has not been allocated.


225




TSO unbundling


Supplier unbundling

Required decisions depend on status to be reported.

Eligibility



No decision required.


Provide increased competition to the Incumbent by joining the regional SEE market.

Transparency




Instruct the TSO to establish the local market operator.

Instruct the Regulator to organize market monitoring and surveillance functions.




226



Figure 65.Action Plan for Bulgaria



227



10.16 Romania


TSO unbundling

TSO legally unbundled.


Supplier unbundling

DSOs with more than 100 000 customers are legally unbundled from the suppliers.

Eligibility

All customers eligible.

Mostly large and medium size industries exercise eligibility.

It is practically possible for eligible customers to enter the market, i.e., necessary metering and settlement established.

Separate grid tariffs for customers connected to the distribution grid established.


Balancing mechanism established.

Hourly metering available for participants on the Balancing market.


Size of 3 largest generators 49,8%.

There are 8 generating companies with at least 5% share of the installed generation capacity in the jurisdiction.

Import capacity 36% of capacity of incumbent. (Incumbents capacity 6 274 MW, Average import capacity 2 250 MW).

Transparency

Wholesale prices are published and easily made available for market participants.

Available cross border capacity and flows published and easily made available for market participants.

Planned maintenance for generation and transmission are published and easily made available for market participants.

Generation and transmission outages published and easily made available for market participants.



A national DAM (OPCOM) is established.

Responsibility for market monitoring and surveillance given to national regulators and national market operator.


228




TSO unbundling


Supplier unbundling


Eligibility



No decision required


Provide increased competition to national Incumbent by joining the regional SEE market

Transparency

Increased transparency and the publication of all the data required


Commit to join the regional DAM

Authorize the TSO to allocate cross border capacity to DAM for implicit auction

Instruct the TSO to purchase main grid losses from DAM


229



Figure 66.Action Plan for Romania



230



10.17 Ukraine


TSO unbundling

TSO (Ukrenergo) is totally (legally, financially, functionally) unbundled.

Distance independent transmission tariffs established, but it is embedded as part of the Wholesale Market Price

Supplier unbundling

Currently Ukraine has a Single Buyer market where Energorynok is functioning as the single buyer of all electricity that covers for most of the market

The Ministry is currently working on an amendment to the law to allow for a market based solution; first based on a bilateral market and then a DAM.

Eligibility

All customers can choose supplier according to the law

There is no definition or criteria of an eligible consumer in the law.

The change for a more market based solution will help as well as creating a clear provision of the eligible consumer in the law


The only entity that is responsible for ensuring physical balance is the TSO, Ukrenergo

Balance responsibility is not implemented fully, but all generators in the competitive market (TPPs) is exposed to penalties in case of deviation from planned volumes of generation

There are plans for a balancing mechanism/market that is under consideration and also covered by the ongoing work on the amendment of the energy law.

This will require that Balance Responsibility will be implemented on a wider base

There is no Balance Responsible Parties assigned for each network connection

Legal requirement for hourly metering for consumers with equipment of more than 150 kw and consumption of more than 50.000kwh per month.


231




NPP (Atomenergo47) delivers 49% of production

The state owned hydro company (Ukrgidroenergo) and the 5 TPPs (Dniproenergo, Donbasenergo, Zahidenergo, Tsentrenergo, Skhidenergo) covers for an additional 45% of the total production

There are more than 140 companies with generation license and 94 that are active on a daily basis

Already 550 MW connected to ENTSO-E

Ukraine has many interconnections to both ENTSO-E countries as well as to UPS/IPS countries

Transparency

Wholesale prices are published on a daily basis on the Energorynok website.

Available cross border capacity and flows are published and easily made available for market participants via Ukrenergo web site.

Planned maintenance for transmission are not publicly easy available, only through the ministry.

Generation and transmission outages are not published and easily made available for market participants. This is only in-house information within Ukrenergo.


There is a political support to establish a Ukrainian energy market and couple it with the neighbouring markets.

Currently Energorynok is established as the market operator for the WEM.

It is not legally allowed to establish a national DAM in line with the principles from the SEE RDAM.

Responsibility for market monitoring is currently established as a division within NERC and Energorynok.

To be able to fully participate in the SEE Regional market, Ukraine has to be synchronised with the ENTSO-E area. This is currently not in place.

There is a pre-feasibility study that just has started lead by ENTSO-E and the operational manager of the project is Transelectrica.

This pre-feasibility study has an expected duration of 2-2,5 years and the project has an expected timeframe of 7,5 years

47 Atomenergo also owns two HPPs: Tashlytska (Pumped storage) and Oleksandrivska

(storage hydro) as well as one wind farm: Donuzlavska


232




TSO unbundling


Supplier unbundling

Follow the plans of establishing a more competitive market solution starting with a bilateral market followed by establishing of a DAM

Eligibility

Establish clear criteria for eligibility as well as incentives for participants to become eligible

Create a clear roadmap for removing the regulated tariffs and expose the participants to the real price for electricity

Create a support scheme for vulnerable customers in line with the market model



Implement a Balancing market as planned.

Define a timetable for implementation of hourly meters in distribution network.

Develop load profiles for non-hourly metered customers in distribution network within the transitional period of implementation of hourly meters.



Transparency

Publish wholesale market information required by transparency guidelines and make the information easily available to market participants.


Establish/decide on the organisation that shall establish the local DAM (market operator).

Do the required changes to the energy law

Follow up and accelerate the project for ENTSO-E synchronisation

Start the work on creating a common market with Moldova


Future


Examine the possibility for the TSO to purchase main grid losses from DAM.


233



10.17.3 Action Plan for Ukraine

To be created under the current work by ECRB/ENTSO-E working group.

10.17.4 ENTSO-E synchronization

Ukraine as a country is currently not synchronous connected to ENTSO-E, but to the UPS/IPS region. However, one part named Western Ukraine, is currently synchronous with ENTSO-E. This region has a total installed capacity of 2,53 GW and have interconnections to Hungary, Slovakia, Romania and Poland. Details on these are found in the table in section Error! Reference source not found..

To fully participate in and utilize the SEE regional market it is vital that the rest of Ukraine will be connected to ENTSO-E. There is currently a project called “Extending the ENTSO-E synchronous zone by integration of Ukrainian and Moldovan Power Systems” where a pre-feasibility study on the inclusion of both Ukraine and Moldova to ENTSO-E is developed. This project is lead by Transelectrica from Romania.

This prefeasibility study is expected to be finalized within 36 months and based on this, an implementation plan will be created. With reference to the ECRB Annual Report of September 1st 2011, the expectation is a total project period of 7,5 years.


234



10.18 Moldova


TSO unbundling

TSO (Moldelectrica) is totally (legally, financially, functionally) unbundled.


Supplier unbundling

There are 2 state-owned public suppliers (RED Nord and RED Nord-Vest) and one private owned (RED Union Fenosa) that act as suppliers and one active private eligible customer (Cement factory)

There is one active supplier on non/regulated tariffs (Energocom)

All 3 suppliers at regulated tariffs and the active eligible customer have to buy priority generation from the 4 Moldavian generators (CHP CHISINAU 1, CHP CHISINAU 2, CHP NORD and HPP Costeshti) at regulated tariffs

The rest of their requirement has to be bought on non-regulated tariffs

In 2013, supply and distribution shall be unbundled as well according to the law

Eligibility

There is a special regulation that opens for eligible consumers. Currently there are 3 customers that has been nominated as ECs and there is one that exercises his eligibility (Cement) factory.

From 2013 all non-household customers will be eligible.

From 2015 all customers including households will be eligible.

Hourly metering and settlement systems for large customers connected to the transmission system are in place.

The ECs buys their electricity on the same basis as the other suppliers, i.e. they buy from the Moldavian generators at a regulated tariff and then buys the rest from other sources at non-regulated prices.


Rules for balancing, hourly metering and settlement established for eligible customers, suppliers and producers are in principle in place

However, all balancing services is bought from Ukraine at present

TSO does not have the possibility to earn or collect money from participants and it is only managing/dispatching the transmission network

The suppliers and the EC are Balance Responsible Parties


235




There is a very dominant generator in Transnistria, “Moldavscaya GRES”. It covers 70% of the need of Moldova

Looking at Moldova excluding generation from Transnistria, there are 4 generators (CHP CHISINAU 1, CHP CHISINAU 2, CHP NORD and HPP Costeshti) where CHP CHISINAU 2 has 64 % of the installed capacity.

However, the import capacity from Ukraine acts as a competitor to the “Moldavscaya GRES” generator

Transparency

As there is no wholesale market in place in Moldova, there are no wholesale prices published

Available cross border capacity and flows are not published and easily made available for market participants.

Planned maintenance for transmission are published and easily made available for market participants in a daily conference call arranged by the TSO.


A draft for transposing the transparency requirements as set out in the EC regulation 1228 is under finalisation


There is a political support to establish a Moldavian market and couple it with the neighboring markets.

There is a current amendment to the electricity law that also covers congestion management through organized capacity allocations. The draft of ANRE regulations contains auctions in line with the EC regulation 1228

Responsibility for market monitoring is given to ANRE.

To be able to fully participate in the SEE Regional market, Moldova has to be synchronized with the ENTSO-E area. This is currently not in place.

There is a pre-feasibility study that just has started lead by ENTSO-E and the operational manager of the project is Transelectrica.

This project has an expected duration of 2-2,5 years

Following this, there will be an implementation phase. This will of course be depending on the results of the pre-feasibility study, but it is expected that this phase will require another 3-4 years before Ukraine can be connected.

This project is a common project for inclusion of both Ukraine and Moldova.


236




TSO unbundling


Supplier unbundling

Follow the current roadmap and monitor the progress.

Eligibility

Follow the current roadmap and monitor the progress.


Change to allow for Moldelectrica to become a fully operational TSO with the balance responsibility for Moldova.

Improve the national balancing mechanism

Make balancing responsibility mandatory for all wholesale market participants.



Transparency

Promote the draft amendment of the electricity law and ANRE regulations for transposing the EU regulation 1228 for transparency guidelines in order to publish the information required and make the information easily available for the market participants.


Follow the current roadmap for Moldova to establish a internal market integrated into a regional market

Start the work on creating a possible common market with Ukraine until the ENTSO-E synchronization is implemented.

Follow up and accelerate the project for ENTSO-E synchronization by one of the options discussed below

Future



Examine the possibilities for covering transmission network losses from DAM.


237 PÖYRY MANAGEMENT CONSULTING


10.18.3 Action Plan for Moldova To be created under the current work by ECRB/ENTSO-E working group.

10.18.4 ENTSO-E synchronization

Moldova as a country is currently not synchronous connected to ENTSO-E, but to the UPS/IPS region.

To fully participate in and utilize the SEE regional market it is vital that Moldova will be connected to ENTSO-E. There is currently a project called “Extending the ENTSO-E synchronous zone by integration of Ukrainian and Moldovan Power Systems” where a pre-feasibility study on the inclusion of both Ukraine and Moldova to ENTSO-E is developed. This project is lead by Transelectrica from Romania.

This prefeasibility study is expected to be finalized within 36 months and based on this, an implementation plan will be created. With reference to the ECRB Annual Report of September 1st 2011, the expectation is a total project period of 7,5 years.

However, in Moldova there have been arguments for that Moldova should start the integration process themselves and connect to Romania. Based on a statement from the Moldova‟s Deputy Minister of Economy Illarion Popa in the media in mid September48, 2011, a debate on this issue has been raised.

In general, the fear is that it might take a very long time and that Moldova will be dependent on the development in Ukraine for its own development of the energy market and European integration. The Deputy Minister stated that a project for Moldova alone would only take 3-5 years and that a common project with Ukraine will take 15-20 years.

It is therefore the recommendation from the Consultants that alternative routes for Moldova is explored.

In general, there are three different options that are possible:

1. Follow the current common project with Ukraine and be connected to ENTSO-E together with Ukraine

2. Do a smaller pre-feasibility study where only Moldova is connected to ENTSO-E through Romania

3. Do a common pre-feasibility study where Moldova is connected to ENTSO-E

through Romania and Western Ukraine (that is already connected to ENTSO-E)

The current position is to follow option one. However, as Ukraine is a large country and the

implementation project is foreseen to be complicated and thereby long, one of the two

other options could be better for a faster integration for Moldova. This will require much

smaller pre-feasibility studies and also shorter implementation projects. As the Consultants

have understood, EBRD have already supported the high-voltage power line Balti-Suceava

financially. This will enable Moldova to connect faster to ENTSO-E through Romania and

diversify its dependencies on Ukraine and Transnistria.

48 Reported in several media, two references are

http://euroatlantica.info/index.php?id=4640 and http://www.kommersant.md/node/4710

http://euroatlantica.info/index.php?id=4640

http://www.kommersant.md/node/4710




The various options have been discussed in a report49 and it is the recommendation from

the Consultants to investigate if any of the option 2 or 3 is viable.

10.18.5 Transnistria

There is a region in Moldova that has claimed independence from Moldova. This is also the location of the large thermal power plant MGRES. For electricity production, Transnistria is managed as an external country/region the same way as for Ukraine and is in most cases directly competing with Ukraine for supply of electricity for the rest of Moldova.

This is a description of the background of this region (source Wikipedia):

Transnistria is a breakaway territory located mostly on a strip of land between the Dniester River and the eastern Moldovan border to Ukraine. Since its declaration of independence in 1990, and especially after the War of Transnistria in 1992, it is governed as the Pridnestrovian Moldavian Republic (PMR, also known as "Pridnestrovie"), an unrecognized state which claims the territory to the east of the river Dniester, the city of Bender and its surrounding localities located on the west bank. The Republic of Moldova does not recognize the secession and considers territories controlled by the PMR to be part of Moldova's autonomous region of Stînga Nistrului ("Left Bank of the Dniester").

After the dissolution of the USSR, tensions between the Moldovan government and the breakaway unrecognized state's authorities in Tiraspol escalated into a military conflict that started in March 1992 and was concluded by a ceasefire in July 1992. As part of that agreement, a three-party (Russia, Moldova, Transnistria) Joint Control Commission supervises the security arrangements in the demilitarized zone, comprising 20 localities on both sides of the river. Although the ceasefire has held, the territory's political status remains unresolved: though internationally unrecognized, Transnistria is, in effect, an independent state, organized as a presidential republic, with its own government, parliament, military, police, postal system, and currency. Its authorities have adopted a constitution, flag, national anthem, and a coat of arms. However, following a 2005 agreement between Moldova and Ukraine, all Transnistrian companies seeking to export goods through the Ukrainian border must be registered with the Moldovan authorities. This agreement was implemented after the European Union Border Assistance Mission to Moldova and Ukraine (EUBAM) started its activity in 2005. Most Transnistrians are Moldovan citizens, but there are also many Transnistrians with Russian and Ukrainian citizenship.

Transnistria is sometimes compared with other post-Soviet frozen conflict zones such as Nagorno-Karabakh, Abkhazia, and South Ossetia. The last two have recognized Transnistria as an independent state and have established diplomatic relations in return for Transnistria's recognition of them via the Community for Democracy and Rights of Nations.

49 Policy Paper Series [PP/01/2010] - Electricity Sector in Moldova: Evaluation of

strategic options, by Georg Zachmann and Alex Oprunenco – German Economic Team in Moldova, September 2010.




Figure 67.Map of Transnistria








ANNEX A LIST OF REFERENCES

1. CAO 2008: Action Plan for Establishing the SEE Coordinated Auction Office

2. ECRB EWG Draft on SEE Co-ordinated flow-based explicit auctions

3. ECRB 2007: Overview of transmission capacity allocation methods in SEE, Status June 2007

4. ECRB 2008 Market Development Report.

5. ECRB 2008 Licensing requirements

6. ECRB 2008: Regional Congestion Management Benchmark

7. ECRB 2009, TF4 ECRB EWG: Proposal for a Harmonized System of Wholesale Trade Licensing in the 8th Region, July 2009

8. EFET: Obstacles to Electricity Trading in Central & South Eastern Europe. Electricity Coordination Center Ltd. and Energy Institute ”HRVOJE POŽAR“ 2005: Generation Investment Study, Transmission network checking, draft report, March, 2005

9. Energy Community Secretariat, Presentation on Energy Community Treaty Implementation given at the 14th Athens Forum.

10. Energy Community Investment Conference, Background information package, August 2007

11. ERGEG 2008; Regional Initiatives Annual Report

12. Europex/ETSO January 2009: Development and Implementation of a coordinated Model for Regional and Inter Regional Congestion Management

13. EU Treaty 2008: Consolidated version article 101-106 of 09.05.2008

14. COM (2007) 528: Proposal for amendment to directive 2003/54/EC concerning common rules for the internal market in electricity.

15. COM (2007) 531: Proposal for amendments to regulation 2003/1228/EC on conditions for access to the network for cross-border exchanges in electricity.

16. COM (2007) 530: Proposal for regulation establishing the EU agency for the cooperation of National Energy Regulators.

17. COM (2006) 841: Communication; prospects for the internal gas and electricity market.

18. COM (2004) 39: Markets in Financial Instruments (MiFID)

19. COM(2008) 192 final, Commission staff working document, Accompanying document to the Report on Progress in Creating the Internal Gas and Electricity Market

20. COM (2009) 115: Report on progress in creating the internal gas and electricity market, technical annex

21. ETSO: Overview of transmission tariffs in Europe: Synthesis 2007

22. Green, R. (2008): Electricity Wholesale Markets: Designs Now and in a Low-carbon Future, The Energy Journal, 2008, special issue

23. IEA 2008: Energy in the Western Balkans, The Path to Reform and Reconstruction




24. IEA 2008: CO2 Emissions From Fuel Combustion

25. IPA Energy + Water Economics (2009), “Study on Tariff Methodologies and Impact on Prices and Energy Consumption Patterns in the Energy Community”, March 2009

26. Mr. Johannes Kindler, Chairman of ERGEG FIS WG) may 2 2008: Regulator‟s view of the role of power exchanges

27. Potomac Economics 2007: Report on South East Europe Market Monitoring for the Period December 2006-February 2007

28. Potomac Economics 2008: Market Monitoring Project, Quarterly Report for March 2008

29. Pöyry Energy Consulting, Market Report for South-East Europe (non-public report)

30. Treaty Establishing the Energy Community

31. KAROVA, R., Energy Community for South East Europe: Rationale Behind and Implementation to Date, EUI Working Paper RSCAS, 2009/12.




ANNEX B GLOSSARY

Acronym/Abbreviation Definition

AAC Already Allocated Capacity

AMR Automatic Meter Reading

API Application Programmers Interface to be used for developing systems for importing or exporting data.

Area Price Is the price per hour calculated for bidding areas defined by TSOs, when transmission constraints are likely to occur towards other bidding areas,

ATC Available Transmission Capacity

ATS The After Trade System

Available Transfer Capacity (ATC)

Is the part of the Net Transfer Capacity (NTC; see below) that remains available, after each phase of the allocation procedure, for further commercial activity.

Bidding area

A geographically limited part of the HV-grid in which market bids are placed and in which a single market price can be determined per time unit.

Bidding Currency The currency used in a participant‟s bid; it will be converted to master currency.

Bilateral trading Direct trading between individual market parties, without involvement of Brokers or a Power Exchange.

BI Business Intelligence concept / blueprint

Block Bid Bid addressing pre-defined series of hours and limited volume.

BM Balancing Market, same as RTBM

Border Capacity (BC) model

Model for the capacity determination and allocation using a simplified flow based network representation where each control area is described by a single node.

BR Balance Responsible

C3 Concentration of 3 largest companies. C3 is calculated as the sum of the market shares for the three largest companies.

CAO Coordination Auction Office

Contractual flow on Individual Interconnector

The Day Ahead exchange between two neighbouring areas.





Control area

(Reference: ENTSO-E Operation Handbook)

A CONTROL AREA is a coherent part of the ENTSO-E INTERCONNECTED SYSTEM (usually coincident with

the territory of a company, a jurisdiction or a geographical area, physically demarcated by the position of points for measurement of the interchanged power and energy to the remaining interconnected network), operated by a single TSO, with physical loads and controllable generation units connected within the CONTROL AREA. A CONTROL AREA may be a coherent part of a CONTROL BLOCK that has its own subordinate control in the hierarchy of SECONDARY CONTROL.

Counter Part The entity buying all from sellers, selling all to buyers.

Critical Branches (CB) model

Flow based model for the capacity determination and allocation using a detailed transmission model and including an explicit treatment of security constrained scenarios by introducing critical branches, the network elements which could become overloaded as more energy is exchanged between the hubs of a region.

DAM Day-Ahead Market. See Day-Ahead Market.

Day-Ahead Market

Market conducted a day before delivery day/hour, operated by power exchanges, based on sealed bid double auction and market (equilibrium) price principles.

Delivery Day (D) The day for which the schedules traded on D-1 is delivered

DMS The Data Management System.

Dome Coupling

An overarching coupling system that coordinates two or more underlying coupling systems and/or markets, using volume coupling (see volume coupling).

DSO Distribution System Operator

DSM Demand Side Management

EC Eligible Customers

Energy derivatives

Financial contracts for forward (possibly long term) delivery periods that derive their value from an underlying reference price, such as a spot price or the difference between spot prices in two different market (bidding) areas or between a regional reference price and a market (bidding) area price.

Explicit auction of rights

An auctioning system where (normally) TSOs sell cross border capacity rights with differing maturity for nomination ahead of operation day/hour, and those auctions are independent of energy trading in the respective areas on each side of the border.

FBATC Flow-based Available Transmission Capacity

FFM Financial Forward Market

Flexible Bid 1 hour sale bid for the hour with the highest price within the day-ahead auction

Forward market

Market that operates the buying and selling of energy related products, physical or financial, with maturity dates longer than a day, typically monthly, quarterly, and yearly.





Full Supply Contract Full Supply Contracts means that the customer can consume whatever he likes and pays the same contract (tariff) price for the whole volume

G Generator

Gate Closure The time from which bids are no longer accepted for the next delivery day. This might differ from the TSO gate closure.

HHI Herfindahl-Hirshman Index. HHI is calculated as sum of the square of the market shares for all market participants: ∑(market share)2

Hour Hour 1 means Time from 00 to 01, Hour 24 means time from 23 to 00.

Hourly Bid One hourly interval bid.

Hub

(See bidding area).

HW/SW Hardware/Software

IDM Intra-Day Market

Implicit Auction

Combines the sale of energy and utilization of cross border capacity in one process, thus establishes prices in each involved Bidding Area and planned flows between all areas.

Intra-Day market

A market offering trading for the current day and after closing of the day-ahead market also for the following day. There are auction based Intra-Day markets, similar to the Day-Ahead Market, or continuous energy trading including cross border bids

ISO Independent System Operator

ITC Inter-TSO Compensation mechanism

KPI Key Performance Indicator (or Index)

Loose volume coupling

The volume coupler uses partially indicative bid/offer information and might not fully replicate the local matching rules.

Market Coupling

Is the process of joining market areas managed by different power exchanges with the purpose of determining day-ahead volumes of exchange by implicit auctioning between the market areas, and in the case of Price Coupling (see below) also prices, based on an algorithm that utilizes bid/offer information acquired from each market and cross border capacities.

Master Currency The currency for which the price calculation is done

Market splitting

Is the process of determining day-ahead volumes of exchange by implicit auctioning, with splitting up the bidding areas managed by one power exchange into two or more price areas, while utilizing the available capacity between the congested areas

MCP Market Clearing Price is price per hour calculated for the bids in defined areas





NEC Net Export Curve

Net Exchange Difference between purchases and sales for an area

Net Transfer Capacity (NTC)

Possible exchange program between market (bidding) areas, compatible with the operational security standards applicable in each area

LMO Local Market Operator – This is the local market operator for each jurisdiction/contracting party, which is the legal counterparty to all its stakeholders

Organic process

(See horizontal process)

OTC (Over-the-counter)

Trade between market participants via a broker, without involvement of a power exchanges.

PFM Physical Forward Market

PHLG/MC Permanent High Level Group/Ministerial Council – bodies in the Energy Community.

PPL Public Procurement Law

PM Project Manager

Price Area

A geographic area, consisting of one or more Bidding Areas, which has a common price in a given time period. Thus in case of several Bidding Areas forming a Price Area it reflects that no congestion exist between those Bidding Areas.

Price calculation The matching of bids and offers.

Price coupling

A coupling system, which in one step establishes both prices and volumes for each coupled market, and where all bids/offers from all market.

Bidding areas are considered in an anonymous manner in the coupling system. Market splitting is a form of price coupling, where all bids/offers; pricing per bidding area and settlement is handled by one power exchange. A price coupling system can be placed in a unique legal entity or can be a unique system that is shared by the local power exchanges.

PTC The Participant Client System.

PSO Public Service Obligation

PTC The Participant Client System.

PX Power Exchange

RBM Regional Balancing Market

RMD Regional Marked Design

Region

ERGEG Region: one of the seven Regions originally defined in the Congestion Management Guidelines 2006/770/EC.

Market region: cluster of market (bidding) areas that share a unique price coupling system, which generates both prices and volumes.





Regional PX This is the regional price setter for the common DAM. This is not a power exchange as such, but the entity that performs the Day-ahead auction on behalf of the LMOs based on an implicit auction. The proposal is that this is performed by a service provider (SEESP). This entity constitutes a cooperation agreement between the involved LMOs and should not be envisioned to be a large organisation, but a body constituting the regional cooperation.

RTBM Real Time Balancing Market

S Supplier

SLA Service Level Agreement.

SRMC Short-run marginal cost

SO System Operator

SEE Regional Power Market This is the implementation of the RMD for the SEE region.

SEESP This is the service provider that is responsible for the tasks defined for the Regional PX in the SEE region.

TC Tariff Customer

TLC Tri-lateral Coupling, Electricity market area of France, Belgium and the Netherlands

Trading Day (D -1) The day the DAM auction price is calculated for the next Delivery Day (D)

TSO Transmission System Operator.

Tight volume coupling

The volume coupler replicates the local matching rules and uses more precise bid/offer information than in the loose volume coupling case.

Volume coupling

A coupling system that partly or fully replicates the matching rules of each coupled market and utilizes indicative or actual anonymous bid/offer information. The algorithm determines the volume of exchanges between the underlying regions/markets. The local power exchanges utilize the generated cross-border volumes to locally determine their bidding area(s) prices and volumes.

VPP Virtual Power Plant

VPPA Virtual Power Plant Auction

UMCP Unconstraint Market Clearing Price

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