background paper international experience … paper international experience with private sector...

Background Paper

INTERNATIONAL EXPERIENCE WITH PRIVATE SECTOR

PARTICIPATION IN POWER GRIDS TURKEY CASE STUDY

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ESMAP Mission The Energy Sector Management Assistance Program (ESMAP) is a global knowledge and technical assistance program administered by the World Bank. It provides analytical and advisory services to low‐ and middle‐income countries to increase their know‐how and institutional capacity to achieve environmentally sustainable energy solutions for poverty reduction and economic growth. ESMAP is funded by Australia, Austria, Denmark, Finland, France, Germany, Iceland, Lithuania, the Netherlands, Norway, Sweden, and the United Kingdom, as well as the World Bank.

Copyright © May 2012 The International Bank for Reconstruction And Development / THE WORLD BANK GROUP 1818 H Street, NW | Washington DC 20433 | USA Cover image: ©iStock

Written by Budak Dilli, Independent Consultant For Victor Loksha, Energy Sector Management Assistance Program (P146042) See synthesis report (No. 99009): World Bank. 2015. Private Sector Participation in Electricity Transmission and Distribution: Experiences from Brazil, Peru, the Philippines, and Turkey. Energy Sector Management Assistance Program (ESMAP) Knowledge Series No. 023/15. Washington, DC: World Bank Group. https://hubs.worldbank.org/docs/imagebank/pages/docprofile.aspx?nodeid=24933178 Energy Sector Management Assistance Program (ESMAP) reports are published to communicate the results of ESMAP’s work to the development community. Some sources cited in this report may be informal documents not readily available. The findings, interpretations, and conclusions expressed in this report are entirely those of the author(s) and should not be attributed in any manner to the World Bank, or its affiliated organizations, or to members of its board of executive directors for the countries they represent, or to ESMAP. The World Bank and ESMAP do not guarantee the accuracy of the data included in this publication and accept no responsibility whatsoever for any consequence of their use. The boundaries, colors, denominations, and other information shown on any map in this volume do not imply on the part of the World Bank Group any judgment on the legal status of any territory or the endorsement of acceptance of such boundaries. The text of this publication may be reproduced in whole or in part and in any form for educational or nonprofit uses, without special permission provided acknowledgement of the source is made. Requests for permission to reproduce portions for resale or commercial purposes should be sent to the ESMAP Manager at the address below. ESMAP encourages dissemination of its work and normally gives permission promptly. The ESMAP Manager would appreciate receiving a copy of the publication that uses this publication for its source sent in care of the address above. All images remain the sole property of their source and may not be used for any purpose without written permission from the source.

CONTENTS EXECUTIVE SUMMARY ................................................................................................................................... i

Turkey Case Study ......................................................................................................................................... 1

1. INTRODUCTION ................................................................................................................................. 1

2 GENERAL OVERVIEW AND HISTORICAL BACKGROUND .................................................................... 1

2.1 The Period until 1984 ................................................................................................................ 2

2.2 The Period between 1984 and 2001 ......................................................................................... 3

2.3 The Period after 2001: Creation of a Competitive Liberal Electricity Market .......................... 4

3 PSP MODELS IMPLEMENTED IN T&D ................................................................................................ 7

3.1 PSP Models under Past Concessionary Regime ........................................................................ 7

3.2 PSP Model After 1984 ............................................................................................................... 9

3.3 EXISTING PSP MODELS IN T&D AFTER EML ............................................................................ 13

4 RESULTS OF IMPLEMENTATION ...................................................................................................... 29

4.1 Before EML .............................................................................................................................. 29

4.2 After EML ................................................................................................................................ 30

5 OPERATIONAL PERFORMANCE OF PRIVATIZED (OR PRIVATELY OPERATED) T&D ASSETS ............. 34

6 PROBLEMS OF IMPLEMENTATION .................................................................................................. 38

7 CONCLUSIONS, LESSONS LEARNED, AND RECOMMENDATIONS .................................................... 40

APPENDIX 1: Transmission System ............................................................................................................. 46

APPENDIX 2: Distribution System ............................................................................................................... 48

T u r k e y C a s e S t u d y | i

EXECUTIVE SUMMARY PSP in Turkish power sector was started almost from the beginning of electricity generation within the country in the first decade of 20th century. Since then, depending on the macroeconomic policies and models preferred by the governments, there had been several distinct periods in which different models are used and for each period, the degree of participation of private sector to T&D activities and investments varied.

It can be said that, except the period up to 1930s, the main players in the field of power generation, transmission and distribution were either municipalities or various state organizations. Up to 1970s the system was fragmented, there was no interconnected transmission grid. The main priority was the electrification of the country, and all electrification programs were carried by public entities. The electrification and interconnected grid construction activities gained pace after consolidation of all activities under a single public authority TEK. PSP was very limited and there were only two vertically integrated regional concessionary companies and only one concessionary distribution company operating in a small region. Pubic companies were also shareholders of these concessionary companies.

In the concessionary regime which was implemented within the period up to the year 1984, the cost of the activity plus a predetermined profit is guaranteed to private participants. The disputes between the private participant and public authorities were to be solved by the State Council. Also concessionary contracts were reviewed by the State Council and should have been revised in accordance with the Council’s comments.

The first major step for liberalization and increasing the level of PSP in power sector was the issuance of the Law 3096 in 1984. The aim of the Law 3096 was to enable PSP in generation, transmission and distribution activities through private law assignment contracts as opposed to concession concept. Build Operate and Transfer and Autoproduction in generation, Transfer of Operating Rights for generation and distribution activities were the models for PSP in power business.

The “assignment” concept was enabling private law contracts, international arbitration for dispute settlement, and no State Council review or approval was needed. However, sometimes after, the Constitutional Court has ruled that, according to Turkish Constitution, the only mean for PSP in a public service is concession and private law cannot be used. As a result, except some BOT generation projects, which were enacted before cancellation, the implementation models brought by the Law 3096 is had to be realized with concession contracts. It was only after 1999, private law contracts and international arbitration was made possible by changing the Constitution. The main reason for this change is to attract private, especially foreign investors to the power sector investments; since administrative law contracts, administrative authorities’ involvement and lack of international arbitration were deemed risky by private investors.

During the period between 1984 and 2001, it was tried to privatize the distribution activities by TOOR method, however upon lawsuit applications of NGOs and labor unions, Council of State decisions, except two regions, all contracts were cancelled. Some of those contracts were private law contracts (enacted after 1999) and after international arbitration proceedings Turkish Government had to pay compensation.

The Turkish electricity market is one of the fastest growing markets throughout the World. The annual average consumption increase was 7.3 % in the last 30 years (1980‐2010), and it is expected that this fast growth will persist in the future. Therefore, there is a need for new generation investments to cope with the demand increase. The transmission and distribution system should also be expanded accordingly. It was necessary to attract local and foreign capital to power business, which was why the first steps have

ii | I n t e r n a t i o n a l E x p e r i e n c e w i t h P r i v a t e S e c t o r P a r t i c i p a t i o n i n P o w e r G r i d s

taken after 1984. However, the first steps were without solid legal footing. Rather than resulting from a long‐term restructuring plan; liberalization of the electricity industry stemmed from high demand growth, and a corresponding urgency for investment needs. Lacking of a properly working legal framework, the process has been subjected to interruptions and reversals. The overall outcome of the first phase of reform efforts (1984‐2001) can be summarized as comprising a moderate level of private capital inflow into the generation segment.

The problems encountered in the previous period led to find a different model for attracting private investment. The currently ongoing period of power market was started in March 2001 by the enactment of Electricity Market Law (“EML”) which aims to establish a liberal, competitive energy market and enables PSP in market activities through a licensing mechanism instead of concession. In fact the main policy since 2001 is to carry out all market activities except transmission by private parties instead of public companies and therefore EML basically envisages a private ownership in all market activities except transmission.

In Turkey “integrated transmission business model” is implemented. That is the transmission system operation and transmission grid ownership and operation is under the responsibility of a single transmission company (TEIAS). EML does not foresee a privately owned and operated transmission grid. TEIAS is a state owned company and independent of all supply and trading activities. The rationale for the selection of the integrated model and public ownership is discussed in the report. As a summary, it can be said that; the vital role of transmission for a reliable power system, the importance of independent and impartial transmission system operation for open access and competition, the need for coordinated operation and necessity for a central decision for investment planning were the main reasons for combining TSO and grid ownership under the same company.

Once the integrated model is selected for transmission and State owned company is assigned, the PSP in transmission activities are limited. However, there are two cases defined in the legislation that making possible PSP in transmission system investments such as: Realization or financing of the necessary investments by the generation companies on behalf of TEIAS for the connection of the power plant to the transmission system and construction and operation of a private direct line.

The PSP in distribution however, followed a different track. Rooting from highly politicized municipality ownership time, political interventions in management, price control policies, insufficient budget allocations have resulted in an inefficient operational performance and low quality of service. Furthermore, starting from 1980s, in parallel with liberalization policies in almost all sectors, PSP in distribution was on the agenda.

Distribution companies have two licenses: distribution license and retail license. Under distribution license, companies operate and maintain distribution system in their regions, carry out necessary expansion investments. Under retail license, they are supplier of non‐eligible consumers in their region. They are completely subject to regulation of EMRA.

The main model for PSP in distribution is privatization of the State‐owned regional companies operating the distribution systems, while the assets remain state‐owned. Today, the implementation of this model in Turkey is well underway, there are 21 distribution regional companies and 13 of them are privatized. The privatization model is “TOOR model backed Share Sale” model which is explained in detail in the report.

Other participation means such as participation in grid investments for generator connections or consumer connections also exist and they are described in detail in the report.

Distribution and retail activities in Organized Industrial Zones (OIZ) are also important PSP implementations in Turkish power market. OIZ legal entities can perform distribution and/or generation

T u r k e y C a s e S t u d y | iii

activities within the approved borders in order to meet the demands of their participants upon receiving license from EMRA.

In the scope of PSP in transmission, total estimated cost of the transmission facilities constructed or under construction by private sector is TL818 million (roughly $455 million) for the connection of 281 new power plants in the last 5 years.

Since the privatization of the distribution business could only start in 2009 (although the process started earlier, due to delays and cancellations actual transfers of the assets started in 2009), and due to gradual transfer process in 2009‐2011 period, a meaningful PSP occurred only in the last two years of this period. Therefore it is not possible to make a general realistic assessment of the gains and/or shortcomings of the privatization. However, the public sector investments reduced by more than 50% after privatization. As opposed to previous payment problems, privatized DistCos are paying fully the cost of energy to the suppliers. Also improvements are reported in collection rates, and in service quality. The loss and theft reduction targets are determined and private DistCos are implementing the systems like Supervisory Control and Data Acquisition (SCADA) systems, Geographic Information Systems (GIS) and they are trying to renew or improve metering, registration and maintenance systems and activities, in order to met the service quality requirements and the loss reduction targets imposed by EMRA.

There are still some lingering problems impeding the successful implementation of the Turkish privatization model in distribution. However, it is expected that these “teething problems” will not persist for too long.

The Turkish experience shows that, first and foremost, a strong and credible judiciary is a necessary condition to employ the regulatory system as a means of securing PSP in the industry. The legal framework should be clearly defined and a consensus of related parties must be reached on the methods with which a “public service” can be provided by private sector.

Also the ownership issue with respect to restructuring and privatization should be solved. Since the assets in T&D grids are used for a public service, and since there is no other alternative, it can be claimed that those assets cannot be subjected in private ownership, like it has been interpreted in Turkey. This interpretation naturally depends on the legal system of countries, however, if interpreted like in Turkey; in order not to cause legal problems, the PSP model like TOOR can be implemented. Although asset ownership increases credibility of the private companies and reduces the risks, a long term operational rights can reduce uncertainty and can be used as a compromise.

The unbundling of distribution activities from retail and careful regulatory oversight for self‐dealing will enhance the effective competition in the market.

The regulatory framework should be prepared by taking into account the future developments and should not be changed frequently. To attract PSP, the regulations should be clear, consistent and simple as much as possible. However, at the same time, the balance between public benefit and incentives should be carefully considered.

If a country plans to liberalize the electricity market, implementing concession or assignment methods or long term contracts inherited from previous regime make the transformation complex and costly. If implementing such models is preferred, as an intermediary step, before liberalization, the related contracts should have an article about full compliance with the further legislative environment.

The unbundling of distribution activities from retail and careful regulatory oversight for self‐dealing will enhance the effective competition in the market. If private ownership is envisaged in transmission, then System Operation should be independent and careful regulatory oversight is needed to ensure non discriminatory transmission service.

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Cost based pricing is important for attracting PSP and for creating a well functioning market. However, especially for the countries like Turkey, where the demand increase rate is very high and substantial generation, transmission and distribution expansion investments are required, it is necessary to protect low income consumers against price increases.

T u r k e y C a s e S t u d y | 1

TURKEY CASE STUDY

1. INTRODUCTION Development of transmission and distribution (T&D) infrastructure is crucial for the power systems. Regardless of the market models and the ownership structure, they have to be adequate for the continuity of the energy flow, the reliability of the power system and the quality of the energy supply. They have to be developed in parallel with the generation expansion in order to cope with the energy demand and to provide a sustainable service to the users and consumers.

Furthermore, in the liberalized electricity markets, the lack of availability of transmission capacity, occurrence of transmission congestion, transmission pricing, etc. are deeply affecting the ability of the market participants to trade and to enter into the system, and may prevent effective competition in the market.

Private sector participation (PSP) mechanisms can be used in order to remove transmission and distribution bottlenecks without putting burden on public finances; or in order to speed up the transmission and distribution investments.

On the other hand, the T&D grid operations are not competitive activities. Due to their monopolistic nature, those activities should be regulated. Therefore, the dynamics and methods of PSP to T&D are different from PSP in generation and/or trade.

In this study, PSP practices of Turkey in T&D have been investigated. In this respect; a general overview and historical background has been given in Section 2. The structural and regulatory aspects of PSP models in T&D in the past and also after the reform have been explained in Section 3. It should be noted that, the PSP models used before the electricity market reform are also introduced in order to give information about different models. However, emphasis is given to the implementation of the recent PSP models. Results of implementation and problems are explained in sections 4, 5 and 6. Finally, conclusions, lessons learned and recommendations are discussed in Section 7.

2 GENERAL OVERVIEW AND HISTORICAL BACKGROUND PSP in Turkish power sector was started almost from the beginning of electricity generation within the country in the first decade of 20th century. Since then, depending on the macroeconomic policies and models preferred by the governments, there had been several distinct periods in which different models are used and for each period, the degree of participation of private sector to T&D activities and investments varied.

Although including some intermediary stages, the development of Turkish power system and PSP models can be overviewed historically in 3 distinct periods:

Zero point to 1984: From a fragmented system to country‐wide vertically integrated system.

1984 ‐ 2001: First liberalization and restructuring efforts and new models for PSP.

2001 ‐ Today: Competitive Electricity Market.

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2.1 The Period until 1984 When the Turkish Republic was established in 1923, the installed capacity of Turkey was only 33 MW and only Istanbul, Tarsus and Adapazari had been using electricity.

Until the mid of 1930ies, the electricity generation and distribution activities were carried out by private concessionary companies (mostly foreign companies). Kayseri ve Civarı T.A.S. (“Kayseri Co.”), being a fully Turkish company was established at that time (1926). By following Kayseri Co. example, a lot of concessionary companies were established in 1926 – 1929 periods. The 154 kV transmission line from Silahtaraga power plant to Yedikule in Istanbul in the year 1927, and 26 kV transmission line between Visera and Trabzon on Black sea shore in 1929 were constructed by those concessionary companies.

In 1930, the Municipality Law was enacted and municipalities had gained the ability to deal with electricity activities and to make concessions for establishing and operating electricity facilities in their territory.

In 1935, three State‐owned enterprises were established. In this context, village electrification activities were carried out by Iller Bankasi (Bank of Provinces), thermal plants were constructed and operated by ETIBANK and hydropower plants were planned and constructed by Electrical Power Resources Survey and Development Administration (EIE).

In the second half of 1930ies, due to the lack of domestic capital accumulation, the rules had changed towards a centrally planned economy and a nationalization program in line with the other European countries was began to be implemented. As a result of this change, concessionary companies of electricity sector were transferred to municipalities (Ankara in 1938, Istanbul in 1939 and Izmir in 1943).

This period lasted to the first half of 1950’s; and after that, a new wave of private participation by the transfer of operational rights from municipalities to concessioner companies was started.

Turkey had not had a national interconnected grid in 1950ies; so municipalities, public companies and concessionary companies were generating and distributing electricity in their area of authority. The first step towards the construction of interconnected grid was the construction of 288 km, 154 kV transmission line between Zonguldak Catalagzi thermal power plant and Istanbul. The constructor company of the transmission line was Eregli Coal Enterprises (afterwards named as Turkish Hard Coal Enterprises ‐ TTK) which also constructed the Catalagzi hard coal TPP.

The main characteristic of that period is that, the electricity system is fragmented. There was a separated ownership structure that directly effecting the operation of the transmission and distribution systems. Concessionary companies and municipalities had their own rights and responsibilities with respect to execution of electricity generation, transmission and distribution and sale activities. Although there were different public organizations dealing with electrification, generation and development, there was no central planning for electrification, generation and transmission development. Also, there was practically no interconnected transmission grid.

The system was drastically changed again by the establishment of vertically integrated Turkish Electricity Authority (TEK) in 1970. TEK was established to own, operate and develop a national transmission and generation system. After the establishment of TEK, there had been a fast increase in generation and development of interconnected transmission system.

Although, the establishment of TEK helped for the improvement of the interconnection system overall management, the today’s country‐wide interconnection can only be ensured by the transfer of all assets including distribution assets hold by municipalities and Iller Bankasi to TEK in 1983 by after the enactment of Law No. 2705 in September 1982 except the assets of two regional vertically integrated concessionary companies Cukurova Electricity Company (“CEAS”) and Kepez Electricity Company (“KEPEZ”) which were


established in early 50’s based on the Concession Law. After the transfers of these facilities, TEK became a real vertically integrated entity, carrying generation, transmission and distribution and sale activities in the country except two regions mentioned above.

2.2 The Period between 1984 and 2001 The very high demand growth and a corresponding urgency for investments needed the government to decide on the abolishment of TEK’s monopoly in electricity generation and distribution. In this respect, the enactment of Law No. 3096 in 1984 was started a new era for the liberalization of power sector even before most of the European countries’ experience.

The aim of the Law 3096 was to enable PSP in generation, transmission and distribution activities based on private law through assignment contracts as opposed to concession concept. However, due the general public opinion and the decisions of jurisdictional authorities at that time, Law No. 3096 was also forced to be implemented within the form of concession subjected to administrative jurisdiction by the Council of State. So, Build‐Operate‐Transfer (“BOT”) and Transfer of Operational Rights (“TOOR”) type PSP models of Law No. 3096 were bounded by concession concept. However, the Auto‐production model which was another type of PSP according to Law No. 3096 was implemented successfully without necessitating the concession concept.

Meanwhile, in 1994, TEK was restructured and two State‐owned companies, namely Turkish Electricity Generation and Transmission Company (“TEAS”) and Turkish Electricity Distribution Company (“TEDAS”) were established. This was the first step towards unbundling of the vertically integrated structure.

On the other hand, the Law No. 3996 which was also covered other sectors beside the energy sector enacted in 1994 in order to open the door again for contracts based on private law rather than the concession. Furthermore, through the Law No. 3996, regeneration of the Law No. 3096 was aimed also; but, the Constitutional Court cancelled the desired implementation of the relevant articles in 1995.

In 1997, through the enactment of Law No. 4283, the Build‐Own‐Operate (“BOO”) model is introduced for generation investments based on imported resources (i.e. natural gas) by taking into account the jurisdictional decisions that interrelated the use of domestic natural resources with the concession concept.

And, in 1999, the Parliament realized Constitutional amendments enabling the implementation of private law for BOT and TOOR models and also allowing international arbitration for dispute settlement. Accordingly a set of adjustment laws were enacted in which the international arbitration clauses became possible even for the already contracted projects based on Law No. 3096. However this time, the problem of “project selection” for Treasury Guarantee had occurred between governmental institutions and the expected benefit cannot be ensured. On the contrary, all of those efforts had counterproductive effects and Government struggled against international arbitration cases in the following years.

The sector structure occurred at the end of this period is shown in Fig. 1 below.


Fig. 1 Turkish power sector between the years 1994‐2001

GENERATION TRANSMISSION DISTRIBUTION

In that period, TEAS was the single buyer and seller of electricity and the generation of BOT, BOO and TOOR power plants were also purchased by TEAS with long term Power Purchase Agreements (PPAs) which including take‐or‐pay commitments guaranteed by the Treasury. Industrial companies were allowed to generate electricity for their own use under auto‐production model.

On the other hand, in this period, in 1990, a new concessionary company AKTAS took over the distribution system of Anatolian side of Istanbul and the concession period of Kayseri, CEAS and KEPEZ is extended in line with the Law 3096. Since the companies except AKTAS were already in the sector, it can be said that the only new private participant for distribution activities in this period is AKTAS.

There were four private companies engaged in T&D business within the country as of 2000. These are CEAS in Adana and surroundings engaged in transmission and generation, KEPEZ in Antalya and surroundings engaged in transmission and generation, Kayseri Co. in Kayseri and surroundings engaged in distribution and AKTAS in the Anatolian Side of Istanbul engaged in distribution. All of those companies were operating according to their concession contracts.

It can be interpreted that, this period has ensured a moderate level of private capital inflow especially into the generation segment; however, due to the regulatory uncertainty and the country risk hampering the investment climate, those generation investments in the form of BOT and TOOR model, have endured high‐risk premiums, which have resulted in elevated energy costs.

In this period, it was tried to privatize the distribution according to TOOR model of the Law 3096. However, the attempt was not successful which will be described in Section 3.2.

2.3 The Period after 2001: Creation of a Competitive Liberal Electricity Market

The currently ongoing period of power market was started in March 2001 by the enactment of Electricity Market Law (“EML”) which pointed out a non‐concessionaire regime for market activities.

In this respect, the issuance of EU Electricity Directive (Directive) in 1996 was also an important milestone for Turkey that coincided with the aspiration to become a member of the European Union. In January 1997, Ministry of Energy and Natural Resources of Turkey (“MENR”) launched the necessary studies funded by World Bank to comply with the conditions of the Directive. The general objective of Turkish


governments for the improvement of economic efficiency and attracting investment into the power sector had also gained pace to the process.

Energy Market Regulatory Authority (“EMRA”) established by EML and became operational on November 2001 was prepared the secondary legislation according to the primary legislation set forth in EML during the Preparatory Period which was ended on 3rd of September 2002. On the other hand, the eligibility concept has been put into operation on 3rd of March 2003 according to EML . There had been many revisions and additions to the secondary legislation since then.

Together with the market reform introduced by EML, sectoral structure and market players are also changed. In this respect, TEAS was restructured to form three State‐owned Public Enterprises namely:

Turkish Electricity Transmission Company (“TEIAS”) for carrying out electricity transmission activities, system and the market operation;

Electricity Generation Company (“EUAS”) for carrying out electricity generation activities until fully privatized;

Turkish Electricity Trading and Contracting Company (“TETAS”) for carrying out electricity wholesale activities in order to undertake the long term PPAs (existing contracts) with BOO, BOT and TOOR companies.

These three companies, together with the Turkish Electricity Distribution Company (“TEDAS”) are the State‐owned players in the market.

In addition to EML and the secondary legislation, High Planning Council of Turkish Government (GoT) published 2004 and 2009 Strategy Papers with the aim to underline the commitment of GoT to the market reform and to constitute a road map for market liberalization, privatization and supply security issues.

On the other hand, by following the enactment of EML, the concession contract of AKTAS was cancelled by MENR upon the decision of the Council of State (DANISTAY), due to misconduct. The concession contracts of CEAS and KEPEZ companies were cancelled also by MENR as those companies did not fulfill the requirements of EML and did not obey the rules and procedures of the market reform introduced by EML even though their contracts oblige them to do so. In addition, Kayseri Co. has abandoned its concession contract and granted by EMRA as a licensed company through the revision of its contract in order to comply with the requirements of EML.

EML does not foresee the privately owned and operated transmission system, (a very important reason for the cancellation of the concession contracts of CEAS and KEPEZ companies was the resistance of those companies for the transferring of the transmission facilities to TEIAS), except private direct transmission lines.


The main model for PSP in distribution system is privatization. Privatization of distribution business is also an important element of market reform through EML. However, the realization of privatizations is considerably delayed and only 13 of 21 regions are privatized during the 10 year’s time. In principle, the Strategy Papers of GoT suggested the completion of distribution privatizations before privatization of power plants which are still pending. Forms of PSP other than full privatization are also possible for the distribution regions which are not privatized yet. The privatization model and other means for PSP in distribution business will be explained in Section 3.3.2.

The fields of activities of the market players before and after EML are shown in the Table 1 below.

Box: Transmission Model

From the ownership and operation point of view, transmission business can be separated into two main categories: One is the transmission system control and operation (can also be named as power system operation) and the other is transmission network operation, maintenance and expansion. Both of those functions are vitally important for security of supply, for providing open access and establishment of a well‐functioning electricity market.

There are different models for running of transmission business. One option is to separate the system operation from the transmission network ownership and establish two entities: TSO and Grid Company. The other alternative, which also implemented in Turkey, is to set up a separate company, independent of all supply and trading activities, which combines the ownership of transmission with system operations (integrated model).

There may be different preferences for the selection of the business model; however, the independence of system operation is indispensible. In some countries there are still vertically integrated utilities which own and maintain the transmission grid either nationally or regionally. The general trend is to take the system operation and planning authorization from these utilities and hand over these functions to an independent system operator. However, the integrated company or utility have still the power to keep other competitors out.

The transmission system operation should be independent from generation and trade activities. The system operators have an enormous power to affect competition. Therefore, even if the integrated model is not selected, the transmission ownership should be unbundled from other activities.

Having only one owner and operator of transmission system has following advantages:

1 | Planning and operation of the transmission system by a single entity is much easier; 2 | There is only one entity that is responsible for the quality of electricity, 3 | Monitoring the independency of the single operator is also much easier. 4 | Coordination is easier and there will be no tension between TSO and transmission system

owner.


Table 1. Market Players Before and After EML

Market Activity Before EML After EML

Generation TEAS, BOT, BO, TOOR, Autoproducers, Autoproducer Groups, CEAS, KEPEZ, Kayseri Co., OIZ

EUAS, IPPs, BOT, BO, TOOR, Autoproducers, Autoproducer Groups*, DistCos**, OIZ

Transmission / System Operation

TEAS, CEAS, KEPEZ TEIAS

Transmission / Market Operation

‐ TEIAS

Distribution TEDAS and Subsidiaries, CEAS, KEPEZ, Kayseri Co, AKTAS, OIZ

21 DistCos (13 private), OIZ

Wholesale TEAS, Autoproducers, Autoproducer Groups TETAS, Private Wholesale Companies, IPPs

Retail TEAS, TEDAS and Subsidiaries, CEAS, KEPEZ, Kayseri Co, AKTAS, Autoproducers, Autoproducer Groups, OIZ

21 DistCos (13 private), TETAS***, Retailers****, Autoproducers,

Import‐Export TEAS

TETAS, Private Wholesale Companies, 21 DistCos (at MV level)

Consumers Captive Consumers Non‐eligible and Eligible Consumers

(*) By following the amendments in EML in 2008, they transformed into IPPs. (**) Price cap is applied for the generated amounts which they produced and/or procured from their affiliates. (***) Only to consumers connected at transmission level before EML as a customer of TEAS. (****) Although allowed in EML, due to the transitional measures, EMRA did not grant any license for independent retailers.

The current situation of the infrastructure in transmission and distribution systems is given in Appendix 1 and 2, respectively.

3 PSP MODELS IMPLEMENTED IN T&D 3.1 PSP Models under Past Concessionary Regime

There were not different PSP models for transmission and distribution grids during the past concessionary regime; so, the models explained below are applicable for both transmission and distribution.

The consistent feature of those past PSP periods was the dominance of the concession concept. The private companies engaged in T&D business in that period are all concessionary companies.

First electrification investments in Turkey were realized by foreign companies under concession regime. Shortly after the generation of first electricity during the time of Ottoman Empire, the “Law on Making of Concessions for the Sake of Public Benefit” (Concession Law) was enacted.

Concession Law was a framework law and not specifically prepared for electricity sector. This Law determined for the authorities who can make a concession, general rules of concession, accessing the land for services, the procedures to be followed after the concession period is over, how many of the personnel and which of them are allowed to be expatriates and for which fields the subject law is not applicable. The fields that Concession Law is not applicable are the fields which have their own specific laws, such as minerals, trading, agriculture, industry, etc.


The land and assets which are necessary for carrying out activities in the scope of a concession would be purchased by the concessionary company. The land which is necessary for temporary use under the concession would be transferred to the concessionary company by the local authorities after the indemnification, which is calculated in line with the Expropriation Law valuation procedure, was paid by the concessionary. If the required land belongs to public domain and not used for other purposes, subject land is given to the concessionary until the end of concession period free of charge. In any case, any cost incurred is paid by the concessionary and the assets would be transferred to government free of charge at the end of concession period. If it is deemed necessary by the Government, the tools and movables used in the concession activities might also be purchased by Government at the end of concession contract period. Also in the contract, at the end of concession period Government’s right of being a partner would take place.

In case that, new investments which were not existing in the concession contract, are realized with the approval of related ministry in the last 15 years of concession period, after completion of such investments, 1/15th of the cost of those investments would be deducted each year and remaining value would be paid to the concessionary at the end of concession period as an indemnification.

The concession contracts would be the enclosure of concession laws specific to the concessionary and would be reviewed, accepted or rejected by the parliament. The rules on tariff determination, revision and implementation take place in the Concession Law or Council of Ministers’ Decree specific to the concessionary.

It is impossible to assess the definite degree of unbundling during the past PSP periods due to the lack of the data. However, the installed capacity was 2,235 MW and the generation was 8.6 billion kWh in 1970 when TEK was established. And, in the year 1983 when the today’s interconnected system is ensured, the total installed capacity and the total energy generation was nearly 6,640 MW and 26.6 billion kWh respectively. In the same year (1983), the total length of transmission lines was 25,231 km and only 887 km of this total (3.5 %) was owned and operated by private sector.

Box: Concessionary Regime

There are primarily two regimes according to Turkish Constitution for the procurement of public services by private parties. One of them is licensing regime while the other is concession. However, until the constitutional amendment realized in 1999, the jurisdictional decisions did not allow private parties to operate under a regime other than concession in energy sector.

In the concessionary regime which was implemented in the period up to the year 1984, the cost of the activity plus a predetermined profit is guaranteed to private participants. The disputes between the private participant and public authorities were to be solved by the State Council. Also concessionary contracts were reviewed by the State Council and should have been revised in accordance with the Council’s comments.

Although pricing policy seems attractive from the financial point of view, dispute settlement mechanism (no international arbitration) and finalizing the contract draft with the State Council approval did not attract foreign capital investments under this model.


3.2 PSP Model After 1984 1984 was an important date where the Law on Assigning Private Companies to Electricity Generation, Transmission, Distribution and Trade (Law No. 3096) was enacted to make private participation to power sector much easier.

With the introduction of Law No. 3096, the procedures were intended to be simplified and the related contracts were intended to be governed by private law rather than the concession. In this model, instead of providing concession for the activity, selected companies were “assigned” for carrying out the activity through an assignment contract. Essentially, except the dispute settlement method (in private law international arbitration is possible and no approval by the Council of State is needed; however, concession contracts should be submitted to the Council of State for approval) the main principles of the PSP model are the same.

The assignment regions where a private company will carry out electricity generation, transmission, distribution and trading should first be determined. The law foresees that electricity generation, transmission, distribution and trading authority in assignment regions may be given to private companies by the Council of Ministers upon suggestion of MENR. Before making such a suggestion, MENR is obliged to receive the positive opinion of State Planning Organization (SPO).

Box. Assignment and Concession Contracts in Turkish Case

With the fast increase in the electricity demand and limited capital accumulation of domestic businessmen, Turkey had strongly needed foreign capital inflow to the energy sector. However, being not a well known emerging economy, foreign investors exhibited hesitancy about the flow of payments they are going to receive and how Council of State would solve the disputes of a concessionary contract in case of conflicts.

To overcome such hesitation, an “assignment system” was introduced through Law No. 3096 in 1984. In this system, MENR would be a party of the implementation contract (governed by private law) to a private participant after that participant is assigned by the decree of Council of Ministers. This contract would be subjected to international arbitration in case of disputes and the first contracts had included such international arbitration clauses.

However, the Constitutional Court has decided that assignment is nothing more than making concession with the following reasons:

Any long‐term contract which was executed with a private party in power sector to carry out a public service is an administrative contract;

Supplying any public service by a private entity having all risk and benefits of the service by means of administrative contracts under the supervision of administration is concession;

According to the Constitution and Council of State’s Law, concession contracts should be reviewed and amended by Council of State.

So, the Constitutional Court has decided that assignment is in fact concession considering the nature of the service disregarding the written articles in the related Law. However, in 1999 after changes in Constitution, it was made possible to sign private law contracts instead of concession contracts.


The assignment process either in BOT or TOOR model was functioning in two ways.

In the first option, a company can submit a proposal to MENR for a market activity in a region. MENR was taking opinion of SPO about the proposal and completed its review and evaluation. If finally agreed and accepted by MENR, a decree of the Council of Ministers was asked by MENR first for the determination of an assignment region where MENR would enter into contract with private parties; and then another decree of the Council of Ministers have been taken for signing of an implementation agreement with a specified company for a specified period.

In the second option, MENR was asking for a decree of the Council of Ministers about determination of a region for assignment. After determination, MENR was making an announcement for assignment and companies were applying to MENR for tendering. The steps that are valid for the first option were followed for the qualified company through tendering process.

After receiving the decree of Council of Ministers, MENR enters into an implementation agreement for up to 99 years with the assigned company. The minimum assignment period is determined by considering the depreciation period of the planned investments. Following the execution of implementation agreement, in the light of implementation agreement articles, the related public companies enter into energy sales agreement and transfer of operational rights contract.

For the field of generation, the assigned company is obliged to utilize the primary energy sources for electricity generation to meet the demand of its assignment region. However, if the sources in the region are not adequate or for achieving generation economy, the assigned company may trade electricity with the public electricity company and/or with other assigned companies.

All the facilities, movable and immovable parts were transferred back to the government without any debt or liabilities at the end of the contract period either in BOT or in TOOR model. In case some assets are left which are not repaid through the tariff, the organization which receives the assets pays the cost of the un‐repaid portion. Also the contracts may be cancelled in case of insolvency or breach of contract conditions.

The tariff is determined on a cost plus basis and approved by MENR. Although the Law No. 3096 enables the assigned company to construct and operate transmission system in the assignment region as well, in some cases only the distribution grid in the region was transferred to the companies and the activity of current companies were limited with distribution.

In case of need of expropriation, MENR expropriates the necessary land and assigned company pays for the cost.

Two different contract types are implemented under TOOR model. First model is used for 2 distribution regions where all the risks were on the energy supplying company TEAS and model guarantees a predetermined profit to the distribution company. Profit was determined as a “reasonable return to the equity”.

At each year, a budget is prepared covering all operational expenses, and investment program. Energy was supplied by TEAS. The sale price of energy is determined through an energy sales agreement (ESA).

The company expenses and profit is transferred to the assigned company by adjusting the energy sale price of TEAS to assigned companies since national tariff is applied country wide. The investment program is prepared by the assigned company in line with the country’s electrification plan and the need of surrounding regions and implemented after the approval of MENR. The assigned company is obliged to include the investments to its investment program which are determined by MENR as well.


After each year is over, costs and revenues are calculated using the actual values and financial reconciliation is achieved to adjust the income of the assigned company. As a result of the reconciliation process, if the company revenues are over than that of determined in the budget, the excess part is transferred back to TEAS. However, in case the result is negative, i.e. if the company cannot obtain the guaranteed profit, the deficient amount is to be paid back to the company.

Indeed, the reconciliation process created problems and accusations in time. Therefore, after two contracts (Kayseri Co. and AKTAS) the model is revised.

The second model used for the TOOR of distribution regions was realized through a tendering process. The main difference of this model is leaving of some risks to the company and removing the reconciliation process.

According to the model, the distribution regions can be transferred to private companies for operation for a limited time. The ownership of assets is remained owned with the state. The companies have exclusive rights to operate the region and to supply energy to all consumers in the region except the industrial companies supplied by autoproducers.

During the tendering process, each bidder prepared a feasibility report showing their expenses for operation, investments and loss and theft reduction programs, and expected profits for 30 years. They also proposed a transfer fee which will be repaid through tariffs.

Again, the energy sale price was used to ensure the revenues determined in the feasibility report which was the part of the contract. If the real revenue is over than the expected revenue in the feasibility report or the expenses are less, the company would make more profit. On the contrary, if the real expenditures of the company were over than the values determined in the feasibility report, then the company could not get expected profit or even lose. There is no compensation or no reconciliation.

On the other hand, there was no IPP’s and eligible consumer concept before EML. The only private energy producers were autoproducers and autoproducer groups which may decrease the consumption in a distribution region when they supply electricity to their shareholders. For such cases, if the consumption of the distribution region is decreased by at least 5%, energy sale price to the assigned company would have to be re‐determined in order to offset the loss of the distribution company. Also the transfer fees would be paid back through tariffs. Provided that they can keep the loss and theft ratios below the pre‐determined level and their operational expenses do not exceed their assumptions, their revenues are guaranteed.

On such conditions, Turkey had auctioned almost all distribution regions in 1996, but not succeeded to transfer the operational rights of the regions because of annulment of the authorizations of most of the companies by the Council of State, except for two regions, this process could not be finalized as described below.


It should also be mentioned that the studies and contract negotiations were coincided with the electricity sector restructuring studies and later with drafting of EML, and were not concluded successfully.

3.2.1 PSP for the Connection of Power Plants Build according to Previous BOT and BOO Models

During the planned economy years starting from 1961 when the power plants were constructed by public electricity companies, transmission grid was also planned and constructed by public electricity company

Box: Unsuccessful Distribution Privatization Attempt according to Law No. 3096

In 1995, 29 distribution regions are defined. Except 4 regions which were operated already by private companies at that time, it was decided to transfer the operating rights of 25 regions according to TOOR model defined in the Law No. 3096. Tenders were realized in 1996 and as a result of tenders, 20 companies were determined (for 5 regions the bids were found to be inappropriate). On the other hand, 3 of those 20 successful bidders did not fulfill the bureaucratic requirements and the Ministerial Council Decisions for remaining 17 regions which were necessary for the “assignment” of the companies, were obtained and MENR has been authorized for contractual negotiations. For some of the regions, contract negotiations for the making of concessions were completed and submitted the Council of State for approval since they were deemed as administrative contracts. Upon approval of the Council of State, some concession contracts were signed in 1997‐1999 period. At the same period, some organizations (NGOs and the labor unions) applied to the Council of State and brought suits against the Ministerial Council decisions and asked for cancellation of authorization.

While the cases against concession contracts were continuing, in 1999 Constitution has been changed and signing of implementation contracts (private law) instead of concession contracts became possible. Upon this change, new legislation is prepared and some of companies preferred to renew their concession contracts and applied for signing implementation contracts. MENR renewed the authorization from the Council of Ministers, and started the negotiations. As a result of negotiations a total of 6 implementation contracts were signed in addition to 5 concession contracts. However, new lawsuits were opened against those contracts also.

The cases against the Ministerial Council decisions and contracts took a long time. After 3 years, except 2 regions, the Council of State has cancelled the Ministerial Council Decisions and contracts could not be implemented.

The main reasons for the cancellation of contracts were:

The tendering conditions did not take public interest into consideration,

Investment programs for the regions were not asked from the companies.

The corruption claims against MENR and formal defects about the tendering process were also effective for cancellation decisions.

As a result, except two regions, the privatization process was not successful. After EML, the remaining two regions were renegotiated and their contracts were revised according to the new legislation and the regions were transferred.

The dispute resolution method for the implementation contracts was international arbitration. 4 companies applied to ICC for arbitration claiming for compensation. 1 claim is rejected; however, GoT has paid roughly $ 150 million to 3 companies.


in parallel to the power plant construction. On the other hand, when the private companies began to be involved in electricity generation activities under BOT and BOO models, the location of the power plants and their commissioning dates were started to be determined by private companies. The speed of construction of power plants by private companies increased the risk of delay in completion of connection facilities by public electricity company. To overcome this difficulty, public electricity companies started to ask the generation companies to construct their connection facilities to distribution or transmission grid. The transmission or distribution facilities which connect the BOO or BOT generation facility to the existing transmission or distribution grid were constructed by the generation companies in accordance with the projects approved by TEAS or TEDAS companies.

The cost of connection facilities were included in the generation companies’ investment cost and hence paid back through energy sale (to the same public electricity companies) price. Such grid connection facilities were constructed by the generation companies on behalf of State‐owned transmission or generation companies and when the facilities are commissioned, the related State‐owned company (TEAS or TEDAS) had the title of connection facilities assets outside the power plant site.

Connection facilities of BOO model generation facilities under the Law No. 4283 were also constructed in a similar way. All BOO generation facilities are connected to the transmission grid and the cost of connection facilities were included in the investment cost of the generation facilities and the title of connection facilities assets outside the power plant site belongs to State‐owned transmission company.

3.2.2 Consumer’s Connection to the Grid

Electricity consumers on the other hand, were obliged to pay to the distribution company a connection contribution charge when they are first connected to the distribution grid. The connection contribution charge was determined by the distribution company for each customer group considering the economic conditions and paid per connection at kW basis. This charge has been changed into connection charge after EML.

On the other hand, some consumers such as agricultural irrigation customers and factories, malls, dwellings etc., may construct, own and operate transformers and connection lines in their property. The basic prerequisite of this implementation is that, the owner of the facilities should be the only user connected to the facilities he owned. If and when other users are connected to such facilities, the commonly used portion of those facilities should be transferred to regional distribution company.

3.3 EXISTING PSP MODELS IN T&D AFTER EML Previous PSP models are no longer in use after the enactment of EML. In line with the establishment of liberalized electricity market, previous PSP methods based on concession and guaranteed models such as BOT and BOO are not used. EML basically envisages a private ownership in all market activities except transmission and suggests competition in generation and trade. However, Turkey still is in a transition stage and there is a mixed ownership. In this section, the models for PSP being used after 2001 will be explained.

3.3.1 PSP in Transmission

The PSP models in transmission are regulated by EML and the secondary legislation issued according to EML.

EML does not foresee a privately owned and operated transmission grid. The rationale for this decision is elaborated in the Section 6. However, there are two cases defined in the legislation that making possible PSP in transmission system investments:


CASE 1: Realization or financing of the necessary investments by the generation license holder on behalf of TEIAS for the connection of the power plant to the transmission system in accordance with article 38 of Electricity Market Licensing Regulation (“EMLR”);

CASE 2: Construction and operation of a private direct line.

The fundamentals of the above mentioned regulatory cases can be summarized as follows:

The enormously increasing number of private generation projects portfolio and accompanying uncertainties for the connection of those plants to the T&D systems;

The budgetary constraints of TEIAS and accompanying deficiencies in infrastructure;

As a short‐term measure, making contribution to the supply security by solving of the connection problems of generation facilities.

3.3.1.1 CASE 1. Realization of transmission investments necessary for the connection of power plants by generation companies

According to EMLR Article 38 and Grid Code, if the connection point is approved by TEIAS and if new transmission facilities (substation, line) are not in TEIAS’ investment plan, or if the proposed timing of the new investment is not suitable for the investor, TEIAS can ask the market participants to construct the connection lines and the related equipment on behalf of TEIAS or finance their establishment. After the construction is completed and power plant is commissioned, the cost of investment is going to be repaid to the power plant license holder via transmission use of system fee. On the other hand, in 2008, with the amendments to EML aiming to speed up the generation investments in order to overcome tight supply‐demand balance; the repayment period was limited to maximum 10 years for the plants to be commissioned before 2015. Amended Provisional Article 14 and the related communiqué are given below:

EML Provisional Article 14

“Where new transmission facilities and installation of new transmission lines are required for connection of the generation plants to the system until the end of 2015, and if the sufficient financing not being available at TEIAS for the construction of said plants, these may be constructed or financed jointly by the legal entity or entities requesting connection to said plant.

The amount of the investment made shall be repaid within the framework of the plant agreement and the connection and use of system agreements to be signed between the related legal entity or entities and TEIAS. Repayment term shall be maximum ten years. Procedures and principles related with the said subject shall be arranged in a communiqué to be published by EMRA.”

Provisional Article 6th of the Communiqué for the Connection and Use of System in the Electricity Market

“Provided that the conditions in the provisional article 14 of EML have been met, the necessary investments can be realized individually or jointly by the license holder or holders according to the plant agreement signed with TEIAS. The ownership of the realized plant and lines shall belong to TEIAS.

In case of a jointly investment, the total cost of investment can be shared proportionally according to the electrical installed capacity figures of each licensee regulated in their respective licenses. The details of implementation shall be set by TEIAS.


The total amount to be subjected to the repayment shall be calculated according to the methodology prepared by TEIAS and approved by the Board of EMRA. The payments shall begin in the subsequent year by following the completion of investments. Payments shall be made at the last working day of each month by the deduction of relevant costs for the use of system and the system operation amounts of each licensee by TEIAS. The total time period for repayment shall be 10 years starting with the temporary commissioning date of the plant and facilities by TEIAS. The interim period between the commissioning date and the subsequent implementation period shall be deducted from the 10 years time period. The repayments shall be done in each implementation period in monthly equal installments.”

The Methodology for the Fixation of Repayment Amounts of Realized Investments

“The total amount to be subjected to the repayment shall be calculated according to the occurred minimum total cost of similar investment projects having the same technical characteristics made by TEIAS during the time period between the signing of the Connection Agreement and the date of commissioning. Price difference calculations or escalation shall not be applied while calculating the total amount of investments.”

In this model, the operation of the transmission line is under the responsibility of TEIAS. That is, the generation company builds the transmission line and hand over to TEIAS after commissioning. Since the line is constructed on behalf of TEIAS, the design standards and technical requirements are designed and provided by TEIAS. There is a separate construction agreement between TEIAS and the generation company, describing the responsibilities and technical specifications for the facility to be constructed. These technical requirements are as per the Grid Code and TEIAS technical standards. Also, the land acquisition and expropriation approvals are obtained on behalf of TEIAS.

On the other hand, the substations of power plants generally constructed and operated by the plant owner. However, if this substation is used for the connection of other participants (other generators or consumers); then, the substation equipment which is used for the connections of other parties also, will become a part of the TEIAS transmission system and owned and operated by TEIAS.

3.3.1.2 CASE 2. Private Direct Transmission Line

If an alternative connection point cannot be proposed or the applicant does not accept the proposed connection point, applicant may propose to build a private direct transmission line within the scope of license application between the generation facility and partners and/or its customers. The line can be established on the condition that a transmission control agreement is signed between applicant legal entity and TEIAS.

Box: Private Direct Transmission Line

A transmission line which is not part a of the transmission system and constructed and operated in accordance with the provisions of the transmission control agreement to be signed with TEIAS and in line with the standards applicable for the national transmission network, providing electricity transmission between a generation facility owned by a legal entity holding a generation, auto‐producer or auto‐producer group license and its affiliates, partners and/or customers.


In addition to those cases, methods used by TEIAS such as outsourcing some of the maintenance work and operation of some substations can also be considered as limited methods for PSP to transmission. The lessons learned from Turkish experience for PSP in transmission is discussed in the last section of the report.

3.3.2 PSP in Distribution

The main model for PSP in distribution system is privatization. Other participation means such as participation in grid investments for generator connections or consumer connections also exist. In this section these models will be explained.

3.3.2.1 Distribution Privatization

As mentioned above, privatization of distribution business was on the agenda even before EML. Privatization of state owned distribution and generation is also accepted as necessary steps of sector reform which is aiming to create a competitive liberal electricity market.

The main differences from the previous regime are: under previous concessionary or assignment model, distribution companies had the exclusive rights in their territories, there was no eligibility concept, and distribution and retail sale was not differentiated as separate activities (no unbundling). Furthermore, that model was ensuring a determined profit. Whereas, in the new regime, the activities are unbundled, there is no exclusive right of the distribution companies to serve all the consumers in their region. Eligible consumers have the right to select their suppliers. Theoretically when the eligibility is enlarged to all consumers including households (full retail competition), the company will compete with other suppliers, otherwise they can only act as a service company for the investments, operation and maintenance of the distribution grid. Distribution privatizations are prioritized by the Strategy Papers of GoT.

The main pillars for the prioritization of distribution privatizations were:

• Improvement of service quality by timely and adequate realization of distribution grid investments;

• Implementation of cost‐reflective pricing without any kind of cross subsidization by the minimization of loss and theft ratios that are exhibiting a big variance in distribution regions;

• Ensuring the creditworthiness of distribution companies for generation investments as they serve a big amount of consumer portfolio;

• Empowering the autonomy of EMRA while setting the regulated tariffs and prices without political influence.

The first Strategy Paper of GoT has been issued on 17th of March 2004 by after long discussions about the execution of EML in all respects. The total number and contents of distribution regions were identified by this Paper and a road map is defined for the realization of distribution privatizations.

The aim and expected gains from market reform and privatizations are listed in the Paper as follows:

Box: Transmission Control Agreements

The bilateral agreements that are signed under the provisions of private law between TEIAS and the licensed legal entities owning or operating private direct transmission lines, and that set forth the minimum terms and conditions for compliance of the private direct transmission lines with the transmission system.


• Obtaining substantial cost reductions through effective and efficient operation of generation and distribution assets by private parties;

• Ensuring the security of supply as well as the supply quality; • Reduction of technical loss ratios to the average values of OECD countries and termination of

theft; • Continuance of necessary expansion and renovation investments by private parties without

creating burden on state budget and contingent liabilities for the public; • Returning of the gains to the consumers through effective regulation and competition especially

in generation and trade segments of the market.

On the other hand, the model to be used for generation and distribution privatizations was actively discussed. And finally, the Privatization Administration (PA) has asked for the view of the Council of State.

The reasoned decision of the Council of State in March 2004 terminated the discussion and it has been decided that the TOOR model of Law No. 4046 (Privatization Law) will be applied for distribution privatizations. The model of PA is determined as a “TOOR model backed Share Sale model ("TSS model").

In accordance with the determined Road Map, TEDAS and its affiliated companies were restructured. In addition to one already privatized under concessionary regime, 20 State‐owned distribution companies were established. The operational rights of those regions were transferred from TEDAS to the regional companies. To enable this, TOOR Agreements between TEDAS and regional public companies were enacted. These companies are not asset owners, but they have rights to operate those regions.

As a result of privatization, the investor shall attain the shares of the distribution company which holds the operating rights of distribution assets and all related assets (e.g., buildings, vehicles, machine park), and the electricity distribution and retail licenses in a given region.

According to this model, the investor will be the sole owner of the shares of the distribution company which will be the unique licensee for the distribution of electricity in the designated region, but they will not have the ownership of distribution network assets. The ownership of these distribution assets will remain with TEDAS. The investor, through its shares in the distribution company, will be granted the right to operate the distribution assets pursuant to a "TOOR Agreement" with TEDAS.

Box. TOOR Model in Law. No. 4046

Currently implemented DistCo privatization model has been derived from the TOOR model under Law No. 4046 by taking into account the lessons learned with respect to distribution privatization attempts in Turkey. Although Law No. 4046 includes the asset sale model, due to the historical background and the final view of the Council of State, the TSS model has been produced depending on the TOOR model in 4046.

So, the current TOOR concept is completely different than the TOOR model of Law No. 3096.

In this new model, the operating rights were transferred to a public DistCo leaving the title of assets with TEDAŞ. In the privatization process, the shares of that public DistCo was block sold to private parties. These private parties operate distribution regions without any guarantee of profit under the revenue cap regulation model. They are completely subject to regulation of EMRA. The consumers in their region may shift if they are eligible and if they feel that they have more favorable seller


After privatization, the distribution company having the operational rights will still remain as the party of TOOR and only the owner of that company changes. Hence, TOOR also contains articles which mostly are in effect after the public distribution company is privatized by way of share transfer.

In the TSS model, asset ownership of new as well as existing distribution assets belong to TEDAS, while the investor attains the right to operate the distribution network together with the obligation to undertake the necessary investments.

In this respect:

• The ownership of the existing assets and the new assets arising from investments to be carried out by the investor; rests with TEDAS. The legal obligations relating to the asset base before the signing of the TOOR Agreement (for example, expropriation costs) have been assumed by TEDAS.

• All investments shall be realized by the investor and will be recovered through the tariffs. Except for cases of investor misconduct, the part of investments not yet recovered via the tariffs shall be paid by TEDAS to the investor upon the expiry or termination of the contract.

Not only all distribution assets transferred to DistCos belong to TEDAS; but also new assets invested by DistCos will be owned by TEDAS. In order to implement rules of the current legislation, Articles 272 and 327 of Tax Procedure Law numbered 213 was amended to enable DistCos to amortize the investments which are realized after privatization and to reimburse the cost of investments.

Since the DistCos do not have any assets and any depreciation in first tariff implementation period (2006‐2010), EMRA determined an additional income component, named the TOOR Charge component, to the distribution tariff to enable DistCos to finance the required investments. In this period depreciation term was determined as 5 years. In the second tariff implementation period (2011‐2015), since DistCos have adequate depreciation income, the TOOR Charge component was removed and depreciation term increased to 10 years.

The first Strategy Paper was brought forward the end of 2006 for the completion of distribution privatizations. However, privatizations could only be started in 2008 and the first transfer was realized in January 2009 by the transfer of the shares of Baskent DistCo to EnerjiSa. As of the beginning of 2012, out of 21 distribution regions, 13 regions have been operated by private parties. Those companies distribute around 50% of the electricity consumed as of 2012.


The current situation of distribution privatizations is shown in the table below. As it can be seen, total distribution privatization revenue of GoT is around US $5,700 million.

Box. DistCo Privatization

The interruptions and the uncompleted situation in DistCo privatizations created a public and private mixed structure which is difficult to manage.

Although the First Strategy Paper foresaw the distribution privatizations to be completed by the end of 2006, the first attempt started in 2006 was unexpectedly postponed by GoT and could only be started in September 2008.

This first package comprised of 3 regions and the transfers were completed for 3 companies within the year 2009. The second package started in October 2009 was also consisted of 3 regions and the successful companies had taken over the regions within the year 2010. The third tender was realized in February 2010 for 4 regions and transfers were completed within the same year except one region which the successful company asked for additional time for the submission of the final payment.

On the other hand, the fourth and last tenders were also realized in 2010 at August and November for 4 and 3 regions respectively. However, only one region could be taken over within the year 2012 while the rest are cancelled due to the failure of successful companies for the final payment. And, with the contribution of global economical crisis as well, the remaining 8 regions could not been transferred to private participants.

It is obvious that starting from the third package of privatizations, the problem of financing has been occurred. It should also be mentioned that all of the companies participated those tenders were domestic companies whereas there were foreign strategic companies during the first attempt in 2006.

One of the reasons of privatization failure in the 4th and 5th tenders is the very high bid prices based on unrealistic and optimistic expectation about the tariff parameters to be used in the second tariff implementation period. Private parties were expecting more favorable conditions for distribution companies and prepared their bids accordingly. They have bided high amounts for DistCos and they realized that those amounts are not realistic when the legislation and the related parameters such as gross profit margin determined by EMRA in 2010, they realized that the regions are not as profitable as they expected.

Further elaboration on the the reasons for the failure in the last tenders can be found in Section 6 (Lessons Learned).

GoT intends to tender the remaining DistCos again but it will take some time and probably the former tender prices are not expected to be bided again.


Table 4: Current Situation of DistCo Privatizations

Source: Privatization Administration

In addition, due to the amendment in EML necessitated from the decision of Competition Board, distribution and retail businesses of distribution companies shall be legally unbundled beginning with the year 2013 and different companies for each activity shall be established.

• Distribution Pricing

The distribution and retailing activities are priced according to regulated tariffs. DistCos prepare tariff proposals in accordance with Tariff Regulation and submit EMRA for approval. The main principle of pricing is cost base pricing. The tariffs reflect the cost of approved investment and operational expenditures and purchased energy prices for retail sale. DistCos are also entitled to efficiency gains for operational and theft‐loss efficiencies beyond a regulatory base in order to provide incentives for efficient operation and reduction of losses.

Region # Region Name Provinces Covered Winner Sale Price (million US Dollars) Status

18 Kayseri Kayseri Kayseri ve Civari Elk.T.A.Ş. Unknown* Transfer Completed19 Aydem Aydın, Denizli, Muğla Aydem Elk. Dağ. A.Ş. 110** Transfer Completed20 Akedaş Kahramanmaraş, Adıyaman Akedaş A.Ş. 60** Transfer Completed4 Çoruh Trabzon, Artvin, Giresun, Gümüşhane, Rize Aksa 227 Transfer Completed5 Fırat Elazığ, Bingöl, Malatya, Tunceli Aksa 230 Transfer Completed6 Çamlıbel Sivas, Tokat, Yozgat Limak, Kolin ve Cengiz 259 Transfer Completed8 Meram Kırşehir, Nevşehir, Niğde, Aksaray, Konya, Karaman Alarko 440 Transfer Completed

9 Başkent Ankara, Kırıkkale, Zonguldak, Bartın, Karabük, Çankırı, Kastamonu. Enerjisa-Verbund 1225 Transfer Completed

12 Uludağ Balıkesir, Bursa, Çanakkale, Yalova Limak, Kolin ve Cengiz 940 Transfer Completed13 Trakya Edirne, Kırklareli, Tekirdağ. IC İÇTAŞ 575 Transfer Completed15 Sakarya Sakarya, Bolu, Düzce, Kocaeli Akenerji-Cez 600 Transfer Completed16 Osmangazi Eskişehir, Afyon, Bilecik, Kütahya, Uşak Eti Gümüş 485 Transfer Completed21 Yeşilırmak Samsun, Amasya, Çorum, Ordu, Sinop Çalık Enerji 442 Transfer Completed1 Dicle Diyarbakır, Şanlıurfa, Mardin, Batman, Siirt, Şırnak Ceylan ve Karavil 228 Pending***2 Vangölü Bitlis, Hakkari, Muş, Van Aksa 100 Pending***3 Aras Erzurum, Ağrı, Ardahan, Bayburt, Erzincan, Iğdır, Kars Kiler A.Ş. 129 Cancelled7 Toroslar Adana, Gaziantep, Hatay, Mersin, Osmaniye, Kilis Yıldızlar Holding 2075 Going to be Cancelled10 Akdeniz Antalya, Burdur, Isparta İl sınırları Enerjisa-Verbund 1128 Going to be Cancelled11 Gediz İzmir, Manisa Eti Gümüş 1915 Cancelled14 Ayedaş İstanbul - Anatolian Side MMEKA 1813 Going to be Cancelled17 Boğaziçi İstanbul - European Side MMEKA 2990 Cancelled

* Existing Contract according to Concession Law and Law No. 3096.** The price offered in 1996 privatizations based on Law No. 3096 has been paid.*** Additional period is given until 1st of June 2012.


There are three separate tariffs within the secondary legislation:

• Distribution tariff (the use of system tariff): for the OPEX including investment for the distribution system (revenue‐ cap method applies);

• Retail sale services tariff: for the services such as meter reading and invoicing provided by companies holding retail licenses to consumers (revenue‐cap method applies).

• Retail sale tariff: for the cost of energy supplied to the non‐eligible consumers (price cap method applies).

The distribution use of system tariff has the following components:

• Distribution charge: A unit price per kWh which is invoiced on the amount of energy taken from the distribution system;

• Capacity charge: Invoiced monthly for each kWh on the capacity of connection agreement, for the industrial consumers which are connected to medium voltage level and in two‐term tariff groups;

• Over capacity charge: Applied to the industrial consumers which are connected to medium voltage level and in two‐term tariff groups, in case of exceeding the determined capacity of connection agreement;

• Reactive energy charge: Is the charge applied to the distribution users subjected to reactive energy limits when those limits are exceeded.

The revenue requirement of a DistCo for the fulfillment of its distribution activities is evaluated by EMRA and approved by the EMRA Board upon application of distribution licensees for 5 years tariff implementation period. The annual revenue requirement is the total of net operational charges and the depreciation of realized investments. The approved annual values are implemented after deducting the values calculated by using the annual efficiency factors determined by the EMRA Board. The approved values are escalated each year using consumer price index. In addition to this escalation, approved annual revenue requirement is corrected according to the difference between actual revenues and approved values.

The difference between the approved investments for 5 years tariff implementation period and realized investments is corrected in the second year of the following tariff implementation period.

Box. EML Definition of Tariffs

Distribution Tariffs: The distribution tariff to be prepared by distribution companies includes prices, terms and conditions for the distribution service to all real persons and legal entities benefiting from the distribution of electricity through distribution facilities, which will be employed on the basis of non‐discriminatory conduct principle.

Retail sale tariffs: The retail tariffs include prices, terms and conditions applicable to all consumers, except for those directly connected to the transmission system, which will be employed on the basis of non‐discriminatory conduct principle.

The retail sale tariffs applicable to non‐eligible consumers are proposed by retail sale companies and/or distribution companies holding retail sale licenses, and reviewed and approved by the Board.

Although EML did not cover a definition of retail sale service tariff, it had been determined through secondary legislation as the services other than sale of electricity and/or capacity by the companies having retail license.


The most critical issue with respect to regulated tariffs is the cost reflectivity of such tariffs in order to ensure the continuance of generation investments and fostering of competition especially in countries having a high demand increase like Turkey. So, the regulated tariffs such as distribution and retail sale tariff for distribution company consumers should allow full cost reflection.

After cost based revenue requirement of DistCos are calculated, the required total revenue is transferred to national tariff which is implemented equally to all distribution regions for each customer group. The revenue collected by implementation of national tariff is distributed among the distribution regions by using the “Price Equalization Mechanism”; and according to their revenue requirements, all DistCos receive adequate amount of revenue to meet its revenue requirement.

3.3.2.2 Other Means of PSP in Distribution

In principle, all the distribution system investments should be carried out by distribution companies and all the distribution facilities should be maintained and operated by these companies. However, for the special cases described below, third parties (generators or consumers) can participate to the realization and/or financing of the distribution investments.

These PSP models in distribution systems are regulated by EML and the secondary legislation issued according to EML are as follows:

• CASE 1. Construction and operation of the distribution connection lines by the generation license holder that connected the power plant directly to the transmission system according to EML Provisional Article 14b;

• CASE 2. Realization or financing of the necessary investments by the generation license holder on behalf of relevant DistCo for the connection of the power plant to the distribution system in accordance with EMLR article 38;

• CASE 3. Construction of a direct distribution line between a power plant and the facilities of the customers;

• CASE 4. Construction and operation of a branching line between the facilities of the consumers and the distribution system in order to be connected to the system;

• CASE 5. Construction and Operation of Consumer’s Transformers.

The fundamentals of the above mentioned regulatory options can be summarized as follows:

• The enormously increasing number of private generation projects portfolio and accompanying uncertainties for the connection of those plants to the T&D systems;

• The budgetary constraints of publicly owned DistCos and accompanying deficiencies in infrastructure;

• As a short‐term measure, making contribution to the supply security by solving of the connection problems of generation facilities.

3.3.2.2.1 CASE 1. Connections of power plants to transmission substations at distribution voltage level

Construction of a generation facility connection line at the distribution voltage level to the transmission system and operation of that line by the generator licensee is one of the short term measures in order to facilitate more generation investments. Provisional Article 14‐b of EML defines the rules of implementation.


To construct such a connection line, the following prerequisites should be met:

• The generation facility is planned to be directly connected to the transmission switchyard feeders at the distribution voltage level,

• The purpose of constructing the connection line should be limited with the connection of subject generation facility only,

• The form of connection should be approved by the Board of EMRA.

These facilities are operated by the generation licensees as long as the facilities are used only for the connection of generation facilities. For this type of connections, the party of connection and use of system agreements are TEIAS. The expropriated fixed assets are booked down on behalf of the Treasury.

In case of the subject connection lines are used by another generation facility or are connected to the distribution system, then those lines will be deemed as a part of the distribution system and the connection lines are transferred to the related DistCo, provided that the opinion of Ministry of Finance has been taken.

The principles and procedures of transfer are described in Electricity Market Connection and Use of System Communiqué in the following way:

The cost of the connection lines is determined by the DistCo who was responsible in the region during the project approval phase.

In case of the subject connection lines are used by another generation facility or are connected to the distribution system, these connection lines are transferred to the related DistCo against its cost.

DistCo licensee enters into connection and use of system agreements with these licensees.

The cost determined by DistCo and expenses paid for expropriation is paid back to the related licensee by deducting them from distribution charge in scope of use of distribution system agreement.

The determination of connection line characteristics, project approval, survey and control, temporary acceptance and similar services are performed by the related DistCo licensee.

The costs of these services are paid by the generation licensees.

Box. EML‐Provisional Article 14b

Connection lines, which are approved by the Board of EMRA for direct connection to the feeder at the distribution voltage level of the switchyards without connection to any distribution center and which shall be installed only for connection of the related generation plant to the grid, shall be installed by related legal entities performing generation activities, and said facilities shall be operated exclusively by said legal entities when they are used exclusively for transmission of the production of the related generation plant. The connection and system utilization agreements on the subject shall be signed with Turkish Electricity Transmission Inc. Co. Immovables expropriated for said plants shall be registered to the name of the Treasury. In the event of said connection lines being used by another legal entity performing generation activities or being connected to the distribution system, they shall be transferred to the related distribution company subject to the positive opinion of the Ministry of Finance. Procedures and principles related with transfer of said plants shall be arranged in a communiqué to be published by the Authority.


3.3.2.2.2 CASE 2. Realization of distribution investments on behalf of DistCos for the connections of power plants

EMLR regulates the rules and procedures for the applications of the generation licensees for the connection and use of distribution grid. The conditions of acceptance and refusal on an application for connection of an IPP investor by DistCos are regulated in the article 38 of EMLR. TEIAS and/or DistCos have to meet the requests for connection applications other than those cases regulated in the said regulation.

If new distribution facilities are not in DistCos’ investment plan, or the timing of the new investment is not suitable for the investor, DistCo can ask the market participants to construct the connection lines and equipment on behalf of DistCo, or to finance their establishment. After the construction is completed and the power plant is commissioned, the cost of investment is going to be repaid to the power plant license holder via use of system fee. The technical, financial and administrative conditions take place in the connection agreement between the parties.

3.3.2.2.3 CASE 3. Construction of a direct distribution line between a power plant and the facilities of the customers

Installation of a direct line between the generation plant of a license holder and its customers and/or its affiliates or eligible consumers is allowed according to EML. However, those direct lines could be realized if a control agreement is signed between the license holder and the relevant DistCo. On the other hand, installation of a direct line at medium voltage level in distribution system could only be possible if the beneficial parties of that line have the ownership of the land at which the line will be erected.

In cases that the opinion of the relevant DistCo could not be created due to the extraordinary circumstances or if the proposed route and the connection point is not accepted by the applicant license holder, in case it is approved by the DistCo direct line can be constructed. All necessary plant and equipment for the installation and operation of the direct line shall be procured and paid by the license holder.

Private distribution direct line does not impede the shifting right of eligible consumers. Any eligible consumer, who wants to shift to another supplier, can be separated from the direct line. In case of installation of direct line; the necessary available capacity is kept by the distribution licensee if the consumer is separated from the direct line, and an amount for keeping the capacity available is paid to the distribution company by the legal entity engaging in generation activity.

Prices together with the principles and procedures required for the calculation of amount for available capacity are calculated by the distribution company, and shall be submitted to EMRA with tariff proposals at each tariff period, and are put in practice by the final decision of EMRA Board.

3.3.2.2.4 CASE 4. Construction and operation of a branching line at distribution level in order to be connected to the system by consumers

A branching line is described in Electricity Market Customer Services Regulation in the following way:

“All equipment (line, cable, pole, circuit breaker, metering system etc.) used to meet only the requirement of a consumer in order to be connected to the distribution grid and constructed by the consumer up to the distribution system connection point, and owned by the consumer”

In cases when the system connection conditions according to EMLR 38 are not suitable and connection can only be realized through a branching line, the preparation of the connection project is under the responsibility of consumer and all necessary information required to prepare the study of connection


project is supplied by the DistCo licensee. The finalized connection project is submitted to DistCo licensee for approval.

The DistCo licensee review the project within 5 business days and either approve the project or send back to the consumer for revisions. The consumer is informed about the causes of revision request in writing also. In case of approval of the connection project, a connection agreement regulating ownership, right of use, financing and connection conditions is executed between DistCo licensee and the consumer. However, if the objection of the applicant is not found appropriate by EMRA, or the suggested time period for realization of connection is unacceptably long for the applicant, then the connection can be made by a branching line to be installed and operated by the applicant.

The distribution licensee can meet new connection requests via using this branching line and its annexes by taking over such the corresponding part of this line from the applicant as that part became a commonly used facility.

If the owner or owners of the portion of branching line which turns out to be used commonly do not consent to transfer that portion to DistCo, that portion is expropriated. All kinds of costs in relation with this expropriation and transfer in a tariff implementation period are submitted to EMRA within the investment program and met through tariff revenues if approved by Board of EMRA.

Taking Over Branching Lines

• A transfer agreement will be executed between the DistCo and the facility owner. • The cost of the facilities to be taken over will be determined by using the specific investment unit

prices of capacity increase that approved by the EMRA Board for each of the DistCos. • For the facilities whose capacity increase unit prices are not existed, the lowest costs paid in the

same year for similar facilities in the scope of renewal or rehabilitation investments will be taken.

3.3.2.2.5 CASE 5. Construction and Operation of Consumer’s Transformers

Some consumers such as agricultural irrigation customers, industrial customers (workshops, factories, etc.) install and operate their transformers and connection lines in their property. The basic prerequisite of this implementation is that the owner of the facilities should be the only user connected to the facilities he owned. If and when other users are connected to such facilities, the commonly used portion of those facilities should be transferred to regional distribution company. In other words, such consumer transformers are not counted as a part of distribution system until they are transferred to the distribution company.

In addition to these, although it is the duty of DistCo, to install consumer transformers for multi‐house dwellings, malls where more than one consumer uses the facilities as the customer of DistCo, these transformers are installed by the third parties due to time limitation or budget constrains of DistCos. According to regulations, DistCos should have installed them or should take over them and operate. However, there are hundredths of this kind, still waiting for transfer roughly 50% of the Low Voltage transformer capacity is installed, owned and operated by consumers. Although this method is speeding up the realization of the connection applications and decreasing financial burden on the distribution companies, unplanned development and unnecessarily increased number of consumer transformers increases technical losses.

3.3.3 PSP in Distribution through the Organized Industrial Zones (OIZ)

Although not considered as a market player during the enactment of EML, OIZs are also the very promising actors of PSP implementations in Turkish power market.


In principal, the aim of OIZ is to prevent the growth of irregular industrialization and environmental pollution by giving emphasis to planned and systematic structures for industrialization.

Indeed, OIZ were operating since 1962 by the establishment of first OIZ in Bursa. In 1982, a regulation was issued for OIZ by the Ministry of Industry and Trade due to the increasing number of OIZs within the country. However, the increase in the number OIZs were continued during the following years, and speeded up especially in the second half of 1990s. This situation necessitated the regulation OIZ through a primary legislation.

The establishment law of OIZ (OIZ Law) was enacted before EML on 12th of April 2000. OIZ Law suggests that the infrastructure development and services related with infrastructure shall be provided by each OIZ legal entity. The reason for that arrangement was the continuation of public dominance in electricity and natural gas sectors at that time and due to the budgetary constraints, the lack of financial and administrative capacity of public to cope with the requirements of OIZs.

Before being a part of power market, distribution companies were wholesaling energy to OIZ at the connection point of OIZ without providing the necessary distribution services within the OIZ. And if, there was a generation within the OIZ, the rights of parties were settled with netting.

Recently, there are totally 264 OIZs established in Turkey while 149 OIZS are already in full operation and the rest is under construction and/or development. There is a separate management for each OIZ and the management committee is selected among the participants of the OIZ.

As of the end of 2010, electricity consumption of OIZs is roughly 15 TWh. About 8% of the electrical energy in Turkey is consumed by OIZs in 2010.

OIZ Law gives the right to OIZs for making expropriations if necessary for the sake of public benefit. In addition, OIZ legal entities have the right to sell or give the right of use of an area within the regional boundaries of OIZ to manufacturers or industrialists. Moreover, the rights of making investments at all kind of infrastructural requirements are belonging to OIZ legal entities.

The important clauses of the OIZ Law with respect to infrastructure are given below:

• Water, electricity, natural gas, social facility, treatment facility and similar operating revenues and participation revenues are included within the revenues of OIZs.

• The right and responsibility to establish and operate the infrastructure, and general service facilities, such as electricity, water, sewerage, natural gas networks, wastewater treatment facilities, roads, communication networks, and sports facilities; to realize their distribution and sales by buying them from public and private agencies; and to establish and operate production facilities with the aim of meeting the requirements of OIZs shall exclusively belong to OIZs.

• The organizations involved in OIZs shall be obliged to meet their infrastructure needs from the facilities of the OIZ. Infrastructure needs may not be met from another facility without the permission of the OIZ; and facilities may not be severally established with this aim. These organizations may not transfer, assign, or allocate the right to use infrastructure facilities allocated to them to other organizations.

As can be seen from the above listed clauses, OIZ Law gives exclusivity to OIZ legal entities while realizing actions with respect to infrastructural areas of electricity and natural gas. Consequently, as the ownership of the land in which the infrastructural investments are realized belongs to OIZ legal entities, the ownership of the distribution assets are belonging to OIZ legal entities accordingly.

Although the OIZs are authorized by the OIZ Law to invest and operate electricity system and allowed to distribute electricity in their zones; EML was not taking into account these activities. In other words there


was a contradiction between OIZ Law and EML. The exception of OIZs at the beginning within EML created some problems with respect to market implementations. Due to those problems, OIZs were incorporated into electricity market by the amendment made in EML in July 2005. Through this amendment, the electricity generation and distribution activities of OIZs are subjected to the condition of being a licensee granted by EMRA. In other words, OIZs became micro distribution companies acting in their defined boundaries. In addition, through the amendment in EML, the publicly owned OIZ distribution systems were transferred to respective OIZ legal entities.

The important clauses in EML with respect to this are given below:

• OIZ legal entities can perform distribution and/or generation activities within the approved borders in order to meet the demands of their participants upon receiving license from EMRA.

• To meet the electricity demand of their participants, OIZ legal entities are deemed as eligible consumers without taking into consideration their amounts of consumption. That is, each OIZ management is an eligible consumer on behalf of the participants.

• Internal distribution system of each zone is autonomously operated by the OIZ management. For this activity, the managements shall have OIZ Distribution License.

• Electricity demand of the participants is supplied by the OIZ management. The OIZ management procures energy and re‐distribute to the participants.

• The retail tariffs within an OIZ are regulated by EMRA and approved by the Board of EMRA. On the other hand, as differing from the DistCo privatizations, the ownership of the existing assets and new distribution assets provided by new investments within OIZ zone belongs to OIZs.

• If there are eligible consumers in the zone; and, if they wish to buy energy from their suppliers, they have to pay a distribution fee to the OIZ.

• OIZs can build and operate generation plants under their generation licenses.

The implementation details are regulated by the “Regulation on the Electricity Market Activities of Organized Industrial Zones”. In that regulation emphasis is given to the harmonization of the distribution activities given by OIZ with DistCos as far as possible.

In this framework, OIZ legal entities are obliged to provide electricity to the participants of the OIZ in a sufficient, good quality, low cost and environment friendly manner and deemed as responsible for the realization of necessary renovation and expansion investments for the distribution assets within the territory of OIZ. In addition, OIZ legal entities are also deemed responsible for the minimization of technical distribution losses and preventing of theft while providing electricity services to the OIZ participants in a non‐discriminatory manner and ensuring the open access and use of system rights of the participants.

However, by considering the non‐profit organization nature of OIZs, the tariff methodology for OIZ retail pricing depended on cost reflectivity only without presuming a profit margin for the OIZ legal entities.

As of the beginning of March 2012, 137 of 149 OIZ legal entities are granted as distribution licensee by the Board of EMRA.


There are no officially published data about the performance records of OIZs with respect to energy market. However, it is so clear from OIZ experience in Turkey that the regulation and auditing of market activities of multiple but different structures is a quite challenging task for regulators and standardization is almost impossible. Moreover, the fragmented structure is decreasing the attractiveness of distribution activity with respect to privatizations.

OIZ Distribution Tariff

The OIZ distribution charge is a total of the use of system charge and other service charges for the execution of distribution services within the OIZ. The method for the setting of tariff is based on the recovery of the cost of OIZ for the execution of service only and a profit is not considered. The tariff proposals of OIZs have to be submitted to EMRA for the approval of EMRA Board at each year until the end of October.

The following cost components are taken into account while setting of the distribution charges for OIZs:

• Investment expenditures, • Personnel expenditures, • Operation and maintenance expenses, • The component for correction of revenue differentials, • Service procurement expenses of OIZs from outside, • Cost of technical losses within the OIZs.

Box. OIZ Experience

The OIZ Law had been enacted before EML without taking into account the concept of liberalized electricity market. Therefore, conflict of authority problems have been aroused between the implementation processes of EML and OIZ Law during the initial years of energy market reform. Consequently, the energy market activities of OIZs have been incorporated into EML in 2005.

The mostly encountered problem before 2005 was related with the protection of consumer rights due to the exclusive rights given to OIZ managements with respect to procurement of infrastructural services including the sale of energy. Those problems became apparent especially after the starting of eligible consumer implementation on 3rd of March 2003. Particularly the OIZs having a vertically integrated structure comprising generation and distribution of electricity and natural gas were continuously created problems for the OIZ participants (eligible consumers) with respect to open access and the use of T&D grids.

On the other hand, regardless with the amount of energy consumed, all OIZs were accepted as eligible consumers while the energy market related activities of OIZs were incorporated into EML in 2005. However, this change negatively affected the loss and leakage target ratios of DistCos as those OIZs began to purchase energy from the competitive market through bilateral agreements.

Although, OIZs were granted also as distribution licensees according to EML, the concept is totally different from ordinary DistCos because OIZs are not profit making associations and accordingly not subjected to performance based price regulation by EMRA like the DistCos. This situation makes almost impossible to develop incentive based mechanisms in order to increase the quality of services given in the OIZs while the continuously increasing number of OIZs makes difficult the functions to be carried out by EMRA. Furthermore, these situations decreasing the economic benefits of DistCos while the uncertainty about the final total number of OIZs creating ambiguity on feasibilities with respect to distribution privatizations.


The distribution charges for OIZs are also differing according to the connection voltage (MV or LV) of the users within the OIZ.

4 RESULTS OF IMPLEMENTATION 4.1 Before EML

Because of the nature of PSP models before EML, the T&D facilities realized under PSP – except for the transformers and distribution lines constructed by third parties only for their own use – should be transferred back to the public companies either when they are commissioned or at the end of contract period, the facilities constructed under this model before EML cannot be addressed wholly. Only using the most recent official documents, the data below has been obtained.

When the implementation of EML started in September 3rd 2002 – after 18 months of preparation of secondary legislation and procedures, pre‐EML period outcome of PSP models in T&D were as follows:

Table 5. Private Share of Concessionary Companies in Transmission Lines

Source: TEIAS 2002 Statistics

Table 6. Private Contribution to the Transmission Transformers

Source: TEIAS 2002 Statistics

400 kV 220 kV 154 kV 66 kV

Public 13625.5 84.6 28999.9 549.3

Private 0.0 0.0 1657.2 121.4

Private (%) 0.0 0.0 5.4 18.1

Length of Transmission Lines (km)

400 kV 154 kV 66 kV

Number 111 815 40

Capacity (MVA) 18910,0 42163,9 457,8

Number 0 67 22

Capacity (MVA) 0 3283 318,8

Number 0 7,6 35,5

Capacity 0 7,2 41,1

Public

Private

Private

(%)

Number and Capacity of Transmission Transformers


Table 7. Public and Private Shares in Distribution Lines in 2002

Source: TEDAS 2002 Statistics

Table 8. Public and Private Shares in Distribution Transformers in 2002

(*) Concessionary Companies, (**) Transformers in the consumer facilities

Source: TEDAS 2002 Statistics

As mentioned above, the contract of one of the assigned companies, AKTAS Elektrik, was terminated in March 2002 by the Council of State and the distribution region (Anatolian side of Istanbul) was transferred back to public distribution company TEDAS.

Hence, the private contribution values given above do not contain the investments realized by AKTAS. According to 2001 Activity Report of AKTAS, it was claimed that a total of US$ 180,000,000 investment was realized in the assignment period of 1990 – 2001 for 8760 km of distribution line, 38602 transformers with a capacity of 2363 MVA.

4.2 After EML 4.2.1 Transmission

TEIAS is the sole owner and operator of the transmission system. Even if some connection lines are being constructed by private generation companies under EMLR article 38, they should be transferred to TEIAS after commissioning. On this scope, there exists a considerable investment by private parties. A total of 1,135 Connection Agreements have been signed between TEIAS and generation companies during the time period of 2003‐2012 at which the 281 of those agreements were signed according to the article 38 of EMLR and the total estimated cost of the transmission facilities constructed or under construction is TL818 million (roughly $455 million). As a comparison, 2012 investment budget of TEIAS is TL650 million.

Length (km) % Length (km) % Length (km) %

280,206.6 85.2 466,846.5 96.6 747,053.1 92.0

7,999.1 2.4 8,526.3 1.8 16,525.4 2.0

40,698.8 12.4 8,121.8 1.7 48,820.6 6.0

328,904.5 100.0 483,494.6 100.0 812,399.1 100.0

(*)Concessionnary Companies (**) Consumer's branching Line (***) Medium Voltage: betveen 33 kV‐ 6,3 kV

(****) Low Voltage : 400 Volt

PUBLIC DIST COMPANY TEDAS

PRIVATE DIST. COMPANIES (*)

THIRD PARTIES (**)

TOTAL

Medium Voltage (***) Low Voltage (****) TOTAL

number % Power (MVA) %

145,456 58.1 45,187.8 57.8

3,118 1.2 837.7 1.1

101,734 40.6 32,155.0 41.1

250,308 100.0 78,180.5 100.0

PUBLIC DIST COMPANY TEDAS

PRIVATE DIST. COMPANIES (*)

THIRD PARTIES (**)

TOTAL

TRANSFORMER


4.2.2 Distribution

The amount of investments realized by public companies gradually reduced in line with privatization program. The graph in Fig. 4 below shows this decrease. As the privatization continues, there will be further decrease.

Fig. 4. Change in public sector distribution investment

Source: TEDAS Annual Report 2010

The situation of distribution assets operated by public and private sector parties and also the status with respect to ownership by the third parties after EML has been developed as follows:

Table 9. Development of Distribution System Lines and Transformers

.

Source: TEDAS Statistics

The development of ownership of distribution line and transformers are shown in Fig. 5 and Fig. 6 respectively.

0,0

200,0

400,0

600,0

800,0

1000,0

1200,0

2008 2009 2010

Million $

Public distribution investments

OWNERSHIP

YEARS

Lines&Cables (km)

Transformers (MVA)

Lines&Cables (km)

Transformers (MVA)

Lines&Cables (km)

Transformers (MVA)

2002 747,053 45,188 16,525 838 48,821 32,1552003 755,346 46,783 14,129 797 49,027 33,4202004 778,222 47,764 14,439 1,011 49,732 35,2742005 810,311 49,892 14,577 1,012 55,615 38,3522006 824,739 51,071 15,036 1,018 57,204 41,7362007 846,755 53,382 14,966 1,027 61,004 46,0472008 808,604 52,830 72,642 3,861 63,946 49,7892009 628,168 44,546 274,362 14,280 66,708 52,256

Public Private Third Parties


Fig. 5 Development in Ownership of Distribution Lines

Fig. 6 Development in Ownership of Distribution Transformers

The share of private distribution companies is increasing in parallel with the privatization process. In fact, as of today, the share of private distribution companies is much bigger (at least twice as big as the values of 2009) and the share of public is much smaller. There was only one private company in 2007. One region was privatized in 2008 and 3 more in 2009. The number of privatized regions was only 5 at the end of 2009, whereas that number is increased to 13 including 3 companies having existing contracts as of 2012. However, since the lack of officially published statistics after 2009, exact figures could not be provided.

64,8

28,3

6,9

0,0

10,0

20,0

30,0

40,0

50,0

60,0

70,0

80,0

90,0

100,0

2002 2003 2004 2005 2006 2007 2008 2009

Distribution Lines Ownership (%)

PUBLIC Private Dist.Companies Third Parties

40,1

12,9

47,0

0,0

10,0

20,0

30,0

40,0

50,0

60,0

70,0

80,0

90,0

100,0

2002 2003 2004 2005 2006 2007 2008 2009

Distribution TransformersOwnership (%)

PUBLIC Private Dist. Companies Third Parties


As can be seen from the figure above, an important portion of the transformer capacity is owned by third parties such as industrial companies, factories, workshops, farms, big commercial companies, etc. However, this situation cannot be attributed to a planned approach of PSP; on the contrary, it resulted incidentally from the reluctance by public distribution companies to enter into the work load and additional costs. The consumer transformers (high voltage to low voltage) at the consumer’s facilities are generally procured, installed and operated by the consumers themselves.

It is expected that the dominance of third parties’ in ownership will reduce in time by following the completion of all distribution privatizations. Indeed, the commonly used portions of lines shall be transferred to DistCos and the new assets will be realized by DistCos also according to the legislation.

On the other hand, share of the total number of consumers and their consumption served by public and private distribution companies changed considerably. The development can be seen from Fig. 7 and Fig. 8.

Fig. 7 The change in consumed energy by the consumers of Public and Private Distribution Companies


94,51%

75,96%

56,46% 53,82% 49,55%

5,49%

24,04%

43,54% 46,18% 50,45%

0,00%

20,00%

40,00%

60,00%

80,00%

100,00%

120,00%

2008 2009 2010 2011 2012

DistCo Privatization ‐ Consumption

Public Private


Fig. 8 The change in the number of consumers served by Public and Private Distribution Companies


5 OPERATIONAL PERFORMANCE OF PRIVATIZED (OR PRIVATELY OPERATED) T&D ASSETS

Since the privatization of the distribution business could only start in 2009 (although the process started earlier, due to delays and cancellations actual transfers of the assets started in 2009) and due to gradual transfer process in 2009‐2011 period, a meaningful PSP occurred only in the last two years of this period. Therefore it is not possible to make a general realistic assessment of the gains and/or shortcomings of the privatization.

Loss Reduction

In addition to reducing the investment burden on the public sector, an important gain expected from distribution privatizations is the reduction of loss and theft ratios to reasonable levels throughout the country.

Essentially, the most desired gain at the first stage is getting under control theft through the implementation of necessary measures by the private operators. In order to create an incentive to private DistCos, additional revenues gained due to the overreach of the determined reduction targets of loss and theft are given to DistCos by EMRA.

However, if the DistCo cannot ensure the determined reduction targets, the DistCo is not allowed to reflect the additional cost to the tariffs. In addition, in order to benefit from this incentive, DistCos should also cope with the technical losses – especially in the distribution regions where the total loss and theft ratio is much smaller comparatively.

There is a big variation between loss and theft values between regional distribution companies. The average ratio was 17.7 % in 2009. In fact, such a big difference was the main reason for the


implementation of nation‐wide price equalization mechanism, allowing cross subsidization between regions.

The loss and theft ratios in the distribution regions for 2009 are shown in Fig. 9 below.

Fig. 9 Loss and Theft Ratios of the Distribution Regions (2009)

Source: EMRA

Since the privatization program was considerably delayed, the reduction targets set for the first tariff implementation period (2006‐2010) could not be met.

EMRA set new targets for 2011‐2015 period. The targets for some of the distribution regions are shown in Fig. 10 below.


Fig. 10 Loss and Theft Reduction Targets for Some Distribution Regions

Source: EMRA

It is expected that, if loss and theft reduction targets is met, there will be roughly 10 billion TL gain in 5 years.

Non‐payment and Collection

One of the expected benefits of distribution privatization –probably the most important one ‐ is the reduction in theft and increase in the collection rate. According to the information obtained from the distribution regions, after privatization, in the first operational year more than 90% of the overdue receivables were collected. Also the payment performance of the governmental institutions are said to be increasing.

According to the information received from DistCos, the collection rate in the privatized regions is over 95%. This shows that the low collection rate has mainly been a result of the weakness of public companies rather than high prices.

Payments to the Suppliers

The main suppliers of DistCos are EUAS and TETAS. Before privatization, total accumulated debt of TEDAS to EUAS and TETAS have reached to roughly 10 billion TL at 2008. Since EUAS could not collect the receivables, it could not pay sufficiently to gas and coal companies also. It was a deadlock situation and could only be solved by issuing a law for reconciliation between state owned energy companies in 2011. However, for privatized regions this problem does not persist anymore. After privatization the privatized DistCos are paying fully.

Service Quality

On the other hand, there is no reliable published official data to determine whether the operational performance has increased or not. The collection and performance based evaluation of this data set will only be possible after full implementation of Electricity Supply Security and Quality Regulation (“ESCQR”).

0

10

20

30

40

50

60

70

2011 2012 2013 2014 2015

Loss and

The

ft Ratio(%

)

Loss and theft reduction targets

Aras

Baskent

Dicle

Fırat

Toroslar

Vangolu


ESCQR determines the technical and commercial quality standards of supply services. Full implementation of this regulation will come in force in March 2013 depending on the establishment of the required technical infrastructure.

ESCQR reviews the service quality of the DistCos under three main categories.

• Supply continuity, • Commercial quality, • Technical quality.

After the full implementation of ESCQR, EMRA Board will determine a Quality Factor which will directly effect on revenue cap of DistCos. However, since distribution charge is collected per kWh distributed currently, DistCos are forced to serve their customers continuously. Hence, such a methodology is recommended for the countries which have not sufficient infrastructure to measure performance.

However, from the discussions with some private DistCos, improvements in service quality are reported. For example, in a relatively big distribution region, it is reported that:

• The number of interruptions decreased 11% and the average interruption duration is decreased 46% after taking over the region. That is between 2010 and 2011, there is a considerable improvement in System Average Interruption Duration Index (SAIDI) and System Average Interruption Frequency Index (SAIFI) .

• The maintenance activities are also enhanced. For example, the number of maintenance work/month is increased at least 5 times.

Efforts Being Planned and Undertaken by Private DistCos

In order to fulfill the requirements of supply continuity and quality requirements, to increase operational efficiency and to decrease technical and commercial losses, the private distribution companies are implementing technical and administrative measures. According to the information provided by DistCos:

Box. Regulation for Quality of Distributed Electricity

The regulation on Supply Continuity, Commercial and Technical Quality of Electricity on the Distribution System was enacted first in September 2006. The regulation contains the rules that should be followed by DistCos and principles and procedures in relation of implementation.

DistCos are obliged to measure and record the parameters related to commercial and technical quality. As well as the duration of interruptions and number of affected customers, the reasons should also be determined and recorded. DistCos are also obliged to issue the quality indexes in their web sites.

EMRA should give quality targets for each DistCo on the basis of implementation period. Then, EMRA should review these parameters of each DistCo and evaluate them. If the parameters are out of the determined tolerance limits, the revenue cap of the subject DistCo is revised.

However, since the measurement and recording process need the completion of a detailed technical infrastructure, the regulation is deemed to be implemented after 2013 when the infrastructure investments are to be completed.


• Most of the private DistCos claiming that the existing technical and customer records do not reflect the actual state of the regions. Therefore, most of them started to renew the records, measurement equipment and information systems in order to make realistic assessment of the region for the determination of the main sources of system faults, losses and technical problems.

• Billing, metering and registration systems are being improved. • They are establishing new call centers for fast responding consumers’ demands and claims. • They are implementing new maintenance and repair routings and more effective management

systems. • Some of the regions start to plan or implement SCADA and Geographic Information System (GIS)

in their regions. • As required by the legislation they have started to implement Automatic Meter Reading Systems

(AMR). • Some of the DistCos started new training activities for the improvement of institutional capacity.

These activities will certainly be helpful to improve the performance and increase effectiveness of operation and management. However, implementation of systems such as AMR, SCADA, GIS, and management information systems will take some time. It is expected that in a few years, after realization of such investments, the performance of DistCos will improve and it will be possible to measure the actual progress.

6 PROBLEMS OF IMPLEMENTATION Distribution

Both in the first and second tariff implementation periods between the years 2006 – 2010 and 2011–2015 respectively, there was no investment program based regional demand forecasts. Although there is national demand forecast, it cannot be said that reliable regional demand forecasts which should provide basis for investment planning exist. Hence, it is highly possible for over or under investment to result at the end of the tariff period.

The distribution tariffs have been approved by EMRA in line with the assumed investment programs of distribution companies in 2006 (before privatization) for 5 years. However, after privatization, private distribution companies claimed that the assumed investment program is not sufficient to meet the actual system expansion. Therefore the distribution companies asked for revision in investment programs, and it caused problems. The unrealistic investment program and the revenue requirement based on this program also lead the companies to force third parties to make their investments in order to be connected or to be supplied. The underlying reason for insufficient investment programs was the effort to keep the prices low. The investment allocations for second implementation period are increased. Naturally this increase is reflected in the distribution tariff.

DistCos were allowed to engage in generation business – provided that they obtain a generation license and that the amount of the annual electricity they generate does not exceed 20 percent of the total amount of electricity supplied for consumption in their region within the previous year. However, by the amendment of EML in 2006, 20% limit is removed. At the moment, DistCos can have generation licenses and can become self suppliers. DistCos are primarily expected to supply their electricity needs by entering into bilateral contracts. If the owner of the DistCo also owns generation plants, vertical integration (or ’self‐supply’ or ‘self dealing’) might be possible. Also, the DistCo would procure energy from bilateral contracts signed with affiliate generation companies. This is possible in the Turkish electricity market and is expected to increase after the privatization of DistCos is completed. Some recently privatized


distribution companies were acquired by investors which also have positions on the generation side. The ownership of a DistCo by a generation company offers opportunities of vertical integration. The Electricity Market Law allows generation companies to enter into affiliation with distribution companies provided that such affiliation should not confer exercising “control” on these companies as defined under the Law. However, the Competition Authority has decided that the distribution activity should be separated from generation and retail sale activities. Based on this decision, the Law has been amended to separate distribution and retail sale functions legally by the end of 2012. After the legal separation, the control and affiliation concept would need to be more fully defined.

After the implementation of the automatic pricing mechanism, which is based on cost‐base pricing of the services and goods, the end user electricity prices had risen considerably. This increase creates payment problems. The price levels are not at affordable levels for vulnerable customers. Lacking of a safety net or protection mechanism is a problem and may lead an increase in commercial losses (theft) and may decrease collection rates.

Another problem is the monitoring and auditing of realized investments. According to the current methodology, financial auditing of investments based on unit prices of significant distribution components determined by the EMRA Board. DistCos give the following year investment program in accordance with their approved budget and report the realization of these distribution components which are commissioned each year. Although it seems possible auditing investment with this methodology, considering the huge amount of investments in 21 DistCos , it is very hard to audit the physical realization of each component. This problem may be solved by changing the methodology to performance based auditing after the required technical infrastructure is completed. Similar risks are valid for OIZs as well.

Being in a transitional stage, the regulations are changing or revised frequently, in order to address the problems. This in turn, creates an uncertainty and can be considered a high regulatory risk.

On the other hand, establishment of OIZ without a long term planning constitutes a risk for DistCos. Industrial customers are most profitable costumers for DistCos. When these customers move into OIZ or new industrial customers are established in OIZ, this may reduce the revenue of DistCos.

An OIZ may be connected to transmission or distribution system. If it is connected to distribution system, OIZ’s participants pay distribution charge twice. For this reason, OIZs want to connect to transmission system. In that case, DistCos revenue reduces considerably and to collect the required revenue, distribution charge of the others users are needed to be increased.

Transmission

In the implementation of PSP in transmission, following problems have been encountered:

• The budget limitation of TEIAS causes the generators to invest in the scope of the article 38 of EMLR; in return long term repayment of the investments caused a burden on generation cost.

• Depending on the size of the facility, financing of transmission investments affect the feasibility of generation facilities negatively. If the required investment is only a fraction of the total generation investment, the problem is not very serious. However, if the required transmission investment is comparable with generation investment ( which can be for a power plant investment with small capacity), or if TEIAS requires the transmission facilities to be build not only for the generator’s facility but also for future generation investments ( for example, higher capacity transmission line or a substation with multiple feeders); then the investment cost of transmission becomes an important factor in the total investment cost, and it brings an additional burden on the investor.


• If common transmission facilities are to be used by more than one company, in the scope of the article 38 of EMLR, one of the generation licensees bears the responsibility of construction against TEIAS. Although the financing of the project is distributed among the licensees according to their generation capacities, the responsible licensee is bearing more risk than the others.

7 CONCLUSIONS, LESSONS LEARNED, AND RECOMMENDATIONS

PSP to TD activities in Turkey is implemented in different forms and degrees since the very beginning of electrification in the country. After a very short period of completely private ownership at the beginning, this situation gradually changed to a state owned monopolistic structure.

Leaving aside the very old methods, it can be said that except 2 small regions, there has been no private participation in the transmission business. This situation persists at least for the last 40 years. After the market reform, which suggests a national transmission system ownership and operation, PSP in those two regions were also ceased. This can be considered a correct approach, since the transmission system is the most important infrastructure for reliability and quality of supply. Furthermore an autonomous and impartial operation of the system, including non‐discriminatory access to the grids has an utmost importance for a well functioning competitive electricity market.

Can these important requirements be achieved with private ownership or operation?

Theoretically the answer is yes, provided that the owners and/or operators are technically capable and more importantly they are independent from other sector activities. The technical capability and efficiency in operation may even be better with private ownership. However, it is not so easy to achieve the impartiality, independence, and non‐discrimination even under very heavy regulatory control. That is why, in many countries there had been a continuous debate for ownership unbundling of the transmission from other activities. Turkey chose the right approach; from the beginning of the sector reform, a separate state‐owned transmission company was established. The reform process is continuing, and Turkey is still in a period of transformation. In this transitional period, introduction of private ownership or operation might increase the complexity of this delicate process. Possibly in the future, new models for PSP in transmission may evolve.


Box. Why Turkey Preferred the Integrated Transmission Model?

During the sector reform and restructuring process, Turkey took radical decisions. Once it has decided to unbundle the transmission related activities from supply, there was no reason to separate transmission system operation from transmission ownership. Separating those two might be preferred if Turkey want to preserve the utility concept and separate only system operation from ownership and keep the ownership with the vertically integrated TEAS. Instead, Turkey wanted to abolish the vertically integrated monopolistic structure and separated also state owned generation, trade and distribution activities with the intention to give up state involvement from generation, distribution and retail.

Even if the model with two companies (TSO and transmission company) could be a workable solution, it was not preferable at least from regulatory perspective. Those two activities are both regulated activities; two companies instead of one would increase the complexity.

If there are no historical, political, administrative and commercial reasons, separation of transmission ownership, maintenance and expansion activities from system operation may create difficulties. This will be more complicated with a fragmented regional transmission ownership. TSO is necessary to provide short term non‐discriminatory open access (use of system in everyday through trading arrangements); however, the market participants need also stable and fair access to the grid in long term also. This can only be achieved through connection agreements and use of system agreements with transmission network owner and operator. The technical condition of transmission grid is very important since it may drastically affect their ability to access and take part in the electricity market. Transmission grid owners have considerable possibilities (technical and administrative) to abuse their powers and adversely affect the open access regardless of ownership of transmission system; the TSO will operate the system in such a way that the network as a whole is used most efficiently. However, TSO and regulator should deal with company(ies) under separate ownership to ensure the non‐discriminatory access.

The problem will be more complicated if there are more than one transmission network owner. Lack of investment in a region is not only a problem for that region only. Similarly over investment in one of the regions will as well affect the power flows in other regions. The interconnection capacities and handling interconnection capacity allocations would create additional problems and complexities.

Unlike distribution, the transmission system congestions, faults and bottlenecks will affect the whole system. The operation of the system needs centralized decisions and centralized expansion planning. Independent of the transmission ownership, TSO and regulator should provide the rules and regulations in order to establish a sufficient transmission grid and efficient operation. Although market based transmission expansion mechanisms can be implemented, (which is not very common), central planning and central decision making mechanism is less complex and more cost effective.

Therefore, Turkey preferred integrated transmission business model and established a nation‐wide Transco (Transmission Company‐ TEIAS) responsible from transmission system operation and at the same time owning, maintaining and expanding the transmission grid. In this model, the coordination is easier, there is no tension between system operator and grid owner for the use of the transmission network, TSO is not operating or taking operational decisions on somebody else’s assets. TSO at the same time is responsible for maintenance and expansion of the grid, no separate agreements between TSO and transmission system owner. This is useful for coordination between transmission grid operation and maintenance, expansion and system operation.


The PSP in distribution however, followed a different track. Rooting from highly politicized municipality ownership time, political interventions in management, price control policies, insufficient budget allocations have resulted in an inefficient operational performance and low quality of service. Furthermore, starting from 1980s, in parallel with liberalization policies in almost all sectors, PSP in distribution was on the agenda.

The main model for PSP in distribution is privatization of the State‐owned regional companies operating the distribution systems, while the assets remain state‐owned. Today, the implementation of this model in Turkey is well underway, with half of the distribution system privately operated.

As it has been told, GoT have obtained approximately US$ 5.7 billion revenue from privatization of 13 distribution regions. However, as stipulated in the Strategy Papers, the main reason for distribution privatization was not and should not be “getting some revenue for the state budget”. The expected benefits should be improvement of the performance, increase in the service quality, ensuring the

Box. Why the State‐owned TSO?

Once the Transco model is selected, and the ownership of the grid is combined in the same company, the integrated activities of TSO started to be carried by TEIAS. TEIAS, is completely out of the generation and supply activities.

According to EML, the transmission is a regulated activity that provides the conditions for competition and must be treated separately and funded independently. As stipulated in EML:

“The Turkish Electricity Transmission Co. Inc. will perform international interconnection activities in line with the decision of the Ministry and will provide transmission and connection services to all system users including eligible consumers connected and/or to be connected to the transmission system, without discrimination, in accordance with provisions of Grid Code and Transmission License”

Once the integrated model is selected and State owned company is assigned, the PSP in transmission activities are limited.

It can be argued that, private ownership would increase the efficiency in operation due to more dynamic management, more flexible decision making when compared with the heavily regulated and limited state owned company. But at the same time private ownership would bring the issues such as impartiality, coordination, investment planning etc. Those issues could be dealt with regulatory arrangements and close monitoring. However, during a massive transformation process, it would also make the transition more complex. Furthermore in Turkey, unlike distribution sector, the institutional capacity and competence of the transmission company was better and transmission company (old TEAS) was relatively successful. In a country like Turkey, where there is a huge demand growth and therefore need for huge generation and transmission investments, the selected model is simpler and effective. As the growth rate decreases and as the need for fast transmission expansion investments reduces, and as the market becomes more mature, the model can be reconsidered. In the future, there may be new structural changes to enable wider PSP into transmission, such as separation of TSO and network ownership and privatization of the Grid Company, or establishment of regional grid companies. However, TSO (independent system operator) concept should certainly be maintained and the issues related with network expansion and open access should be carefully assessed and solved. However, for the time being, such models will make the transition more complex and there would be unnecessary conflicts and problems.


operational efficiency, and making of the necessary expansion and renovation investments by private parties without creating burden on state budget and contingent liabilities for the public and ensuring the creditworthiness of distribution companies for attraction of new generation investments.

Since there have been serious delays and U‐turns in the process, a meaningful privatization only occurred in the last 2‐3 years. Therefore, it is not possible to assess the outcomes. The success of the PSP can only be possible with a consistent implementation of cost effective pricing, better investment projections, and better regulatory monitoring.

The unbundling of distribution activities from retail and careful regulatory oversight for self‐dealing will enhance the effective competition in the market.

There are still some lingering problems impeding the successful implementation of the Turkish privatization model in distribution. However, it is expected that these “teething problems” will not persist for too long.

The previous experience shows that, first and foremost, a strong and credible legislation is a necessary condition to employ the regulatory system as a means of securing private participation in the industry.

Main reason behind the unsuccessful attempts for insufficient PSP before 2001 was the everlasting discussions and arguments about the legal framework for PSP in energy sector (recall the discussions in section 1 and 2 about concession, assignment, private law contracts, administrative contracts etc.). Therefore, above all, the legal framework should be clearly defined and a consensus of related parties must be reached on the methods with which a “public service” can be provided by private sector.

Also the ownership issue with respect to restructuring and privatization should be solved. Since the assets in T&D grids are used for a public service, and since there is no other alternative, it can be claimed, as has been the case in Turkey, that those assets cannot be subjected in private ownership. This interpretation naturally depends on the legal system of countries. However, if interpreted like in Turkey, in order not to cause legal problems, the PSP model like TOOR can be implemented. Although asset ownership increases credibility of the private companies and reduces the risks, the acquisition of long term operational rights can reduce uncertainty and can be used as a compromise.

The regulatory framework should be prepared by taking into account the future developments and should not be changed frequently. To attract PSP, the regulations should be as clear, consistent and simple as possible. However, at the same time, the balance between public benefit and incentives should be carefully considered. One of the reasons for unsuccessful distribution privatization program before 2001 was the claims against the tendering process, asserting that public benefit is not sufficiently taken into consideration by leaving most of the risks to public. Therefore, the process should be prepared and implemented carefully; otherwise the cost of failure can be huge. In addition to loss of time, claims for damages in legal proceedings at international arbitration cases may result substantial payments.

If a country plans to liberalize the electricity market, implementing concession or assignment methods or long term contracts inherited from previous regime make the transformation complex and costly. If implementing such models is preferred, as an intermediate step, before liberalization, the related contracts should have an article about full compliance with the further legislative environment. That is, the concessionary or assigned companies should have to comply with the changes in the legal structure and accept revisions to their contracts accordingly to adapt to the new structure.

If operational rights of a distribution region are planned to be transferred to a private sector entity, certain conditions should be met in order to ensure the continuity of the operation and the realization of the required investments. The actual situation of the region should be determined with the attendance of the subject private company and all parties should agree on the details. Otherwise, using the information of


the public company about the region will usually be misleading since public companies try to show the situation in the region better than it actually is. In fact one of the claims of the new operators of distribution regions is the insufficient and/or unrealistic information about the technical and commercial characteristics of the regions.

Distribution is a regulated activity and, without the retail business, has predictable revenue. Since there is no competition for the wire business, the risks as well as profit opportunities are limited. That is why, the “attractiveness” of PSP in transmission and distribution is also questioned. Also there are so called good regions and bad regions. The size of the regions and economies of scale is an important factor to attract PSP. If regions are small, then strategic investors may not be interested in participation and only small local investors will be in the market. However, in order to achieve the targets aimed for PSP, experienced and financially capable participants are necessary. Therefore, when determining the distribution region boundaries, the economies of scale should be taken into consideration. Also, during the privatization tendering process, the steps should be carefully determined or else so called bad regions cannot be privatized. If competition is aimed in the market and if OA is to be implemented, then it would be a mistake to give up unbundling of distribution from retail business in order to increase “attractiveness” for the privatization. It should be noted that privatization is not liberalization, it is only a tool. If liberalization and competition is aimed, the methods hindering the competition should not be used for the sake of “selling the assets and increase revenues”.

For an effective and successful PSP, the selection of private participants is vitally important. Weak and inexperienced participants may ruin the process and may cause public discontent because of insufficient service quality; this may create regulatory problems and may even be a problem for successful market implementation. Since distribution is a vital public service, it would not always possible to stop the service, and it is not easy to improve the performance in a short time. Although there will be a regulatory monitoring, it would be very difficult to enforce regulatory correction methods for a service which is continuously needed. Therefore, from the beginning, the capacity of the participant should carefully be evaluated and the technical and administrative experience and capacity should be the main factor for selection, rather than the price submitted in the privatization tenders.

The recent distribution privatization tenders showed that, unrealistically high price offers in the tendering process are not a real success but rather an indication of danger. As explained in previous sections, (see Table 4 in Section 2). The companies offered very high prices, assuming imaginary returns which cannot be justified with feasibility studies. So, in the financing stage, careful evaluation showed that it is not possible to get enough revenue from the business to recover the price of those huge bids. It shows that, sometimes, some investors could not make realistic evaluations and may have even taken high risks. However, the risk is not only on them; such behaviors create risks for the entire system. That is why the offered price should not be the only or main decision criterion.

It is important to note that, practically no foreign strategic investor was interested in the tendering process, probably because of the global financial crisis, or those who attended the process together with local companies did not bid such high prices. In that stage, the unknown tariff parameters and uncompleted regulation about tariff setting were also important factors for foreign investors and probably those risks caused them not to attend the bidding process. So, it is recommended that before starting privatization process, related regulation and parameters should be finalized.

Cost based pricing is important for attracting PSP and for creating a well‐functioning market. However, especially for countries like Turkey, where the demand increase rate is very high and substantial generation, transmission and distribution expansion investments are required, it is necessary to protect low income consumers against price increases.


The connection facilities constructed via PSP models in transmission facilitate the construction of the generation facilities on time, but at the same time create uncertainties and financial burden on generation companies. Therefore, transmission expansion planning should be ready and the financial capacity of the transmission companies should be sufficient to cope with the investment needs.


APPENDIX 1: TRANSMISSION SYSTEM The transmission system is the group of facilities starting from generation units to distribution network and transmitting energy at the level of High Voltage (HV) and Extra High Voltage (EHV).

In Turkey the TSO model is implemented. That is, the ownership and operation of the grid are integrated in the same single State owned entity TEIAS, which is responsible for transmission system operation and maintenance, planning of new transmission investments, and construction of new transmission facilities to meet the needs of market participants. TEIAS is also responsible for the preparation of transmission planning as defined in the Grid Code, and preparation of transmission system investment programs.

Except the special procedure for the transmission investments being carried by private generation companies as defined in the previous sections (procedures according to Article 38 of EMLR), all transmission investments should be realized by TEIAS.

As shown in the figure below, the Turkish power grid is a strongly meshed and interconnected national grid. It consists of the lines and substations at the voltage levels of 400, (220), 150, and 66 kV. The total length of transmission lines was about 48,760 km by 2010.

Figure. Transmission Map of Turkey

(Source: TEIAS)

The transmission system is being managed via 9 regional dispatching centres (Adapazari, Carsamba, Keban, Izmir, Golbasi, Ikitelli, Erzurum, Cukurova and Kepez) coordinated by the National Load Dispatch Centre in Ankara at Golbasi. Additionally there is one emergency national control centre.

Operation of the power system is carried out by SCADA and Energy Management System (EMS) software. The SCADA system covers 380 kV lines, substations, power plants and some important 154 kV centres and power plants with capacities higher than 50 MW. The total number of centres connected to SCADA‐EMS system has reached to 310. The system operator can manage all system studies necessary for quality, daily operating programs and system frequency control.


The transmission line and substation capacity of TEIAS is summarized in the table below.

Table. TEIAS Transmission Line and Substation Information

Voltage level (kV)

Transmission lines (km)

Cables (km)

Transformer total MVA

Number of transformers

Number of substations

400 15.559 28,7 37.870 197 77

220 84,5 0 330 2 2

154 32.608 179,3 61.035 1065 513

66 508,5 3,2 617 53 14

Total 48.760 196,4 99.852 1317 606

Source: TEIAS

The transmission system design characteristics and operation principles in Turkey are in accordance with Electricity Market Grid Regulation (the Grid Code) and ’Electric Transmission System Supply Reliability and Quality Regulation .’.

Grid Code

Grid Code provides the protocol that governs the relationship between the power system operator and power system users and to define the roles and responsibilities of the parties. These responsibilities focus on the safe, secure and economic operation and planning of the power system, and compliance with relevant statutory and license conditions.

Grid Code covers the liabilities of TEIAS, the users of the transmission system and other users who are connected to the distribution system but affect the transmission system and the facility design and operation rules they should comply with, and the principles regarding the provision of technical data required for transmission system planning through balancing supply and demand and for the operation of the transmission system in line with the balancing rules.

Grid Code is divided into planning code, connection conditions, set of operating codes, scheduling and dispatch code, data registration code, general conditions, metering code sections.

Electric Transmission System Supply Reliability and Quality Regulation

This regulation provides rules for planning, design and operation of transmission system. It covers also the technical requirements for the substations to be constructed for power plants. TEIAS, generation companies and other system users are obliged to follow the rules and principles stated in this regulation in order to have a reliable power system. It covers planning and design principles, the criteria for supply reliability and defines operational principles.


APPENDIX 2: DISTRIBUTION SYSTEM The distribution grid consists of distribution facilities with voltage level of 36 kV and below. Distribution system covers the network starting from the transmission interface or from the connection points of generation plants which are directly connected to the distribution grid and ends at the consumer interface at low or medium voltage level.

The voltage levels are usually consisted of 33 kV, 15.8 kV, 10.5 kV, 6.3 kV and 3.3 kV while the low voltage network is working on 0.4 kV level.

Since its establishment in 1994, electricity distribution and retail services are provided by TEDAS. Organization of TEDAS was composed of 7 subsidiaries and 61 enterprises until the decision of High Planning Council in April 2004 for the privatization of TEDAS.

Since then, as shown in the figure below, the distribution regions were re‐defined by dividing Turkey into 21 regions and establishing 20 distribution companies that started to operate on 1st of March 2005 . All of those 20 companies have held their respective distribution and retail licenses on 1st of September 2006 from EMRA that are valid for a 30‐years period.

Figure. 21 Distribution Regions

Source: Privatization Administration and EMRA

The DistCos have two licenses:

Distribution License for operating distribution system in their regions,

Retail Sale License for supplying electricity to non‐eligible consumer in their region.

At the moment, DistCos have separate accounts for each of the activity. However, after 2012 there will be legal unbundling (different companies for each activity).

The governing regulations for the distribution and retail services are Distribution Grid Code, Consumer Services Regulation and Electricity Supply Security and Quality Regulation:


• Distribution Grid Code defines the responsibilities of distribution system operators and distribution system users, rules and procedures for planning, design and operation of the distribution system. It also describes the rules and procedures to be followed for connection of consumers and generators to the distribution grid.

• Consumers Services Regulation determines the service quality standards for uninterruptible supply; the rules and procedures to provide energy and/or capacity under competitive environment, measurement and billing, consumer relations and complaints; the rights and obligations of the consumers.

• Electricity Supply Continuity and Quality Regulation determines the technical and commercial quality standards of supply services. Full implementation of this regulation will come in force in March 2013 depending on the establishment of the technical infrastructure.

As a distribution licensee, DistCos operate and maintain the distribution grid, carry out the necessary grid investments. They are obliged to provide non‐discriminatory electricity distribution and connection services to all system users including eligible consumers connected and/or to be connected to the distribution system as specified by provisions of their licenses and the Electricity Market Distribution Regulation.

The distribution licensees prepare distribution investment plans for new distribution facilities to be constructed in the regions specified in their licenses and shall construct, operate, develop, repair and maintain the new distribution facilities in compliance with the applicable legislation.

In order to finance the investments, the distribution companies are compensated for investment on regulatory assets at a rate based on the weighted average cost of capital (“WACC”) method. For the 2011‐2015 period, total investment budget of all distribution regions was approved by EMRA as roughly 9 billion TL.

The distribution system capacities are given in the table below.

Table. Transformers and Installed Capacities of Distribution System

SECONDARY V. 15,8 kV 10,5 kV 6,3 kV OTHERS 0,4 kV TOTAL

PRIMARY V.

33 kV NO. 466 232 405 76 288875 290054

POWER (MVA) 4176 3645 2732 1000 80282 91835

15,8 kV NO. 5 1 30462 30468

POWER (MVA) 8 1 9264 9273

10,5 kV NO. 7770 7770

POWER (MVA) 6650 6650

6,3 kV NO. 10 6793 6803

POWER (MVA) 157 3107 3264

DİĞER NO. 4 4

POWER (MVA) 60 60

TOPLAM NO. 466 232 410 91 333900 335099

POWER (MVA) 4176 3645 2740 1218 99304 111082

background paper international experience … paper international experience with private sector...

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