market design options of kazakhstan and …activity completion report market design options of...

ACTIVITY COMPLETION REPORT

MARKET DESIGN OPTIONS OF KAZAKHSTAN AND ITS ROLE IN THE CENTRAL ASIA REGIONAL ELECTRICITY MARKET

(89.KZ, 107.KZ,108.KZ&117.UZ)

INOGATE Technical Secretariat and Integrated Programme in support of the Baku Initiative and the Eastern Partnership energy objectives

Contract No 2011/278827

A project within the INOGATE Programme

Implemented by:

Ramboll Denmark A/S (lead partner) EIR Development Partners Ltd.

The British Standards Institution LDK Consultants S.A. MVV decon GmbH ICF International

Statistics Denmark Energy Institute Hrvoje Požar

Document title Activity Completion Report “Market Design Options of Kazakhstan and its Role in the Central Asia Regional Electricity Market” (89.KZ, 107.KZ,108.KZ&117.UZ)

Document status Final

Name Date

Prepared by Emmanuelle Rault, Konstantinos Perrakis, Nikos Tourlis, Nikos Patsos and Mariyash Zhakupova

04/04/2016

Checked by

Nikos Tsakalidis Adrian Twomey

06/04/2016

Approved by

Peter Larsen 23/05/2016

This publication has been produced with the assistance of the European Union. The contents of this publication are the sole responsibility of the authors and can in no way be taken to reflect the views of the European Union.

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Acronyms

APX UK APX Power UK (formerly named UKPX) AREM Agency for the Regulation of Natural Monopolies, mainly

regulating tariffs AS Ancillary Services ASECA Automated system of electricity control and accounting ATS Trade system administrator AZ K The Agency for Competition Protection which monitors

operation of competitive markets CAPS Central Asian Power System CCA Competition capacity auctions CCGT Combined Cycle Gas Turbine CCS Carbon Capture and Storage CDA Capacity Delivery Agency CDC Energia Central Dispatch Centre (of Central Asia) CHP/DH Combined Heat and Power/ District Heating CHPP Combined Heat and Power Plant CIGRE Council on Large Electric Systems CIS Commonwealth of Independent States COGEN Cogeneration Association of Europe CONE Cost Of New Entry CPM Capacity Payments CRE Energy Regulatory Commission of France DC Direct Current DECC Department of Energy and Climate Change (UK) DG Directorate General (of the European Commission) DG-TREN Directorate General for Transport and Energy DPM long-term capacity supply agreements (in their Russian

abbreviation) DR Demand Response DSR Demand Side Response E.ON European holding company based in Düsseldorf, North Rhine-

Westphalia, Germany EC European Commission EDF Electricite de France EEX European Energy Exchange AG, Germany's energy exchange ENTSO European Network of Transmission System Operators EOM Energy Only Market EPA Environmental Protection Agency EPC European price coupling EPEX SPOT SE European Power Exchange is an exchange for power spot

trading in Germany, France, Austria, Switzerland and Luxembourg

ERGEG European Regulators Group for Electricity and Gas

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EU European Union EU IEM European Union Internal Electricity Market EUR Euro EWEA European Wind Energy Association EXAA Energy Exchange Austria FERC Federal Energy Regulatory Commission (of the US) GW Giga Watt HHI Herfindahl-Hirschman Index HPP Hydro Power Plant IAEE International Association of Energy Economics IEM Internal Electricity Market IEM Energy management system INOGATE Technical Secretariat & Integrated Programme in support of the

Baku Initiative and the Eastern Partnership energy objectives” project, funded by EC/Europeaid

IPE International Petroleum Exchange, now ICE Futures (since 2005) ISO Independent System Operator ISO-NE ISO New England (US) IT Information Technology ITO Independent Transmission operator ITS INOGATE Technical Secretariat JSC Joint Stock Company KARNM Kazakhstan’s Agency for Regulation of Natural Monopolies KEA Kazakhstan Electricity Association KEGOC the Transmission System Operator -, which includes the

National Dispatch Center and serves as the system operator of the National Electric Power System

KOREM The Kazakhstan Wholesale Energy and Capacity Market Operator, which operates centralized trading platform for the short-, mid-and long-terms trading

KREM An alternative acronym for KARNM (see above) KZ The Republic of Kazakhstan LLC Limited Liability Company LMP Locational Marginal Pricing LPX Leipzig Power Exchange GmbH LSE Load serving entities (decentralised) LSE Load Serving Entities LTA Long term agreements MCP Market Clearing Price MINT Ministry of Industry and New Technologies (re-organised to

Ministry of Energy) MIP Mixed Integer Program MOPR Minimum Offer Price Rule MRC Multi Regional Coupling MISO Midcontinent ISO (US) MW Mega Watt MWh Mega Watt Hour

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NOME Law Nouvelle Organisation du Marché de l'Electricité Law NordPool The single financial energy market for Norway, Denmark,

Sweden, Finland, Estonia, Latvia, Lithuania, Germany and the UK.

NREL National Renewable Energy Laboratory (US) NWE North west Europe NYISO New York ISO OHPL Overhead Power transmission lines OTC Over The Counter (trading) OU Ownership Unbundling PDC Power distribution company PEGAS Pan-European Gas Cooperation PJM PJM is a regional transmission organization (RTO) that

coordinates the movement of wholesale electricity in all or parts of 13 states and the District of Columbia.

POLPX Polish Power Exchange PowerEX Marketer of wholesale energy products and services in western

Canada and the western US, and a growing niche player in other markets across North America

Powernext SA Powernext S.A. designs and operates spot and futures exchanges for the trading of power, gas, and emissions contracts in the European energy sector.

PV Solar Solar Photovoltaics PXs Power Exchange(s) RAO UES Unified Energy System of Russia ( an electric power holding

company before its restructuring) RCC RES Renewable Energy Sources RM Regulated market RSE Regional State Enterprises RTE Transmission System Operator of France RTO Regional Transmission Operator SEM Single Electricity Market SO System Operator ST Steam Turbine TM Target Model TTF Dutch gas trading exchange TYNDP Ten Year Network Development Plan UES Kazakhstan’s Unified Energy System UES CA Unified Energy System Of Central Asia UK United Kingdom UKPX United Kingdom Power Exchange UNDP United Nations Development Programme US United States USA United States of America USSR Union of Soviet Socialist Republics UZ Republic of Uzbekistan

https://en.wikipedia.org/wiki/Norway

https://en.wikipedia.org/wiki/Denmark

https://en.wikipedia.org/wiki/Sweden

https://en.wikipedia.org/wiki/Finland

https://en.wikipedia.org/wiki/Estonia

https://en.wikipedia.org/wiki/Latvia

https://en.wikipedia.org/wiki/Lithuania

https://en.wikipedia.org/wiki/Germany

https://en.wikipedia.org/wiki/The_UK

https://en.wikipedia.org/wiki/The_UK

https://en.wikipedia.org/wiki/Canada

https://en.wikipedia.org/wiki/Electric_power

https://en.wikipedia.org/wiki/Holding_company

https://en.wikipedia.org/wiki/Holding_company

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VAT Value Added Tax VG Variable Generation VOLL Value-Of-Lost-Load VPP Virtual power plants

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1 Contents 1 PART 1 – EUROPEAN COMMISSION .............................................................................................. 12

1.1 Background ........................................................................................................................... 12

1.2 Essence of the Activity .......................................................................................................... 12

1.3 Key Findings .......................................................................................................................... 14

1.4 Ownership and Benefits of the Activity ............................................................................... 15

1.5 Recommendations ................................................................................................................ 15

1.6 Challenges Faced ................................................................................................................... 17

1.7 Impact Matrix ....................................................................................................................... 17

2 PART 2 - BENEFICIARIES ................................................................................................................. 19

2.1 Executive Summary ............................................................................................................... 19

2.2 Background ............................................................................................................................ 26

2.2.1 Objectives of the study, key findings and recommendations ....................................... 26

2.2.2 Methodology and outputs ............................................................................................. 27

2.2.3 Limitations and further work......................................................................................... 27

2.2.4 Structure of the report .................................................................................................. 28

2.3 ELECTRICITY MARKETS .......................................................................................................... 29

2.3.1 Concepts in the new market structure .......................................................................... 29

2.3.1.1 The rationale of preserving networks as natural monopoly ..................................... 29

2.3.1.2 Unbundling ................................................................................................................ 30

2.3.1.3 Trading in wholesale electricity markets ................................................................. 31

2.3.1.4 Bilateral contracts ..................................................................................................... 31

2.3.1.5 Power Pools or Electricity pools ................................................................................ 32

2.3.1.6 Power exchanges ....................................................................................................... 33

2.3.1.7 Balancing markets ..................................................................................................... 36

2.3.1.8 Coordination of electricity markets ........................................................................... 36

2.3.1.9 Short Term Wholesale market models ...................................................................... 37

2.3.1.10 Determination of the wholesale price of electricity ............................................. 40

2.3.2 Electricity markets liberalisation in the EU ................................................................... 40

2.3.2.1 Drivers of liberalisation and its evolution in the EU .................................................. 40

2.3.2.2 The latest step of harmonisation of the EU Internal Electricity Market by means of the 3rd Package ......................................................................................................................... 43

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2.3.2.3 Unbundling in the notion of the EU legislation ......................................................... 44

2.3.2.4 National Regulatory Authorities ................................................................................ 45

2.3.2.5 Agency for Cooperation of Energy Regulators .......................................................... 46

2.3.2.6 Cross-border cooperation ......................................................................................... 46

2.3.3 Integration of national markets – the EU Internal Energy Market ............................... 50

2.3.3.1 Regulation 1228/2003 and Directive 2003/54 .......................................................... 50

2.3.3.2 Regional Initiatives within the EU ............................................................................. 51

2.3.3.3 The 3rd Energy Package (2009) ................................................................................. 57

2.3.3.4 The Target Model for the EU electricity market ....................................................... 58

2.3.4 Coordinated Transmission planning .............................................................................. 60

2.4 THE ELECTRICITY MARKETS IN KAZAKHSTAN ........................................................................ 63

2.4.1 Electricity sector overview ............................................................................................ 63

2.4.1.1 The legal framework governing the electricity sector in Kazakhstan ....................... 63

2.4.1.2 Public authorities’ functions and powers in the area of electricity market operation and energy development .......................................................................................................... 63

2.4.1.3 Recent developments as regards the legal framework governing the electricity sector 64

2.4.1.4 Competition law and regulatory specificities in Kazakhstan ..................................... 64

2.4.2 The Kazakhstan’s Wholesale Electricity Market ............................................................ 64

2.4.3 Key challenges of the power sector in Kazakhstan ....................................................... 66

2.4.4 Gap analysis on the legal basis governing the Kazakh and EU electricity markets ....... 67

2.4.4.1 Key provisions of the EU Electricity Market .............................................................. 69

2.4.4.2 Gap Analysis .............................................................................................................. 72

2.4.5 Prospects for the development of the future electricity market in Kazakhstan ........... 76

2.5 ELECTRICITY SECTOR INVESTMENTS UNDER A LIBERALISED MARKET REGIME .................... 78

2.5.1 Background .................................................................................................................... 78

2.5.2 Investments in generation & Capacity support schemes .............................................. 79

2.5.2.1 New generation capacity in liberalized markets ....................................................... 79

2.5.2.2 Energy-only markets versus markets with capacity mechanisms ............................. 79

2.5.2.3 Capacity support schemes ......................................................................................... 80

2.5.2.4 The EU experience ..................................................................................................... 87

2.5.2.5 Experience in the USA ............................................................................................... 96

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2.5.2.6 Annual cost of existing capacity mechanisms ......................................................... 101

2.5.2.7 Summary.................................................................................................................. 102

2.5.3 Renewable Generation and Capacity Markets ............................................................ 106

2.5.3.1 Calculating the Capacity Value of Intermittent RES Generation in the US ............. 107

2.5.3.2 The capacity-based RES support scheme in Russia ................................................. 108

2.6 Key Findings ......................................................................................................................... 113

2.7 Ownership and Benefits of the Activity ............................................................................... 114

2.8 SPECIFIC ISSUES AND RECOMMENDATIONS PERTINENT TO THE FUTURE DEVELOPMENT OF THE ELECTRICITY SECTOR IN KAZAKHSTAN ..................................................................................... 114

2.8.1 Technical, market and organizational aspects ............................................................ 114

2.8.1.1 Mandatory vs. non-mandatory participation in PX ................................................. 114

2.8.1.2 Interaction of capacity and energy markets: .......................................................... 115

2.8.1.3 CHP in participation in capacity markets................................................................. 115

2.8.1.4 CHP technologies able to participate in capacity mechanisms ............................... 119

2.8.1.5 Governance in the capacity market ........................................................................ 120

2.8.2 Legal aspects................................................................................................................ 121

2.8.2.1 The role and legal status of Power Exchanges in the EU ........................................ 121

2.8.2.2 Recommendations with regards to the implementation of a capacity market in Kazakhstan ............................................................................................................................... 126

2.9 REGIONAL MARKET OF CENTRAL ASIA ................................................................................ 133

2.10 Challenges Faced ................................................................................................................. 136

2.11 Impact .................................................................................................................................. 136

2.12 APPENDICES ......................................................................................................................... 137

2.12.1 APPENDIX 1: EU Best Practices: Example of the French Wholesale Market / trading activities 137

2.12.1.1 Definition ............................................................................................................. 137

2.12.1.2 Products and pricing ............................................................................................ 138

2.12.2 APPENDIX 2: Kazakhstan Electricity Sector Profile ...................................................... 142

2.12.2.1 Brief characteristics of the Republic of Kazakhstan ............................................ 142

2.12.2.2 State authorities vested with functions and powers in the area of functioning and development of the energy sector .......................................................................................... 142

2.12.2.3 General characteristics of the electric power industry ....................................... 143

2.12.2.4 Current status of Kazakhstan electric power industry ........................................ 145

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2.12.2.5 Existing Market Model and Tariff setting Principles ........................................... 151

2.16.2.2 Brief description of parallel operation with energy systems of neighboring countries (Russia, Kyrgyzstan, Uzbekistan) ............................................................................. 171

3 BIBLIOGRAPHY ............................................................................................................................ 178

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List of Figures: Figure 1: Price discovery - either at the intersection of demand and supply, two-sided pool (left) or supply .................................................................................................................................................... 32 Figure 2: Basic structure of an auction ................................................................................................. 35 Figure 3: Simple bid matching .............................................................................................................. 35 Figure 4: Electricity Markets Time-line .................................................................................................. 37 Figure 5: Bilateral or Decentralised model ............................................................................................ 39 Figure 6: Pool model and bilateral trade model .................................................................................... 40 Figure 7: The electricity market liberalisation time-line of the EU Directives ....................................... 42 Figure 8: Regional Initiatives- Elements of an organisational framework ............................................ 56 Figure 9: The final 7+1 regions in which “Regional Initiatives” were established ................................. 57 Figure 10: The EU Target model ............................................................................................................ 59 Figure 11: The roadmap for the integration of electricity markets across regions ............................... 59 Figure 12: The status of implementation of Day-Ahead markets in the EU .......................................... 60 Figure 13: The 6 Regions for which regional investment plans are prepared in the EU ........................ 62 Figure 14: Taxonomy of capacity mechanisms ..................................................................................... 81 Figure 15: Development stage and type of capacity mechanism in the EU .......................................... 91 Figure 16: Types of capacity mechanisms in the EU .............................................................................. 92 Figure 17: Capacity price in RTO/ISOs ................................................................................................... 98 Figure 18: Illustration of demand curve for capacity ............................................................................ 98 Figure 19: Installed cogeneration capacities in Europe in terms of fuel input .................................... 116 Figure 20: Generalised process diagram of an advanced type of CHP with fuel and operational flexibility .............................................................................................................................................. 118 Figure 21: Back-pressure versus extraction Steam Turbine types ....................................................... 120

List of Tables: Table 1: Questions and Answers on the third legislative package for an internal EU electricity market ............................................................................................................................................................... 49 Table 2: Legal gap analysis comparting the Kazakhstan and EU electricity market related legislation 76 Table 3: Annual cost of existing capacity mechanisms ....................................................................... 102 Table 4: Summary table of capacity mechanisms ............................................................................... 105 Table 5: Methods for determining the Capacity Value of solar and wind in RTO/ISOs ...................... 107

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1 PART 1 – EUROPEAN COMMISSION

1.1 Background

Assignment Title: “Market Design Options of Kazakhstan and its Role in the Central Asia Regional Electricity Market”

Country and Dates: Kazakhstan, November 2014 –August 2015 Beneficiary Organisation(s): Ministry of Energy of the Republic of Kazakhstan, KOREM, CDC

Energia (International organisation based in Uzbekistan) Beneficiary Organisation’s key contact persons – name and e-mail address

Mr. Taltat Abilgazy, [email protected] Mr. Erjan Madiev, [email protected] Mr. Khamidilla Shamsiev, [email protected]

Deliverables Produced A report addressing the issues of internal market design for the electricity sector of Kazakhstan as well as a roadmap for the further development of electricity cooperation in Central Asia

Expert Team Members Nikos Tourlis, Task Leader, Energy Markets Expert Konstantinos Perrakis, Electricity (EU) Expert Emmanuelle Rault, Energy Law Expert Nikos Patsos, Energy Analyst Mariyash Zhakupova Local Electricity Expert

1.2 Essence of the Activity

The present report comprises the final deliverable of an assignment carried out under the Ad-Hoc Expert Facility (AHEF) of “INOGATE Technical Secretariat & Integrated Programme in support of the Baku Initiative and the Eastern Partnership energy objectives” project, funded by EC/Europeaid. Five applications for provision of Technical Assistance have been combined in this technical assistance assignment as they all shared common characteristics and comprised merits for addressing them collectively. The applications included:

• 89.KZ Study and analysis of experience in in development of power exchange trade in the countries of the Western Europe submitted by JSC "Kazakhstan Operator of Electricity Market" (JSC KOREM)

• 107.KZ Study and analysis of the existing models of electricity market in the countries of Europe, CIS and USA submitted by Ministry of Energy of the Republic of Kazakhstan

• 108.KZ Study and analysis of tariff setting in the area of electricity (production, transmission, supply) in the countries of Europe, CIS and USA

• 117.UZ Study and analysis of the existing models of electricity market in the countries of Europe, CIS and USA submitted by the International non-governmental organisations Central Dispatch Centre Energy

as they are filed under Component B: Electricity & Gas in the AHEF Registry. The assignment has been implemented over the period of November 2014 –August 2015.

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1.2.1 Objectives of the study, key findings and recommendations According to the ToR the assignment had to work with the Ministry Energy on the strategic aspect of electricity sector development and future operation and KOREM on the tactical one of improving the market by analysing specific aspects and compare with the EU practices. It also involved the Ministry of Economy, KEGOC and the industry associations. In addition to the above the assignment also addressed with the cooperation of CDC Energia the regional dimension taking Kazakhstan as a reference and starting point.

The specific objectives of the task included:

For MINT:

• To get acquainted with the EU experience in regards of development and integration of electricity markets;

• To understand the distinction between competitive and regulated segments of the electricity sector and the manner that electricity composite prices/tariffs evolve in relation to these;

• To receive information on the mechanisms of achieving investments in a liberalised market environment, on who is responsible for planning and on how these investments are recovered;

For KOREM:

• To understand the distinction energy (i.e. forward, spot, balancing) and capacity markets; • To introduce the EU experience with regard to wholesale electricity market models and the

so-called Target Model; • To receive information on the nature and content of trading and settlement arrangements

that should exist in order to govern the relationships of the market participants;

For All Beneficiaries:

• To get acquainted with the EU experience with regard to cross border arrangements in the EU;

• To discuss whether these principles would be in whole or in part useful for developing a regional market in Central Asia.

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1.3 Key Findings

The EU Member States had to transpose the Electricity Directive 2009/72/EC, which are a fundamental part of the Third Energy Package, by 3 March 2011 and to apply them from that date. The Electricity Directive set out key rules necessary for a proper functioning of the electricity market. The new or reinforced requirements concerning the unbundling of networks, the independence and the powers of national regulators and the functioning of retail markets via enhanced consumer protection measures represent major developments compared to the provisions of the Second Energy Package adopted in 2003. Important rules for the operation of the markets are also set out in the Electricity Regulation (EC) No 714/2009, also part of the Third Energy Package and applicable as from 3 March 2011.

Unbundling within energy markets refers to the unbundling of vertically integrated structures. The unbundling of generation, transmission, distribution and retail sales has an important role within the electricity market with regard to the implementation of competition. The inclination towards the unbundling of the transmission and distribution operations, which are referred to as network operations and which, as already mentioned, carry natural monopoly characteristics, from generation and retail sales activities, is based on the concern that the dominant undertaking may limit in various ways the access of other undertakings that it is competing with in generation and retail sales areas.

The above activities, initiatives and legislative framework resulted to the adoption of a ‘target model’ for the electricity sector in the EU.

The European Electricity Regulatory Forum (Florence Forum) decided in November 2008 to establish a Project Coordination Group of experts drawn from the European Commission, regulators, and relevant stakeholders, to develop an EU-wide Target Model (TM) and a roadmap for the integration of electricity markets across regions. The tasks were to develop a practical and achievable model for the harmonization of co-ordinated EU-wide transmission capacity allocation, to manage congestions and to propose a roadmap with concrete measures for the integration of forward, day-ahead, intraday and balancing markets – including governance issues.

In energy-only market designs, the (only) traded commodity is electricity (MWh/h). In such markets, the supplying companies get revenues only by selling electricity, either in organized wholesale markets and/or through bilateral contracts with customers. The companies recover capital and fixed costs of power generation because the selling prices or the wholesale market prices turn out to be higher than the variable costs (mostly fuel costs) of power generation, either continuously or periodically, but in a sufficient number of hours. Generation capacity adequacy is supposed to be derived from the resulting market dynamics. Moreover, scarcity pricing ensures revenues to cover capital cost of peak (and other) generation capacity.

By contrast, market designs with explicit capacity mechanisms recognize two market commodities, namely electricity (the output) and generation capacity (the means). Introducing capacity mechanisms imply that generators receive payments for the mere availability of capacity in addition to revenues obtained from the energy market. One might say that in a market with an explicit capacity mechanism the energy market is still the main instrument for short term optimization of

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resources, while the capacity mechanisms is the main instrument for long term development of generation capacity.

1.4 Ownership and Benefits of the Activity

Despite the fact that the “missing money problem” has not yet hit the Kazakh wholesale electricity market, the Ministry of Energy considers establishing capacity support mechanisms. On the other hand the Market Operator of Kazakhstan evaluates different market design features with a view to propose amendments/improvements to the current market design in Kazakhstan. These include the mandatory vs voluntary participation of market actors to the Power Exchange, the impact of participation of the CHP generation to the capacity support mechanism as well as generally the enhancement of the role of the PX in the wholesale electricity market. On top of these issues which concern only Kazakhstan as the most advanced and important (in terms of its size) electricity market in the Central Asian region, INOGATE has always been looking to enhance and support the central role of Kazakhstan on the creation of a regional Central Asia electricity market. These interlinked objectives have led to the combination of the originally distinct applications for technical assistance. The results can be viewed as a knowledge base enhancement which may under appropriate circumstances and with the support of other international development partners working in Kazakhstan translate into reforms and eventually the creation of a regional electricity market.

1.5 Recommendations

Capacity Mechanisms and the lessons learnt for Kazakhstan

Capacity mechanisms are set up in order to remedy to the risk of insufficient electricity generation, it is normally opened to both existing and new generation plants.

The ultimate goal of the introduction of capacity market mechanisms is to ensure the security of supply and benefit the end users has regards both the security of supply and cost -reflective tariffs.

The introduction of capacity market mechanisms must be assessed according to two main objectives:

• Foster and incentivise investment in power generation and • Ensure a better control of the electricity demand, especially during peak hours

These objectives being met, any country setting up a capacity market should be able to secure its supply. However, the introduction of capacity market mechanisms has inevitably an effect on the balance of power market and on its competition/openness level.

Therefore, one should take into account a number of risks and challenges affecting the deployment of a sustainable and opened electricity market:

• The introduction of a capacity market can have the consequence to strengthening the market position of dominant operators and exclude the possibility of entrance of new players on the market. The energy and competition regulatory framework need to be given sufficient

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monitoring and sanction powers in order to ensure fair competition and avoid market dominance behaviour.

• Any dominant or strong market player should be particularly monitored by the regulator in order to avoid further market dominance (as for example, by holding certificates in order to create an unbalance of the certificate markets and ensure higher certificates trading prices)

• The evaluation of the capacity needs should take into account opportunities connected to the interconnection system and the import of electricity. These will affect positively the security of supply and the volume of electricity import should be taken into account

• Protection of equality of treatment among operators is key in order to avoid predatory behaviour from dominant market players

• The cost of capacity market certificates should be included in the calculation of regulated tariffs

• The possibility to launch tender for new capacity needs to be assessed vs. investment in new generation capacity which would have occurred in a traditional market

The Central Asia Regional Electricity market – A roadmap

In the centrally planned era the regional electricity flow in the Central Asia Region used to be part of a wider economic planning context. Electricity, water, cotton, fuels and other commodities where exchanged year-round in an area which used to be part of a single state. With the collapse of the Soviet Union the re-scheduled deliveries were hard to be matched as commodities and were now produced by different counties under different conditions. The history is more or less known and what is important to be highlighted is that the electricity flows in the region have gradually and steadily been decreasing in an area where the hydro-thermal cooperation would be beneficial - as it used to be in the past but nowadays even more due to the technological advancements.

Kazakhstan beyond any doubt comprises an important player in the future market –primarily due to its market size and level of advancement – but it is rather unlikely that it could catalytically lead the process in which the rest of the partners are not convinced to follow.

As far as the Roadmap for the development of the Regional Central Electricity Market is concerned, in the views of the ITS team this can for the time being define general directions but for the detailed milestones to be accurately defined would require all prerequisites to be in place. Instead of a full-defined Roadmap the one proposed below describes the necessary prerequisites for a process to be set up in order to guide the development. Perhaps the discussions at international level would be able to support and facilitate a process such as the one briefly described below:

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1.6 Challenges Faced

One of the biggest challenges faced in the present assignment had to do with the considerable gap of the EU and Kazakh legislation with respect to the organisation and operation of the energy sector generally. While the organisation of the electricity market of Kazakhstan is in many ways similar to several EU countries the primary legislation is way too generic in comparison to the 3rd Energy Package. Some of the reported issues in the electricity market have also direct relevance to competition legislation and we assume that this might not only lead to unique considerations in the electricity sector but might probably affect the Kazakh economy as a whole.

Another challenge had to do with the infrequent exchange of experiences between Kazakhstan and the EU. Kazakhstan being a member of the Euro-Asian Economic Union is determined to integrate its electricity market with the other members of the union and this does not entail compliance to the EU Acquis. It is therefore rather difficult to identify and propose solutions of the reform of certain segments of the electricity markets in an isolated manner.

Last but not least, the development of cross border electricity infrastructure in Central Asia has both shifted the centre of gravity to countries that fall beyond the regional group of five Central Asian ex-soviet union countries while it currently has little in common with the regulatory framework adopted in Europe for the development of key energy infrastructure.

1.7 Impact Matrix

The main role of this assignment was to raise awareness of key decision makers in the Kazakh electricity market. It is understood that several lessons learnt as well as the terminology, taxonomy

• A political cooperation process is required

• New vs existing forum

International cooperation level

• Unharmonised regulatory frameworks

• NRAs and regional cooperation

Regulatory Cooperation level

• Vertical undertaking and unbundled TSO

• CDC Energia role Operational Level

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and principles of the EU electricity markets might serve as an important background and basis for further thinking on questions that might appear to be in their essence similar to those discussed in this report. We hope that reform process in the electricity sector of Kazakhstan will continue with the support of other international development partners and this will also include the objectives of the creation of a regional electricity market. Looking at this work from a different perspective we hope that part of this analysis will be useful to any party that is interested in the Kazakh electricity market irrespectively of the viewpoint (EU or non-EU reader).

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2 PART 2 - BENEFICIARIES

2.1 Executive Summary

Liberalisation of the Electricity Markets and the EU

The recent economic appreciation of the network industries in general and within them the electricity supply industry continues to recognise the merits of monopoly but only with regards to the networks i.e. proposing that inefficiencies of the monopoly are less than the avoided cost of spontaneous network investment and that allocative efficiencies may be achieved by introducing competition to the generation and supply segments. The high cost of electricity networks (both at transmission and distribution level) can make it efficient to have a single supplier of network services in a particular geographic area, leading to a natural monopoly industry structure. In addition, the electricity networks are regulated to manage the risk of monopoly pricing, where a business can charge higher prices or provide poorer services compared with the situation in a competitive market. Thus, even in the liberalized electricity sector, network tariffs are not determined by market forces: because each network is a monopoly and so market forces cannot be relied upon to provide efficient prices.


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Source: CEER

The Electricity Market of Kazakhstan

The situation in the electricity market of Kazakhstan implies an advanced electricity market which is in certain aspects quite similar to that of several EU Member States.

The main actors

The main actors of Kazakhstan’s Wholesale Electricity Market are as follows:

• The recently reorganized Ministry for Energy, responsible for the whole energy sector of Kazakhstan

• The Agency for the Regulation of Natural Monopolies (AREM) regulates tariffs in the sector • The Agency for Competition Protection (AZK) monitors operation of competitive markets to

detect market power abuses and prevent market manipulation • KOREM - The Kazakhstan Wholesale Energy and Capacity Market Operator, which operates

centralized trading platform for the short-, mid-and long-terms trading. • KEGOC –the Transmission System Operator -, which includes the National Dispatch Center

and serves as the system operator of the National Electric Power System

Wholesale Market organization

• The electricity market in Kazakhstan is based on bilateral contracts and their mandatory physical implementation

• In addition, KOREM performs 2 types of auctions: o “Day ahead” auctions o Forward auctions (medium-term for a week, month and long-term for a quarter,

year)

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• On the basis of bilateral contracts and the results of centralized trading, the System Operator prepares the preliminary dispatch schedule

• Balancing: o is performed by the System Operator with involvement of power systems of Russia,

Kyrgyzstan and Kazakhstan o The rules for balancing market were developed in 2007-2008. The balancing market

still operates in “imitation” mode. In January 2008 the Balancing Market started work in a simulation routine

• Wholesale market buyers are electricity supply organizations which resell electric power to retail consumers.

The figure below presents schematically the current organisation of the electricity market in Kazakhstan:

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Challenges in regards to the future development of the electricity sector in Kazakhstan and key recommendations

During our review of the electricity sector of Kazakhstan we have identified a number of deviations from the current EU status quo; the electricity demand is increasing at a constant pace in Kazakhstan, centralised planning is not adequately consulted with the relevant stakeholders (or at least the ITS team has not been able to find this documented), electricity tariffs transparency and their effect on competition is rather different compared to the practices of most EU Member States. Last but not least, the role, responsibilities and authorities of National Energy Regulatory Authorities are spread among several governmental authorities. In this context the section below presents some high level recommendations which in the ITS team of experts’ opinion need to be discussed at national level.

Estimation of generation capacity needs should be done with due care concerning electricity export prospects; risks for investments to cover such needs should be left almost in their totality to the private sector. On the other hand, domestic demand should be covered with the necessary reliability offered in modern economies. To this objective, power system planning (both generation and transmission, for a horizon in the order of ten years) should be done according to international practices and quality standards. All options (e.g. refurbishment of existing plants vs. creation of new plants) should be treated in the analysis with due attention in cost and reliability features and numbers used for the various technical options.

In the aforementioned analysis, one should try to avoid cross-subsidization in the production of heat and electricity on the CHP. Such cross-subsidization reduces investment attractiveness of projects for the construction of a thermal power plant due to the overestimation of the cost of the electricity produced in CHP plants, and electricity becomes uncompetitive in the wholesale market.

Tariffs and revenue collection should ensure the viability of the system. Subsidisation of specific categories of consumers (low income, remote areas, etc.) should be explicitly calculated and included either in the tariffs or through appropriate financial subsistence (provided either to the electricity sector -generators, network companies- or outside of the electricity market). In both the latter options, the expenses should be covered from the public budget and foreseen on an annual basis or equivalently each regulatory period.

Unbundling of accounts (e.g. for energy, for reserves, for transmission, for distribution, for system operation, etc.) should be also a priority, given that such unbundling will help identify inefficiencies in a much easier and transparent way.

Benchmarking of the costs of the various categories in the electricity market should be performed often (e.g. on a 2 years basis) according to international standards and with participation of accredited accounting firms.

New capacity should be procured according to auctions, in quantities as they are calculated based on the aforementioned long-term plan. PPAs are considered to be an appropriate approach at the current state of the market.

A comprehensive and efficient market monitoring system should be established. Market monitoring reports should be produced on a 3-month and yearly basis.

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In addition, assigning the monitoring and regulation function of the electricity (and heat) sector in one body might add to efficiency in the operation of the sector. More specifically, the integration of responsibilities that now belong to AREM (Agency for the Regulation of Natural Monopolies, mainly regulating tariffs) and AZ K (The Agency for Competition Protection which monitors operation of competitive markets) will improve the capabilities of the singe institution to detect market power abuses and prevent market manipulation. Such a regulatory body would, for example approve the power system development plans (both generation and transmission) which should be in turn developed by KEGOC in collaboration with the regional transmission companies.

Capacity Mechanisms and the lessons learnt for Kazakhstan


The ultimate goal of the introduction of capacity market mechanisms is to ensure the security of supply and benefit the end users has regards to both the security of supply and cost -reflective tariffs.





• The introduction of a capacity market can have the consequence to strengthening the market position of dominant operators and exclude the possibility of entrance of new players on the market. The energy and competition regulatory framework need to be given sufficient monitoring and sanction powers in order to ensure fair competition and avoid market dominance behaviour.


• The evaluation of the capacity needs should take into account opportunities connected to the interconnection system and the import of electricity. These will affects positively the security of supply and the volume of electricity import should be taken into account



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The Central Asia Regional Electricity market – A roadmap

In the centrally planned era the regional electricity flow in the Central Asia Region used to be part of a wider economic planning context. Electricity, water, cotton, fuels and other commodities where exchanged year-round in an area which used to be part of a single state. With the collapse of the Soviet Union the re-scheduled deliveries were hard to be matched as commodities where now produced by different counties under different conditions. The history is more or less known and what is important to be highlighted is that the electricity flows in the region have gradually and steadily been decreasing in an area where the hydro-thermal cooperation would be beneficial - as it used to be in the past but nowadays even more due to the technological advancements.

Kazakhstan beyond any doubt comprises an important player in the future market –primarily due to its market size and level of advancement – but it is rather unlikely that it could catalytically lead the process in which the rest of the partners are not convinced to follow.

As far as the Roadmap for the development of the Regional Central Electricity Market is concerned, in the views of the ITS team this can for the time being define general directions but the detailed milestones to be accurately defined they would require all prerequisites to be in place. Instead of a full-defined Roadmap the one proposed below describes the necessary prerequisites for a process to be set up in order to guide development. Perhaps the discussions at international level would be able to support and facilitate a process such as the one briefly described below:

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2.2 Background

The present report comprises the final deliverable of an assignment carried out under the Ad-Hoc Expert Facility (AHEF) of “INOGATE Technical Secretariat & Integrated Programme in support of the Baku Initiative and the Eastern Partnership energy objectives” project, funded by EC/Europeaid. Five applications for provision of Technical Assistance have been combined in this technical assistance assignment as they all shared common characteristics and comprised merits for addressing them collectively. The applications included:

• 89.KZ Study and analysis of experience in in development of power exchange trade in the countries of the Western Europe submitted by JSC "Kazakhstan Operator of Electricity Market" (JSC KOREM)

• 107.KZ Study and analysis of the existing models of electricity market in the countries of Europe, CIS and USA submitted by Ministry of Energy of the Republic of Kazakhstan

• 108.KZ Study and analysis of tariff setting in the area of electricity (production, transmission, supply) in the countries of Europe, CIS and USA

• 117.UZ Study and analysis of the existing models of electricity market in the countries of Europe, CIS and USA submitted by the International non-governmental organisations Central Dispatch Centre Energy

as they are filed under Component B: Electricity & Gas in the AHEF Registry. The assignment has been implemented over the period of November 2014 –August 2015.

2.2.1 Objectives of the study, key findings and recommendations According to the ToR the assignment had to work with the Ministry Energy on the strategic aspect of electricity sector development and future operation and KOREM on the tactical one of improving the market by analysing specific aspects and compare with the EU practices. It also involved the Ministry of Economy, KEGOC and the industry associations. In addition to the above the assignment also addressed with the cooperation of CDC Energia the regional dimension taking Kazakhstan as a reference and starting point.

The specific objectives of the task included:

For MINT:

• To get acquainted with the EU experience in regards of development and integration of electricity markets;

• To understand the distinction between competitive and regulated segments of the electricity sector and the manner that electricity composite prices/tariffs evolve in relation to these;

• To receive information on the mechanisms of achieving investments in a liberalised market environment, on who is responsible for planning and on how these investments are recovered;

For KOREM:

• To understand the distinction energy (i.e. forward, spot, balancing) and capacity markets;

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• To introduce the EU experience with regard to wholesale electricity market models and the so-called Target Model;

• To receive information on the nature and content of trading and settlement arrangements that should exist in order to govern the relationships of the market participants;

For All Beneficiaries:

• To get acquainted with the EU experience with regard to cross border arrangements in the EU;

• To discuss whether these principles would be in all or in part useful for developing a regional market in Central Asia.

2.2.2 Methodology and outputs The approach involved a mixed field work and homework effort that involved two missions to Astana. The assessment commenced with homework on the electricity sector profile of Kazakhstan with a view that the team establishes the basic background knowledge on the sector. The first mission to Astana was carried out in December 2014. The purpose of the mission was to discuss the guiding ideas over which the analysis would deploy and also to get feedback on specific issues that were of an immediate and specific interest to the beneficiaries (mostly KOREM). There has been analysis on the specific issues and also on the remainder of the subjects mentioned in the ToR during the period between January and April 2015. In April 2015 the second mission has been carried with the purpose of providing answers to the detailed requests of KOREM and also to hold a workshop in the Ministry of Energy in which both national market design but also regional Central Asia electricity market developments were to be discussed. This second mission included also the participation of CDC Energy which INOGATE and several international institutions recognise as a specialist organisation in the regional electricity market of Central Asia.

Kazakhstan is a major electricity market in the region and has so far achieved considerable reforms in comparison to the neighbouring markets in Central Asia. In that sense INOGATE has developed this study as a background work for the Ministry of Energy in order to communicate the developments in relation to the integration of the European electricity market. We believe that certain aspects of this work might reveal a point of reference for the Ministry of Energy in the process of developing and modernise the electricity sector in Kazakhstan. The conditions for the development of a regional electricity market in Central Asia at the moment do not allow for a detailed discussion on the market design specifics. The development of infrastructure which is currently underway and supported by several IFIs as well as the need for political and regulatory cooperation need to be dealt with as a matter of priority. INOGATE follows closely the development in this respect and will be available to discuss future engagement should certain precedents such as the political and regulatory cooperation are established.

2.2.3 Limitations and further work The aim of the study was to develop the necessary background for the beneficiaries in order to contribute in their turn in the national dialogue for the future development of the Kazakh electricity market. One of the key limitations identified during this assignment is that European legislation

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especially after the adoption of the 3rd Energy Package has become quite detailed and specific particularly in the areas of generation authorisation, Regulated Third Party Access and Unbundling of the Transmission System Operators. While these legal and regulatory provisions have gradually emerged as a mechanism for the integration the national European markets into the Internal Electricity Market their validity and transferability is becoming increasingly challenging in countries outside the EU. Kazakhstan, on the other hand, as a member of the Euro-Asia Economic Union will have to work towards the legal and regulatory integration with Russia and Kyrgyzstan. There are a few areas which mostly relate to merely technical and operational aspects in the electricity markets that have only briefly mentioned in this study and could form part of the future cooperation between Kazakhstan and INOGATE in the future.

2.2.4 Structure of the report The report comprises two major parts each one comprising a distinct geography namely; the European Union and the Republic of Kazakhstan. Particularly, the electricity market models and EU legislation as well as the so far experience with capacity mechanism comprise the major part of this report. The review of the electricity sector of Kazakhstan and the legal gap analysis as well as the review of the status and recommendations on the Central Asia Electricity Markets comprise the remainder of this report. More specifically:

Chapter 2.3 discusses electricity markets the models that have emerged and their legal implementation in the EU.

Chapter 2.4 attempts an review of the key areas related to the electricity market in Kazakhstan and includes a high level legal gap analysis.

Chapter 2.5 provides an overview of introduction of new generation capacities in liberalised markets.

Chapter 2.6 discusses specific and immediate legal, technical and regulatory issues that are currently on stake in the discussion for the future development of the Kazakh electricity market.

Chapter 2.7 is devoted to the review of the progress of the development of the Central Asia Electricity Market and provides recommendations for structuring the dialogue on broader cooperation.

Two appendices comprise an integral part of this report with each of them corresponding to:

Appendix 1: The French Electricity Market

Appendix 2: Kazakhstan Electricity Sector Profile

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2.3 ELECTRICITY MARKETS

2.3.1 Concepts in the new market structure This section discusses briefly the motivation and economic rationale under which several energy policy makers (including Kazakh as it is evident by the Law on Natural Monopolies) to restructure their national electricity supply industries and introduce competition in certain segments while keeping (primarily) the networks as natural monopolies. This section in addition to the description of the resulting organization of the sector extends to the impact of these reforms on price discovery mechanisms and the prevailing wholesale electricity market models.

2.3.1.1 The rationale of preserving networks as natural monopoly Electricity in general has the typical characteristics of a good to be supplied by a natural monopoly. At least this was the prevailing economic perspective of the industry from its emergence during the Thomas Edison and Nicola Tesla era until recently. There are several arguments justifying that with most of them being founded on the premises of economies of scale, and security of operations. First, the generation of electricity involves significant economies of scale. In order to produce electricity, a plant needs to be erected to generate the first kilowatt-hour. After the initial investment, however, additional megawatts can be produced in the same generation plant without incurring new fixed costs. Consequently, production on a larger scale can be done at decreasing average cost. Secondly, transmission and distribution are quintessential natural monopolies1. The building of networks entails high, largely sunk fixed costs so that it would be economically wasteful to have multiple network resources covering the same area. Third, complementarities between generation and transmission lead to substantial economies of scope. This explains the rationale for the structural integration of the electricity industry. A striking attribute of a transmission grid is “its ability to synchronize dispersed generating units into a stable network”2. Production from facilities with higher marginal cost can be substituted by production from facilities with lower marginal cost in real time, thereby increasing efficiency. Moreover, in order to ensure electricity supply, there needs to be a continuous balancing of generation and consumption. If one single element of the system (e.g. a generation unit or a transmission line) does not work properly, it can endanger the stability of the entire electricity grid3. These special characteristics of electricity make it very complicated to replace the existing vertical and horizontal integration with decentralized market mechanisms4.

The recent economic appreciation of the network industries in general and within them the electricity supply industry continues to recognise the merits of monopoly but only with regards to the networks i.e. proposing that inefficiencies of the monopoly are less than the avoided cost of

1 Kessides (2004). p. 133. Reforming Infrastructure: Privatization, Regulation and Competition. Herndon, VA, USA: World Bank 2 According to Joskow, cited in: Kessidis (2004). p. 133, Reforming Infrastructure: Privatization, Regulation and Competition. Herndon, VA, USA: World Bank 3 Kessides (2004). p. 133. Reforming Infrastructure: Privatization, Regulation and Competition. Herndon, VA, USA: World Bank 4 Joskow (2003). p. 5. Electricity Sector Restructuring and Competition: Lessons Learned. Latin American Economic Review.

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spontaneous network investment and that allocative efficiencies may be achieved by introducing competition to the generation and supply segments. The high cost of electricity networks (both at transmission and distribution level) can make it efficient to have a single supplier of network services in a particular geographic area, leading to a natural monopoly industry structure. In addition, the electricity networks are regulated to manage the risk of monopoly pricing, where a business can charge higher prices or provide poorer services compared with the situation in a competitive market. Thus, even in the liberalized electricity sector, network tariffs are not determined by market forces: because each network is a monopoly and so market forces cannot be relied upon to provide efficient prices.

2.3.1.2 Unbundling Keeping certain parts of the industry as a natural monopoly while allowing third parties to get access to the networks and eventually compete on a level playing field led to the introduction of the notion of unbundling.

The Notion of Unbundling

Unbundling within energy markets refers to the unbundling of vertically integrated structures. The unbundling of generation, transmission, distribution and retail sales has an important role within the electricity market with regard to the implementation of competition. The inclination towards the unbundling of the transmission and distribution operations, which are referred to as network operations and which, as already mentioned, carry natural monopoly characteristics, from generation and retail sales activities, is based on the concern that the dominant undertaking may limit in various ways the access of other undertakings that it is competing with in generation and retail sales areas. The mechanism referred to as vertical unbundling aims to provide the access of all players to distribution and transmission systems without discrimination and the prevention of cross subsidization between undertakings conducting generation, transmission, distribution and supply activities.

Unbundling within the electricity market may be realized as:

• unbundling of accounts, which provides for the independent accounting for separate operations

• legal unbundling, which provides for the organization of different activities under different legal entities. However, this does not prevent such different activities from being owned by the investment group.

• functional unbundling: accounting separation, plus (1) relying on the same information about its transmission system as the other market players when buying and selling power, and (2) separating employees involved in transmission from those involved in power sales.

• operational unbundling: operation of, and decisions about, investment in the transmission grid are the responsibility of an entity that is independent of the owner(s) of generation; however, ownership of the transmission grid remains with the owner(s) of generation.

• ownership unbundling, to the contrary of legal unbundling, requires the unbundled assets and activities to not be owned by the same investment group.

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Thus, within the electricity sector, it is essential that unbundling be realized within vertically integrated undertakings in order to support the entry of new players to the market and to prevent discrimination between undertakings within the market.

2.3.1.3 Trading in wholesale electricity markets Trading in liberalized wholesale electricity markets5&6 can be characterized according to the features of the underlying contracts, i.e. whether the underlying contract is for ‘physical’ delivery or just a pure financial contract:

• Contracts for physical delivery tend to be formed closer to the delivery time, and are formed between appropriate market participants, in this case between generators and suppliers or end –users.

• Financial contracts tend to be formed well in advance of the delivery time; in such contracts it is not necessary that the parties can actually be engaged in transactions of physical delivery of electricity, i.e. traders not owing / representing any generation capacity or not consumption installation may engage in such contracts.

Concerning the type of market, wholesale electricity trading can be performed via:

• Bilateral Over-the-Counter (OTC) contracts with free formats; such contracts may be established over a variety of products and for various time horizons (from long-term, i.e. 3 years ahead, up to one-day ahead).

• Organized markets (Pools or Power Exchanges/PXs); organised markets can be implemented in different horizons:

o Long-term / forward markets (for physical or financial delivery of energy), with different standardized formats of contracts; usually implemented through a PX;

o Day-Ahead organized markets (physical delivery of energy); usually implemented through a Pool or a PX;

o Intraday markets (physical delivery of energy); usually implemented through a PX;

2.3.1.4 Bilateral contracts As for many commodities, a way to trade electricity is a market mechanism based on (physical or financial) bilateral contracts. This means that sellers and buyers freely enter into bilateral contracts for power supply. Sellers will normally be generators and buyers can be traders, electricity suppliers, distribution companies and eligible consumers. However, generators could also become a buyer (e.g. in case they have a shortage of generation). Likewise, consumers can become sellers. Brokers can act as an intermediate between buyers and sellers dealing in standard contracts. These types of transactions are referred to as Over the Counter (OTC).

As mentioned above, such contracts may be established over a variety of products and for various time horizons (from long-term, i.e. 3 years ahead, up to one-day ahead). In addition, they may involve ‘physical’ delivery of electricity or be just pure financial contracts.

5 http://www.oscogen.ethz.ch/reports/oscogen_d5_1b_010702.pdf 6 http://ocw.mit.edu/courses/engineering-systems-division/esd-934-engineering-economics-and-regulation-of-the-electric-power-sector-spring-2010/lecture-notes/MITESD_934S10_lec_11.pdf

http://www.oscogen.ethz.ch/reports/oscogen_d5_1b_010702.pdf

http://ocw.mit.edu/courses/engineering-systems-division/esd-934-engineering-economics-and-regulation-of-the-electric-power-sector-spring-2010/lecture-notes/MITESD_934S10_lec_11.pdf

http://ocw.mit.edu/courses/engineering-systems-division/esd-934-engineering-economics-and-regulation-of-the-electric-power-sector-spring-2010/lecture-notes/MITESD_934S10_lec_11.pdf

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2.3.1.5 Power Pools or Electricity pools Power Pools constitute an organized market having its origin to the way that traditional utilities used to operate before the liberalization era. Electricity pools require generators to submit bids indicating how much electricity they can generate at a given price (price-based pools).

On the demand side, the market operator may forecast demand and dispatch generating units against this. This is called a one-sided pool. In more sophisticated pools (two-sided pools), the market operator may dispatch on the basis of a demand curve created from price-quantity bids made by the buyers on the market, such as distribution companies and eligible consumers (Figure 1).

Market participants submit the required quantity (in MW or MWh), as pools usually operate on hourly or ½ hr granularity.

Source: CIGRE, 2005

Figure 1: Price discovery - either at the intersection of demand and supply, two-sided pool (left) or supply and predicted demand, one-sided pool (right)

Thus, Generators submit bids for supplying a given volume of power at a specific price, usually a day ahead. When Suppliers do not submit price – quantity offers (i.e. they only submit quantity required), the market operator accepts bids from generators, starting with the cheapest, until the demand forecasts are met. Generators are ‘in merit’ when their bids are successful and ‘out of merit’ when unsuccessful. When Suppliers submit price – quantity offers the market is ‘solved’ through an algorithm aiming to maximize the social welfare7. Pools usually have horizon of 24 hours, thus implementing a Day-Ahead market. The Bids and offers are normally firm and they are matched in the market clearing process and result in an obligation to take and deliver the matched volumes (physical delivery of electricity). These volumes will be financially settled at some later point in time.

7 The term ‘social welfare’ is used in microeconomics; in the electricity markets context it can be described as the sum of the benefits that Generators and Suppliers obtain from the electricity market. In turn this means the sum of the amounts above the bids of Generators and below the offers of Suppliers. In one-sided pool, this corresponds to the traditional Economic Dispatch, i.e. the dispatching algorithm aims to minimize total costs for meeting the load, based on bids of the Generators.

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Based on the set of generator costs received and on customer demand for electricity, the System Marginal Price (SMP) for each (hourly or half-hour) trading period is determined by the Market Operator, using a stack of the cheapest generator cost bids necessary to meet the demand. More efficient generators are generally run to meet demand in the trading period. The marginal generator needed to meet the demand sets the SMP for that trading period. The other generators who have submitted bids lower than this price are deemed to be in merit and will also be scheduled to run. The SMP for each trading period is paid to all generators that are needed to meet demand. All generators who have submitted a bid which is under the SMP earn a profit, known as inframarginal rent, on the difference between their bid offer and the SMP. In some pool implementations the market is solved and SMP is calculated for each trading period independently from other trading periods. In some other implementations, all 24 hours of the Day-ahead horizon are solved simultaneously (co-optimized), thus taking into account intertemporal constraints such as start-up/shut down times of generating units, ramping rates of generating units etc.

A pool can be a compulsory pool or a voluntary pool. A compulsory (or gross pool) requires all generators, except the smallest ones, to sell their output to the pool at the pool’s price. In a voluntary (or net pool), generators can agree bilateral trades with buyers for the delivery of electricity, but must inform the system operator who takes it into account when scheduling (see below Section 2.3.1.9.3 on ‘Hybrid Model’.)

During the matching process the network can be treated as a “copper plate” resulting in a single energy price in the whole control area. The cheapest generation gets priority regardless of network constraints. In a second stage the feasibility of the achieved solution is examined. If there is congestion, some out-of-merit generators are dispatched to replace in-merit generators. This is the so-called “constrained-on/off” generation. The cost of this action constitutes the uplift charge and is added to the ‘equilibrium’ price (Pc):

P energy = Pc + P congestion

Alternatively the matching can be on the basis of a security constrained dispatch taking into account both generation marginal price and the physical aspects of the transmission system. This is common in a pool model.

2.3.1.6 Power exchanges Power exchanges in the liberalised electricity market context signify an important mechanism to implement wholesale electricity markets. Over the last years and in the face of the ongoing liberalisation of the electricity sector in Europe and many other parts of the world, a number of electricity exchanges have been put into operation.

The main goal of exchange-based markets lies in the facilitation of the trading standardized products and the promotion of market information, competition, and liquidity. Power exchanges (ideally) also provide other benefits, such as a neutral marketplace, a neutral price reference, easy access, low transaction costs, a safe counterpart, and clearing and settlement service. Besides, exchange-based

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spot market prices are an important reference both for over-the-counter (bilateral) trading, and for the trading of forward, future and option contracts.

2.3.1.6.1 Auction trading The basic structure of auction trading is depicted in Source: OSCOGEN, 2002

Figure 2: Basic structure of an auction Source: OSCOGEN, 2002

Figure 2: Basic structure of an auction . Participants can submit (usually cannot change) their bids until the closure of the ‘call’ phase (or ‘gate closure’). For price determination all the bids collected up to the gate closure’ are sorted according to the price and aggregated to get a market demand and supply curve for every hour.

The simple bid matching ignores any execution conditions or grid capacity constraints and results in an initial market clearing price (MCP), for every hour and trade volumes for every bid (see Source: [OSCOGEN, 2002]

Figure 3: Simple bid matching ). The MCP is the price level at the intersection of the aggregated demand and supply curves. If there is no intersection of the two curves, there may be a second round of submitting bids in order to get an auction price or the last calculated MCP.

The initial solution has first to be checked against all the conditions added to the bid8. If not all conditions are satisfied the initial solution is not valid. In this case one of the unfulfilled bids is eliminated and the price calculation is run again. This checking process is iterated until all the remaining bids can be fulfilled.

In general, the auctions organized by PXs are9:

• double-sided: there is demand and supply side bidding by generators, suppliers, traders, large consumers, etc.

• Multi unit: orders are typically expressed in MWh for delivery or off-take in a certain hour of the next day

• Uniform priced: all orders are settled at the same price • Sealed bid - Single round: order books are not disclosed and orders cannot be changed.

8 e.g. for ‘block bids’ which span a period of more than I hour, an average of the market clearing prices for the hours included in the bid is calculated. This price has to be equal, or better, than the price limit stated by the participant to satisfy the bid (minimum income (sales) or maximum payment (purchases) condition) 9 Power Exchange Auction Platform Design, L. Meeus, 2006

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Source: OSCOGEN, 2002

Figure 2: Basic structure of an auction

Source: [OSCOGEN, 2002]

Figure 3: Simple bid matching

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2.3.1.6.2 Continuous trading Some exchanges provide an alternative trading form to the auction system called continuous trading. This form is used to either trade only block contracts (Borzen, EEX) or individual hours and block contracts (UKPX, APX UK). Continuous trading differs from auctions in the following points. Firstly, participants have access to the order book. Secondly, each incoming bid is immediately checked and matched if possible according to price/time priority. Finally, the transaction price is not the same for all transactions as it is determined according to only the concerned bids.

2.3.1.7 Balancing markets Power systems have to be kept continuously in balance, i.e. electricity injected must be equal to electricity absorbed from the system. Thus, errors in forecasted demand or outages of generators dispatched or the intermittence of generation from some type of RES (e.g. wind or solar PV) must be treated on a continuous basis either by automatic mechanisms (provision of primary and control and load following by specific generators) or manually, by bringing on-line or asking available generators to adjust their output (tertiary control). The task of balancing is performed by the system operator, being responsible for allocating specific units to provide ancillary services in short term (in the order of minutes to ½ hour).

In more advanced markets, the system operator runs a balancing market ( or the market operator but can also be allocated to a separate entity (e.g. settlement administrator) in order to establish a market based price for the settlement of the imbalances.

Balancing markets operate shortly before the time interval during which the balancing service would be required (e.g. few hours or even 1 hour before the hour of provision of the service.)

Balancing markets are usually implemented through a Power Exchange.

2.3.1.8 Coordination of electricity markets Electricity can be traded across different time scales. However, trading arrangements are designed in a way that, at a set point before real-time delivery, contracts are fixed. This set point in time is called gate closure. In real time delivery, the gate closure allows generators to finalise their physical outputs according to their contracted volumes and to notify their expected output for each of the next contracted periods to the transmission system operator (TSO).The above described electricity markets can be seen operating as follows time-wise and product / objective wise:

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Source: own elaboration

Figure 4: Electricity Markets Time-line

2.3.1.9 Short Term Wholesale market models Based on the above described electricity trading mechanisms, short –term (i.e. 24 – 72 hours) wholesale markets for electricity have developed along several models, as follows:

2.3.1.9.1 The ‘Pool’ (or ‘Integrated’) model Participation in the Pool is mandatory, meaning that all electricity to be sold and bought has to be traded through the Pool.

The salient feature of the pool is that Generators do not try to find specific customers (Suppliers) to sell energy. In order to sell they only have to be ‘successful’ so that their bid is below the market clearing price. Same holds for Suppliers, with the only difference that their offer has to be equal or higher to the market clearing price.

The pool model is used usually for short term (time wise) wholesale electricity markets, e.g. 24 to 72 hours ahead. Participants to the Pool agree to physical transactions of energy, in the sense that they are meant to physically inject or absorb electricity from the grid (as opposed to financial transactions, which means that participants are not obliged to actually produce or consume electricity)

Ancillary services and transmission constraints are usually solved / co-optimized for the whole period for which the market is solved (eg. 24 hours for a Day-Ahead market);

The Pool model, like every short term electricity wholesale market model, is usually complemented by a Balancing market.

The UK model (the England and Wales Power Pool, 1990-2001) is the most famous example of an Electricity Pool and has deeply influenced reform processes in several countries in Europe, Latin America and Asia.

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Participants in a competitive Pool market tend to bid close to their variable costs (Generators) and ‘value’ of electricity (Suppliers / off-takers). This may cause, under conditions, a problem for Generators to recover their investment cost.

Potentially, a generator who sells directly to the wholesale pool market may receive the following payments10:

1. Energy Payment- The market price per MW sold per half hour time slot. 2. Capacity Payments – Compensation for being available to generate upon instruction from the

grid operator11. 3. Constraint Payments – Compensation for being constrained from exporting scheduled

amount of energy onto the system (due to grid stability issues).

2.3.1.9.2 The ‘Bilateral’ model The Basic Trading mechanism in the Bilateral model includes Bilateral Contracts as well as trading in private Power Exchanges. Each Seller must have a Buyer & each Buyer must have a Seller; the amount bought must equal the amount sold. Thus, the aim is to leave as much of the trading as possible to the market participants. Actually, the market players are rather forced to trading in the –private- markets of the Bilateral Model (OTC or in PXs ).

In the Bilateral Model, the ‘Unit commitment’ function, i.e. the decision whether a generator is ON or OFF, is performed in a decentralized way, by market participants themselves (self – scheduling and dispatch).

The TSO schedules the system explicitly using the bilateral transactions + any PX transactions. IT does not simultaneously clear all markets (energy + ancillary services + transmission network congestion) as it happens in the Integrated/Pool model. The ISO tries to implement the agreed transactions but also verifies that sufficient transmission capacity exists to complete the transactions (maintaining transmission security). Thus, unlike what happens in the Pool Model, in the Bilateral Model there is no ex-ante guarantee that all the agreed transactions shall be implemented; some might be modified by the TSO in order to maintain the system’s operational security. The process of notification of the TSO about the agreed transactions is depicted in the picture below.

10 http://www.wattics.com/the-electricity-market-in-ireland/ 11 The issue is analysed further in detail below (Section 2.5.2)

http://www.wattics.com/the-electricity-market-in-ireland/

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Source: own elaboration

Figure 5: Bilateral or Decentralised model

As is the case for the Pool model, and like every short term electricity wholesale market model, the Bilateral model is complemented by a Balancing market.

2.3.1.9.3 ‘Hybrid’ models Short term electricity markets may combine:

o Bilateral contracts and a voluntary pool OR o Bilateral contracts and a (public, auction-based) Power exchange.

A power exchange offers day-ahead and intra-day trade with the following benefits for the market participants:

o More price transparency, o No counter party risk, o Anonymous trading, o Tool to optimize trading portfolio.

The model with bilateral contracts and a voluntary power exchange has been implemented in several European countries, with exchanges in the Netherlands (Amsterdam Power eXchange), France (Powernext), the Scandinavian countries (NordPool), Germany (EEX), Poland (PolPX) and Austria (EXAA). One can even have several competing exchanges in one country, as was the case in Germany (EEX and LPX) and England (UKPX , APX, PowerEX and IPE).

System Operator(TenneT)

Schedules

Power Exchange

(APX)

Consumer/Trader

Generator /Trader

Schedules

Schedules

Bilateraltransactions

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In addition, pools and bilateral contracts, though so much different, can coexist. The figure below shows the general framework of the two hybrid models.

Source: CIGRE, 2005

Figure 6: Pool model and bilateral trade model

2.3.1.10 Determination of the wholesale price of electricity In a pool model, the price buyers pay and successful bidders are paid is a single price which is determined in the pool. This price, however, varies significantly throughout the day as demand fluctuates. Hence, market participants use hedging instruments, such as Contracts for Difference (CfDs), to manage this price volatility. There is also high likelihood of the imposition of price caps within a pool especially in capacity short situations or where “demand response is limited or absent”.

In the Pool model, the price (uniform for all participants) is provided by the solution of the unit commitment problem (usually formed as a Mixed Integer Program – MIP), and theoretically consists of the shadow price of each hourly load balance constraint.

In a Power Exchange, the hourly price is determined by solving, separately for each hour, the market, as determined by Generator bids and Suppliers (off-takers) offers.

Prices in the bilateral model are negotiated between a buyer and seller.

2.3.2 Electricity markets liberalisation in the EU

2.3.2.1 Drivers of liberalisation and its evolution in the EU The international economic tendency of “less-state” in national productive structures and public utilities has since the 80s been in the focus of reforms particularly in the United States and later on in

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the United Kingdom and the EU. The electricity industry has traditionally been a pivotal area of reforms given its importance in the economy and society in each country. The European Union was already moving in that direction by the Maastricht Treaty of 1992 but specifically laid the legal basis for the organisation of the Internal Electricity market in December 1996 with the Directive 96/92/EC.

The establishment of the internal market in electricity is particularly important to increase efficiency in production, transportation and distribution of electricity, while enhancing security of supply and the competitiveness of European economy with respect to the environmental protection. There were established, under the principle of subsidiary, general authorities for the organization of energy markets at the EU level, but the definition of specific terms application were left to Member States which had decided which best suited to their particular situation status.

There are three packages for the liberalization of electricity markets. The first package for the liberalization of electricity market was adopted at 19 December 1996 with the Directive 96/92/EC. This Directive establishes common rules for the generation, transmission and distribution of electricity. It lays down rules on the organization and conduct of electricity, market access, criteria and procedures applicable to tendering, licensing and exploitation of networks. The completion of a competitive electricity market is an important step towards completing the internal energy market.

The Directive 2003/54/EC, which has introduced the second package for the liberalization of electricity market, emphasizes that fair and impartial access to network is needed as far as the appropriate transmission and distribution systems (vertically integrated enterprises with a distinct legal personality) and finally it is crucial to ensure the independence of transmission system operators and distribution over the producers and suppliers.

The third package for liberalization of the electricity market includes Directive 2009/72/EC and the Regulation 714/2009 on conditions network access for cross-border exchanges in electricity and Regulation 713/2009 establishing the Organization for Cooperation of Energy Regulatory Authorities. This Directive repealed at 3/3/2011, the previous directive 2003/54/EC.

The third energy package in 2009 was considered as the completion of the internal EU energy market and it is supposed to separate the production from distribution, transportation and delivery.

This package "was introduced to reduce energy prices," said Johannes Kleis from the European Organization of Consumers, but we see the prices to get increased in a lot of countries. In countries like the UK, the price of energy for households was increased approximately 140% since 2004, with a percentage of about 90% only in the last 6 years.

Furthermore, at the beginning of its existence the Commission believed that liberalization would increase competition; it would prevent monopolies and would bring benefits in the wallet of consumers.

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"We know that markets bring the best prices and best services," said the Commissioner for Energy Andris Piebalgs in 2007. ‘’You really need to create competition in order to reduce prices’’. 12

The above chronicle of the energy packages succession reflects on the European Commission and the Parliament aim to reach the goals of “Europe 2020 Strategy” through a secure, competitive and sustainable supply of energy to the economy and the society.

Source: CEER

Figure 7: The electricity market liberalisation time-line of the EU Directives

Between the Electricity Directive versions of 1996 and amended in 2003, the EU Institutions had to face a significant fact: despite many efforts to set up an effective EU internal energy market, the correct transposition of the European electricity (and gas) legislation in all Member States was still not complete, monopoly situations still prevailed in some EU Member States, unbundling between transmission, distribution and generation was not successfully implemented.

Because of this, the Third Internal Energy Market Package was adopted in 2009 in order to:

• Accelerate investments in energy infrastructure • Enhance cross border trade and • Allow better access to diversified sources of energy (such as renewable).

Legislation in the 3rd Energy Package:

12 Source: The ‘’Story’’ of the Liberalization of Electricity Market in Europe, Strategy International, July 2012 (http://www.strategyinternational.org/index.php/en/sectors/goeconomicsgeopoliticsgeography/economics/281-the-story-of-the-liberalization-of-electricity-market-in-europe)

http://en.wikipedia.org/wiki/Europe_2020

http://en.wikipedia.org/wiki/Energy_infrastructure

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The Third Energy Package consists of two Directives and three Regulations:

Directive 2009/72/EC concerning common rules for the internal market in electricity and repealing Directive 2003/54/EC

Directive 2009/73/EC concerning common rules for the internal market in natural gas repealing Directive 2003/55/EC

Regulation (EC) No 714/2009 on conditions for access to the network for cross-border exchanges in electricity and repealing Regulation (EC) No 1228/2003

Regulation (EC) No 715/2009 on conditions for access to the natural gas transmission networks and repealing Regulation (EC) No 1775/2005

Regulation (EC) No 713/2009 of the European Parliament and of the Council of 13 July 2009 establishing an Agency for the Cooperation of Energy Regulators

Additionally, the 3rd energy package aimed at reducing market concentration on the EU energy market, where a small number of companies control a large part of the market.

2.3.2.2 The latest step of harmonisation of the EU Internal Electricity Market by means of the 3rd Package

The EU Member States had to transpose the Electricity Directive 2009/72/EC, which are a fundamental part of the Third Energy Package, by 3 March 2011 and to apply them from that date. The Electricity Directive set out key rules necessary for a proper functioning of the electricity market. The new or reinforced requirements concerning the unbundling of networks, the independence and the powers of national regulators and the functioning of retail markets via enhanced consumer protection measures represent major developments compared to the provisions of the Second Energy Package adopted in 2003.

Important rules for the operation of the markets are also set out in the Electricity Regulation (EC) No 714/2009, also part of the Third Energy Package and applicable as from 3 March 2011.

In the electricity sector, the European Union's Third Energy Package is a legislative package for an internal electricity market in the European Union. Its purpose is to further open up the electricity markets in the European Union. The package was proposed by the European Commission in September 2007, and adopted by the European Parliament and the Council of the European Union in July 2009. It entered into force on 3 September 2009.

Core elements of the third package include:

• Unbundling, which stipulates the separation of companies' generation and sale operations from their transmission networks,

• The establishment of a National regulatory authority (NRA) for each EU Member State, and • The Agency for the Cooperation of Energy Regulators which provides a forum for National

regulatory Agencies to work together.

http://en.wikipedia.org/wiki/Directive_(European_Union)

http://en.wikipedia.org/wiki/Regulation_(European_Union)

http://en.wikipedia.org/wiki/Internal_Market_in_Electricity_Directive

http://en.wikipedia.org/wiki/Directive_2003/54/EC

http://en.wikipedia.org/w/index.php?title=Directive_2009/73/EC&action=edit&redlink=1

http://en.wikipedia.org/w/index.php?title=Directive_2003/55/EC&action=edit&redlink=1

http://en.wikipedia.org/wiki/Electricity

http://en.wikipedia.org/wiki/European_Union

http://en.wikipedia.org/wiki/European_Commission

http://en.wikipedia.org/wiki/European_Parliament

http://en.wikipedia.org/wiki/Council_of_the_European_Union

http://en.wikipedia.org/wiki/Ownership_unbundling

http://en.wikipedia.org/wiki/National_regulatory_authority

http://en.wikipedia.org/wiki/Member_State_of_the_European_Union

http://en.wikipedia.org/wiki/Agency_for_the_Cooperation_of_Energy_Regulators

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2.3.2.3 Unbundling in the notion of the EU legislation The organisation of the electricity market in the European Union is provided in the Directive 2009/72/EC of the European Parliament published within the Official Journal dated August 14, 2009 concerning rules for the internal market in electricity ("Directive 2009/72/EC"). Directive 2009/72/EC repealed Directive 2003/54/EC ("Directive 2003/54/EC") that was published in the Official Journal dated July 15, 2003. According to Directive 2003/54/EC, in the case of vertically integrated undertakings, transmission and distribution systems operators within such undertakings were required to be organized under different legal entities with independent decision making mechanisms.

Directive 2009/72/EC emphasized the importance of the independent functioning of distribution and transmission systems especially with regard to other players within the market engaged in generation and retail sales and stated that for this reason, transmission and distribution system operators must have independent management structures. In this context, parent companies were prohibited from giving instructions with respect to the day to day operations of the subsidiary. In addition to these, the unbundling and transparency of accounts were also accepted. However, it did not require ownership unbundling.

Directive 2009/72/EC which is in force today on the other hand, accepts three models of unbundling; setting forth that legal unbundling provided within the Directive 2003/54/EC did not implement effective unbundling with regard to transmission systems. Scholars and policy makers argue that the only way in which effective transparency and prevention of discrimination within the market can be implemented is the removal of the incentive for vertically integrated undertakings to discriminate, by the ownership unbundling of network operations and generation. Accordingly, the unbundling of distribution and transmission system operators has been required for vertically integrated undertakings. The following paragraphs describe briefly the unbundling models provided in Directive 2009/72/EC.

Ownership unbundling

Ownership unbundling is advocated by the European Commission and the European Parliament. This option is intended to split generation (production of electricity) from transmission (of electricity from electrical generating station via a system to a distribution system operator or to the consumer). The purpose of this system is to ensure that the European energy market does not suffer from vertical integration (competition law provisions).

Note that ownership unbundling has brought some tough discussion:

• Some players see there a good option to enhance competition and avoid survival of monopoly situations

http://en.wikipedia.org/wiki/Vertical_integration

http://en.wikipedia.org/wiki/Vertical_integration

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• Some other raise questions as to who can buy the transmission networks, and question whether such a system will regulate the market-place and who will pay possible compensation to the energy firms.

Independent system operator (ISO)

Art. 13 to 16 of the Directive 2009/72/EC give the member states the opportunity to:

• Let the transmission networks remain under the ownership of energy groups, but • Transferring operation and control of their day-to-day business to an independent system

operator. • Investments on the network will be made, not only by the owner’s funding but also by the

ISO’s management. This represents a form of ownership unbundling, but with a trustee. In theory, this would allow transmission and generation to remain under the same owner, but would remove conflicts of interest.

Independent transmission operator (ITO)

Austria, Bulgaria, France, Germany, Greece, Luxembourg, Latvia and the Slovak Republic presented at the end of January 2008 a proposal for a third option. This model, the ITO, envisages energy companies retaining ownership of their transmission networks, but the transmission subsidiaries would be legally independent joint stock companies operating under their own brand name, under a strictly autonomous management and under stringent regulatory control. However, investment decisions would be made jointly by the parent company and the regulatory authority.

In order to exclude discrimination against competitors, one prerequisite is the existence of a compliance officer, who is assigned to monitor a specific programme of relevant measures against market abuse. It is also named a legal unbundling.

2.3.2.4 National Regulatory Authorities Establishment

Chapter IX of the Directive 2009/72/EC requires each Member State to designate a single National Regulatory Authority (NRA).

EU Member States may designate other regulatory authorities for regions within the Member State, but there must be a senior representative at national level. Member States must ensure that the NRA is able to carry out its regulatory activities independently from government and from any other public or private entity.

Functions

http://en.wikipedia.org/wiki/Austria

http://en.wikipedia.org/wiki/Bulgaria

http://en.wikipedia.org/wiki/France

http://en.wikipedia.org/wiki/Germany

http://en.wikipedia.org/wiki/Greece

http://en.wikipedia.org/wiki/Luxembourg

http://en.wikipedia.org/wiki/Latvia

http://en.wikipedia.org/wiki/Slovak_Republic

http://en.wikipedia.org/wiki/Brand_name

http://en.wikipedia.org/w/index.php?title=Legal_unbundling&action=edit&redlink=1

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The Directive sets out eight general objectives of NRAs and 21 specific duties. In addition to a duty to fix or approve tariffs, NRAs have a number of monitoring and reporting duties, and are granted information rights and investigative and enforcement powers to enable them to carry out their duties.

2.3.2.5 Agency for Cooperation of Energy Regulators Regulation 713/2009 establishes an Agency for the Cooperation of Energy Regulators. The purpose of the Agency is to assist NRAs to exercise their duties and to provide means of coordinating their actions where necessary.

2.3.2.6 Cross-border cooperation Regulation 714/2007 aims at laying down rules for cross-border exchanges in electricity with a view to improving competition and harmonisation in the internal market for electricity. It lays down the procedure and condition for the certification of Transmission System Operators; provides for the creation of the European Network of Transmission System Operators (ENTSO) for electricity and its tasks concerning the development of the pan-European network codes following the issuing of Framework Guidelines by ACER.

The following table summarises the key questions connected to the EU electricity third energy package:

QUESTION ANSWER

What is the aim of the "third energy package"?

The aim is to make the energy market fully effective and to create a single EU electricity market. This will help to keep prices as low as possible and increase standards of service and security of supply

What does the 3rd energy package bring to the EU electricity market?

• Effective unbundling of energy production and supply interests from the network. This should eliminate any conflict of interests between these activities. Unbundling should prevent network operators from favouring their own energy production and supply companies

• Increased transparency of retail markets and strengthening of consumer protection rules

• More effective regulatory oversight by independent market watchdogs, the national regulatory authorities

• Establishment of the Agency for the cooperation of Energy Regulators (ACER) to ensure effective cooperation between national regulatory authorities and to take decisions on cross-border issues

• Better cross-border collaboration and investment: a new European Network for Transmission System Operators will bring together EU electricity grid operators to cooperate and develop common commercial and technical codes and security standards.

http://en.wikipedia.org/wiki/Agency_for_the_Cooperation_of_Energy_Regulators

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QUESTION ANSWER

What’s in it for consumers?

Effective and properly regulated competition will offer the best deal for consumers. The Third energy package has introduced new deadlines so that consumers can switch supplier within three weeks.

Why do we need unbundling of transmission networks?

The rules on unbundling aim at preventing companies which are involved both in transmission of energy and in production and/or supply of energy from using their privileged position as operators of a transmission network to prevent or obstruct access of their competitors to this network. Unbundling requires the effective separation of activities of energy transmission from production and supply interests.

Are there different unbundling models?

Yes. The third energy package provides for three basic models for unbundling: Ownership Unbundling (OU), the Independent System Operator (ISO) and the Independent Transmission Operator (ITO). When implementing the unbundling rules of the third energy package EU Member States have to decide whether to implement exclusively the Ownership Unbundling model, or leave to the TSO a choice between the different models.

Ownership Unbundling

If an EU Member State decides to impose full ownership unbundling, all integrated energy companies would have to sell off their electricity grids. In this case, no supply and production company would be allowed to hold a majority share in a transmission system operator, nor exercise voting rights or appoint board members. Supply and production company are free to decide to whom and to what price they sell their networks.

A number of large integrated companies in the EU have already proceeded in this way. For instance in electricity both E.ON and Vattenfall Europe divested their high voltage grid in Germany, while Endesa divested its transmission assets in Spain.

Independent System Operator

Under this model, the supply company can still own the physical network, but it has to leave the entire operation, maintenance and investment to an independent company.

Independent Transmission System Operator

Under this model, the supply company can own and operate the network. The management of the network must be done by a subsidiary of the parent company, which can make all financial, technical and other decisions independently from the parent company. A supervisory body is in charge of preserving the financial interest of the mother company without being involved in the day-to-day business.

Are exemptions of Yes. This is possible for new electricity infrastructure. Under the conditions listed in the Third energy package, the competent national authority may

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QUESTION ANSWER

the regulated regime possible for transmission systems?

grant an exemption (full or partial) from certain obligations, including from the obligation of Third party access, regulated tariffs and unbundling, if the level of risk attached to the investment is such that the investment would not take place unless an exemption was granted. The conditions for obtaining an exemption include that the infrastructure must enhance competition and that the exemption itself must not be detrimental to competition.

Why was the new agency ACER created?

Over the years of working towards creating a well-functioning EU internal market it has become clear that national energy regulators alone and the existing advisory group – the European Regulator Group for Electricity and Gas (ERGEG) – are insufficient to cope with the tasks of regulation at the EU level. Thus it was decided to create an independent body with special expertise on technical issues. This new body ACER is independent from the EU Commission, national governments and energy companies.

What does ACER do?

• Drafting framework guidelines for the operation of cross-border electricity networks. Based on these guidelines the operators of pipelines and electricity networks will establish concrete rules;

• checking that these rules are consistent with these framework guidelines;

• reviewing the implementation of the EU-wide ten-year network development plans as well as national network development plans;

• Deciding cross-border issues, if national regulators cannot agree or ask ACER to intervene. This includes the method by which operators can sell the very lucrative capacities during peak hours, when demand is high;

• Monitoring the functioning of the internal market, including retail prices, available network access for electricity produced from renewable and respect of consumer rights. Each year the agency will publish a report on its findings and it may suggest to the Commission and the European Parliament measures that help remove barriers to the completion of the internal market.

When can ACER take legally binding decisions?

In case national regulators cannot reach an agreement on how to regulate cross-border energy infrastructure ACER will decide on: • allocating the scarce capacity of electricity cables among interested market participants ("capacity allocation")

• sharing the profits from selling the capacity and charges on cable and pipeline users

ACER may "exempt" new cross border electricity cables from some of the rules of the internal energy market. The idea of such exemptions is to increase the profitability of a new interconnector in order to overcome

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QUESTION ANSWER

certain risks which fend off its investors. But this is subject to the approval by the European Commission which must approve any type of exemption from the internal market rules, also including exemptions granted by national regulators.

Source: EU Commission, Memo/11/125, Brussels, 2 March 2011 „Questions and Answers on the third legislative package for an internal EU gas and electricity market“ http://europa.eu/rapid/press-release_MEMO-11-125_de.htm?locale=en

Table 1: Questions and Answers on the third legislative package for an internal EU electricity market

http://europa.eu/rapid/press-release_MEMO-11-125_de.htm?locale=en

http://europa.eu/rapid/press-release_MEMO-11-125_de.htm?locale=en

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2.3.3 Integration of national markets – the EU Internal Energy Market The liberalisation of European energy markets promised many benefits to Europe's citizens and industry: more choice, increased competition pushing prices down, better service and improved security of supply.

The following main steps can be distinguished in the process of the formation of the EU IEM in electricity:

1. 2nd energy Package - Adoption of Regulation 1228/2003 on cross-border trade (2003) and EC Directive 2003/54 (part of the ‘2nd Energy Package’ (2003)

2. The Regional Initiatives, launched by the ERGEG (2006) 3. The 3rd Energy Package (including the EC Directive 2009/72/EC concerning common rules for

the internal market in electricity and Regulation (EC) No 714/2009 on conditions for access to the network for cross-border exchanges in electricity

4. The development and implementation of the ‘Target Model’

These steps are briefly described below.

2.3.3.1 Regulation 1228/2003 and Directive 2003/54 While the 1st Electricity directive (92/1996) focused on liberalisation of national electricity markets (with emphasis to wholesale markets), the Electricity Directive adopted in June 2003 (EC 2003/54) set important rules for the EU Internal Electricity Market (IEM). The opening of a previously closed sector to the EU single market was planned to be achieved through:

• effective ownership unbundling of power generation and supply assets, • free choice of supplier and • enhanced market monitoring and transparency.

In addition, with an aim to intensify trade in electricity, Regulation (EC) 1228/03 was enacted in July 2003. The act regulates the access to the network for cross-border exchanges and spells out the principles of cross-border congestion management:

• Transmission system operators must be compensated for costs incurred as a result of hosting cross-border flows of electricity on their networks. This is prerequisite for an open, competitive market.

• Non-discriminatory and transparent tariffs for access to networks must be set to reflect payments and receipts resulting from compensation between transmission system operators. This is a precondition for effective competition in the internal market.

• In cases of network congestion, the allocation of cross-border capacities shall be addressed with non-discriminatory, market based solutions to give efficient signals to market participants and transmission system operators.

• Different safety, operational and planning standards used by national transmission system operators should be harmonized in order to avoid distortion of competition.

• Publication of relevant data for the market participants to eliminate asymmetries in information.

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As part of the enforcement, the national governments had the duty to lay down the rules on penalties applicable to infringements of the regulation. The penalties had to be effective, proportionate and dissuasive.

Pursuant to the Regulation 1228/2003, congestion management should be based on the following principles:

• economic efficiency and promotion of competition • maximizing of the amount of capacity available and the use made of it • transparency to network users on a non-discriminatory basis • secure network operation • largely revenue neutral mechanisms from the point of view of TSOs.

The Regulation (EC) 1228/03 identified explicit and implicit auctions as an appropriate market orientated measure to allocate available cross-border capacities on interconnectors for cross-border trading.

2.3.3.2 Regional Initiatives within the EU The European Commission set out a statement of the vision and process for the creation of a Single Electricity Market in its March 2004 Strategy Paper Medium term vision for the internal electricity market. This anticipated the integrated single market being reached via the interim step of the establishment and further development of a number of regional markets. Market arrangements within regions are likely to be relatively strongly harmonized, and reflective of strong underlying physical, institutional, and political links. The Nordic region was supposed to be a good example of an existing regional electricity market, although there remained scope for further integration.

Regions or markets would in due course become more closely integrated and so approach the single market paradigm.

Experience by that time had shown that it is not necessary for the establishment of the single electricity market that full harmonisation of national and regional arrangements must occur. However some degree of co-ordination and harmonisation in material areas is likely to be required to ensure that national and regional markets do not create any impediments to effective operation of the overall market. For example, some co-ordination of market rules, clear rules for operation within a market and transparency within and between markets will be required to ensure that market participants act upon their commercial incentives to trade.

2.3.3.2.1 The 1st generation of EU regional initiatives: the 7 “mini-fora”13

For the management of congestion on electricity interconnectors between Member States, the regional approach has been the subject of direct action following the 11th Florence Forum of

13 CEER, 2005: http://www.ceer.eu/portal/page/portal/EER_HOME/EER_CONSULT/CLOSED%20PUBLIC%20CONSULTATIONS/CROSSSECTORAL/Creation%20of%20REMs/CD/E05-PC-04-01_ERGEG_CREATION_OF_REM_DISCUSSIONPAPER_PUBLI.PDF

http://www.ceer.eu/portal/page/portal/EER_HOME/EER_CONSULT/CLOSED%20PUBLIC%20CONSULTATIONS/CROSSSECTORAL/Creation%20of%20REMs/CD/E05-PC-04-01_ERGEG_CREATION_OF_REM_DISCUSSIONPAPER_PUBLI.PDF


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September 2004. The Forum called for the establishment of 7 “mini-fora”. Each mini-forum is a grouping of relevant stakeholders from a number of neighbouring Member States. Each is to provide a plan and detailed timetable for the introduction of at least day ahead co-ordinated market based mechanisms for congestion management between territories. The ‘Central Western’ mini-forum, for

Example, comprised Belgium, France, Germany, Luxembourg, and the Netherlands. A central idea was that these smaller Regions would be able to introduce feasible and pragmatic congestion management methods that take account of local conditions and markets more easily than methods that attempt to cover the whole EU. Each mini-forum was expected to report back progress on its regional initiative on a yearly basis.

2.3.3.2.2 Independent initiatives within EU The regional approach to market integration was also reflected in a number of separate initiatives taken forward by individual member states working in cooperation with others:

• -The Nordic market was a particularly good example of a regional electricity market, where three Member States and Norway adopted a large degree of harmonization methods designed to allow seamless and efficient trade of electricity across the four countries.

• -The Spanish and Portuguese governments have committed themselves to creating a single Iberian market for electricity.

• -The ‘all-island’ electricity market of Ireland: government and regulatory authorities have adopted plans to create an all-island electricity market across the Republic of Ireland and Northern Ireland. A single electricity market across Great Britain came into effect on 1 April 2005 from which point the two separate markets became fully integrated.

Steps were also being taken towards establishing a South East European Energy Market (which would include both EU and non EU states). Finally, in relation to Austria and some parts of France and Germany a common wholesale price area developed as a result of a high degree of interconnection capacity.

2.3.3.2.3 The ERGEG Regional Initiatives CEER considered that the existence of a regional market will be signaled where the following conditions exist:

(i) sufficient transmission capacity exists between the markets within the region and is made available to market participants (such capacity may be made available through the use of implicit or explicit auctions)

(ii) there are no distortions within the local markets which significantly affect the functioning of the regional market

(iii) an appropriate legal and regulatory framework is in place which allows for action across a regional market

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(iv) national institutions within the regional market co-ordinate and co-operate closely with each other within an appropriate legal framework. In particular:

• TSOs working together in order to ensure that interconnector capacity is optimised and allocated efficiently

• Regulators working together and freely exchanging information so that proper monitoring and regulation both of national and regional markets can happen.

In a CEER document14, the following were considered as obstacles to trade within the envisaged EU Internal Electricity Market: Network operations ― The role of the TSO

― Network capacity and investment

― Network access

― Transmission charging

― Live network operation

― Emergency planning and black start

― Network maintenance

― Co-operation between TSOs

― Information provision by TSOs

wholesale market arrangements

― Market types

― Key market characteristics

― Assessment of possible obstacles to effective trade between markets

In June 2006, ERGEG concluded15 that a pragmatic way to achieve this aim would be via the interim step of integrating national markets into regions, in a manner which will allow the subsequent step of full market integration. The idea was that groupings of neigbouring countries with an interest in fostering trade would form a ‘regional initiative’. Thus it was possible to initiate a process to make concrete progress in integrating national markets and so facilitate further the creation of regional markets. Aim for each regional market was to identify specific problems of impediments to trade or distortions to trade, and introduce practical improvements that would contribute to removing such impediments. Such ‘regional initiatives’ should enable local stakeholders to identify, and plans

14http://www.ceer.eu/portal/page/portal/EER_HOME/EER_CONSULT/CLOSED%20PUBLIC%20CONSULTATIONS/CROSSSECTORAL/Creation%20of%20REMs/CD/E05-PC-04-01_ERGEG_CREATION_OF_REM_DISCUSSIONPAPER_PUBLI.PDF 15 http://www.ceer.eu/portal/page/portal/EER_HOME/EER_PUBLICATIONS/CEER_PAPERS/Electricity/2006/ERGEG_REMCREATION-CONCLUSIONS_2006-02-08_0-1.pdf



http://www.ceer.eu/portal/page/portal/EER_HOME/EER_PUBLICATIONS/CEER_PAPERS/Electricity/2006/ERGEG_REMCREATION-CONCLUSIONS_2006-02-08_0-1.pdf


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solutions for, the priority areas for action needed to deliver integrated markets. Hence each regional initiative had as objectives to:

• Identify and publish, based on the priority areas discussed in this conclusions paper and through open consultation with market participants, the priority areas to be addressed in the region.

• Establish and publish a timetable for the technical work required to address these areas, including allocating responsibility for the tasks to the stakeholders most able to accomplish the relevant work.

• Take forward and oversee that this work is done to timetable. Monitor and report progress. Note any reasons for any delay.

The composition of the ERGEG regional initiatives was as follows:

• Baltic States : Estonia, Latvia, Lithuania • Central Eastern Europe : Austria, Czech Republic, Germany, Hungary, Poland, • Slovakia, Slovenia • Central Southern Europe : Austria, France, Germany, Greece, Italy, Slovenia (and Switzerland) • Central Western Europe : Belgium, France, Germany, Luxembourg, Netherlands • Northern Europe : Denmark, Finland, Germany, Norway, Poland, Sweden • South Western Europe : France, Portugal, Spain • UK and Ireland : France, Republic of Ireland, UK

The regional initiatives involved all stakeholders and consulted on proposals for market integration. Each regional initiative would identify its own priority issues needed to best foster market integration, taking into account therefore local details and requirements. Each tried to establish a process for delivering solutions, and so this involved collaboration with and action by, among others, regulators, government, and TSOs.

For the purpose of creating finally a single electricity market it was of utmost importance that each regional initiative considers the need for compatibility of the established processes with those in connected regions, -especially given the (intentional) participation of several countries in more than one regions-, although progress in one region should not be contingent on progress in another.

It was also be important for the overall process to progress compliance with the relevant EU legislation. Full compliance with the EU legislation, in particular the Electricity Directive 2003/54/EC, Regulation (EC) 1228/2003 and the associated congestion management guidelines and other legal instruments of relevance for the European electricity market, had to be ensured in all the activities and deliverables of the regional initiatives, including the mini fora. Furthermore, the results of the related activities at the European level, (e.g. DG-TREN’s reports and Electricity Sector Inquiry by DG Competition) had to be taken into account. Ensuring this compliance was the duty of the national regulators and was reported regularly on an annual basis to ERGEG.

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Governance of Regional Initiatives

Each regional initiative would tailor an organisational framework to its own needs. However the framework should achieve results in accordance with the objectives above, and monitor and report on progress. Some regional initiatives had regulators working closely with member states to identify and publish priority areas for action and action plans for solutions. Regulators and other institutions in countries that are part of more than one region might combine and/or target resources as necessary.

At the core of the framework, ERGEG established Regional Co-ordination Committees (RCCs) which comprised the regulators for each region. Each of the ERGEG’s RCCs had responsibility and authority for driving forward the work in their region. An RCC’s role included acting as overall co-ordinator of the tasks facing the Region and providing leadership, strategy and decisions. Each RCC also consulted stakeholders. The RCC’s duties could therefore include the establishment and lead of the regional projects and activities such as mini fora, defining the way of work, involving stakeholders and setting up priorities, milestones and deliverables in line with the general EU/ERGEG objectives, in suitable collaboration with Member States and the Commission. Each RCC should also ensure compliance with the relevant EU legislation. Each RCC would also be responsible for reporting on the progress of their regional initiative through ERGEG to the Florence Forum.

The following figure depicts the envisaged organizational framework:

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Source: The Creation of Regional Electricity Markets - An ERGEG Conclusions Paper, February 2006

Figure 8: Regional Initiatives- Elements of an organisational framework

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Source: Nina Grall-Elder, 2010

Figure 9: The final 7+1 regions in which “Regional Initiatives” were established

2.3.3.3 The 3rd Energy Package (2009) It is generally accepted that the way in which national markets in the EU were liberalised and integrated was not in the absence of difficulties. The original voluntary character of initiatives for the integration of the EU electricity market achieved progressive but limited national market convergence within a region and created divergences between regions. This made it difficult to take full advantage of liberalisation. Differences in gate closure times, cross-border trading and congestion management methods were not thoroughly addressed or coordinated and, eventually, more top-down regulatory intervention at European level was required.

The introduction of the 3rd Energy Package which came into force in March 2011, created a new context for the achievement of the single European energy market notably through the provision of binding framework Guidelines and Network Codes. These set the legal framework for cross-border transmission management and market integration in an effort to accelerate the progress towards a single European energy market. In addition, the establishment of new European institutions (i.e. ACER and ENTSOs) would complement a binding cross-border regulatory framework.

These measures were expected to transform the context within which the ERGEG Regional Initiatives used to operate from an essentially voluntary one, to one with binding and enforceable rules.

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2.3.3.4 The Target Model for the EU electricity market The above activities, initiatives and legislative framework resulted to the adoption of a ‘target model’ for the electricity sector in the EU.


The main areas of work to achieve the TM were (see Figure 10):

i. A flow-based transmission capacity allocation method in highly meshed networks ii. A single European platform for the allocation and nomination of long-term transmission

rights on interconnectors between countries (or ‘bidding areas’) iii. A single European price market coupling (for the Day-Ahead market) iv. Implementation of continuous implicit cross-border trading (for the Intraday markets) v. Pilot projects for the implementation of balancing markets

The importance of the measures outlined in the TM was underlined by the EU Heads of State meeting at the European Council on 4 February 2011. It agreed to achieve the IEM with all necessary regulatory measures by 2014, and made this a top priority for the European Commission (Figure 11 for the roadmap).

Source: EWEA, 2012

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Figure 10: The EU Target model

Source: EWEA, 2012

Figure 11: The roadmap for the integration of electricity markets across regions

European market coupling for the Day-Ahead16

The target model for the day-ahead timeframe is a European Price Coupling (EPC) model which will simultaneously determine volumes and prices for all price zones in Europe. This solution requires TSOs and PXs to develop common arrangements for each stage of the process, including pre-coupling aspects (such as how much transmission capacity to make available to the market), the coupling solution (the development and implementation of the algorithm) and post-coupling aspects (such as the financial settlement between PXs and between PXs and TSOs). The implementation of a single European price market coupling model follows a step-wise approach which went live first in the North-West Europe (NWE) region on 4 February 2014, quickly followed by its extension to the Iberian Peninsula on 13 May 2014. With this extension, the project has been renamed Multi-Regional Coupling (MRC). Other markets should join as soon as ready.

16 ACER report on ERIs, May 2015 (http://www.acer.europa.eu/Official_documents/Acts_of_the_Agency/Publication/2nd%20ERI%20Progress%20Report.pdf )

http://www.acer.europa.eu/Official_documents/Acts_of_the_Agency/Publication/2nd%20ERI%20Progress%20Report.pdf


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The implementation of day-ahead market coupling made a tremendous step forward on the 24th of February 2015 when the Italian Northern Borders join the MRC. Before this achievement, within the Central East region, the 4 Market Coupling Project which aims at coupling the Czech, Slovak, Hungarian and Romanian with the MRC solution successfully went live on the 19th of November 2014. This milestone is an intermediate step until the North West Europe – Central East Europe Flow-Based Market Coupling project goes live. This area is not coupled with the MRC one due to a difference in the gate closure time.

As of drafting of the present report, the status of implementation of the Day-Ahead markets was as depicted in the figure below.

Source: ACER, 2015

Figure 12: The status of implementation of Day-Ahead markets in the EU

2.3.4 Coordinated Transmission planning The regional approach in electricity, apart from elements dealing with coupling of the electricity markets of the EU neighbouring countries, involves planning for electricity transmission at a level beyond that dictated by strictly national analyses. In that sense, electricity transmission planning in the EU is conducted at three distinct levels:

National level

where according to Article 12 of E.C. Directive 72/2009, every year, transmission system operators submit to their (national) regulatory authority a ten-year network development plan based on existing and forecast supply and demand after having consulted all the relevant stakeholders. The ten-year network development plan:

(a) indicates to market participants the main transmission infrastructure that needs to be built or upgraded over the next ten years;

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(b) contains all the investments already decided and identify new investments which have to be executed in the next three years; and

(c) provides for a time frame for all investment projects.

EU level

Regulation (EC) 714/2009 established ENTSO-E, the network of the EU Transmission Network operators. Thus a global European framework for coordination in transmission and system operation was established. All EU transmission system operators shall cooperate at Community level through the ENTSO for Electricity, in order to promote the completion and functioning of the internal market in electricity and cross-border trade and to ensure the optimal management, coordinated operation and sound technical evolution of the European electricity transmission network.

Among others, ENTSO for Electricity is responsible for elaborating common (EU level) network codes and adopting (Article 8 of Regulation (EC) 714/2009):

(a) common network operation tools to ensure coordination of network operation in normal and emergency conditions, including a common incidents classification scale, and research plans;

(b) a non-binding Community-wide ten-year network development plan (TYNDP), including a European generation adequacy outlook, every two years;

The first Ten-Year Network Development Plan was published by ENTSO-E on a voluntary basis in spring 2010, in anticipation of Directive 72/2009 and Regulation 714/2009. The latest TYNDP of ENTSO-E is available at https://www.entsoe.eu/major-projects/ten-year-network-development-plan/tyndp-2014/Pages/default.aspx .

Regional level

where according to Article 12 of Regulation (EC) 714/2009, EU Transmission system operators shall establish regional cooperation within the ENTSO for Electricity in order that, every two years, they develop and publish a regional investment plan and may take investment decisions based on that regional investment plan. The six (6) regions of Europe for which Transmission Plans are developed are shown in Figure 13 below.

https://www.entsoe.eu/major-projects/ten-year-network-development-plan/tyndp-2014/Pages/default.aspx

https://www.entsoe.eu/major-projects/ten-year-network-development-plan/tyndp-2014/Pages/default.aspx

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Source: ENTSO-E, TYNDP 2014

Figure 13: The 6 Regions for which regional investment plans are prepared in the EU

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2.4 THE ELECTRICITY MARKETS IN KAZAKHSTAN

2.4.1 Electricity sector overview

2.4.1.1 The legal framework governing the electricity sector in Kazakhstan The legal framework governing the electricity sector in Kazakhstan comprises mainly the following acts:

• The Law of the Republic of Kazakhstan "on electric power industry" by July 9, 2004 year(N)588-(II) (with amendments and additions as of July 4, 2013 onwards);

• The Law of the Republic of Kazakhstan "on introduction of amendments and additions to some legislative acts of the Republic of Kazakhstan on the electric power industry, investment activity subjects of natural monopolies and regulated market" (from July 4, 2012 onwards);

• The Law of the Republic of Kazakhstan "on support of renewable sources of energy" from July 4, 2009 year(N)165-(IV) ADMS;

• Law of the Republic of Kazakhstan "on energy saving and increasing energy efficiency by January 13, 2012 year(N)541-(IV)THE ADMS;

• Law of the Republic of Kazakhstan «on competition from December 25, 2008 year(N)12-(IV); • Law of the Republic of Kazakhstan dated July 9, 1998 year(N)272-(I)"On natural monopolies

and regulated markets" (with amendments and additions as on 29.09.2014, 2005); • Resolution of the Government of Kazakhstan from March 10, 2009, no. 277 "on approval of

the rules for determining the estimated tariff approval limits and individual tariffs».

2.4.1.2 Public authorities’ functions and powers in the area of electricity market operation and energy development

The Decree of the President of the Republic of Kazakhstan n. Nazarbayev from August 6, 2014 "on public administration reform in the Republic of Kazakhstan" created and reorganized a number of ministries, which left to the following institutional organisation:

• The Ministry of Energy is in charge of the development and implementation of the State policy in the sphere of power engineering, nuclear energy, oil and gas;

• The Committee of Atomic Energy is in charge of the supervision and control of the Ministry of energy

• Regulatory matters are dealt through the Committee for regulation of natural monopolies and competition of the Ministry of national economy

• The Committee on statistics performs its activities under the auspice of the Ministry of national economy

• The Committee on the protection of consumer rights acts under the authority of the Ministry of national economy

• Lastly energy savings are dealt with through the Institute for the development of electric power and energy saving

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The sectoral/social organizations representing the sector are the following:

• The Association "Kazenergy» • Kazakhstan Electricity Association (KEA) • The Union of Power Engineers

2.4.1.3 Recent developments as regards the legal framework governing the electricity sector Two bodies govern the antimonopoly approach to the sector:

• As of August 6, 2014, the Antimonopoly agency became a Committee under the Ministry of Energy.

• A Committee for Regulation of Natural Monopolies and of Protection of Competition has been set up within the Ministry of Economy and Industry

• There is no Energy Regulatory Authority as such in Kazakhstan, the Ministry of Industry and Economy undertakes the regulatory role through the Antimonopoly Committee.

• The market organization can be summarized as follows: o The Ministry of Industry and of National Economy / the Committee of protection of

competition undertakes the role to overview the transmission , supply and retail tariffs/ and price formation;

o The Ministry of Energy monitors competition among electricity generators/ generation tariffs;

Capacity market mechanisms to be implemented in 2015 will be implemented through Ministerial order

In June 2014, the Concept of Fuel and Energy complex for Kazakhstan until 2030 has been adopted. Such strategy paper refers to oil, gas, electricity and gas sectors.

Currently, the Ministry of Industry and Energy is preparing amendments to the Laws on Energy. It is planned that the Parliament will consider and comments on such amendments in spring 2015.

During the summer 2015, secondary legislation to the amended energy laws will be adjusted accordingly.

2.4.1.4 Competition law and regulatory specificities in Kazakhstan The Antimonopoly Committee is the key institution/body regulating the electricity market in Kazakhstan. At a regional level, there are no responsibilities foreseen for the regulatory function in the sense of regulatory institutions in the EU and other OECD countries in Kazakhstan and all affairs are coordinated by the Ministry of Energy.

2.4.2 The Kazakhstan’s Wholesale Electricity Market

The main actors

The main actors of Kazakhstan’s Wholesale Electricity Market are as follows:

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• The recently reorganized Ministry for Energy, responsible for the whole energy sector of Kazakhstan17

• The Agency for the Regulation of Natural Monopolies (AREM) regulates tariffs in the sector • The Agency for Competition Protection (AZK) monitors operation of competitive markets to

detect market power abuses and prevent market manipulation • KOREM - The Kazakhstan Wholesale Energy and Capacity Market Operator, which operates

centralized trading platform for the short-, mid-and long-terms trading. • KEGOC –the Transmission System Operator -, which includes the National Dispatch Center

and serves as the system operator of the National Electric Power System

Wholesale Market organization18,19

• The electricity market in Kazakhstan is based on bilateral contracts and their mandatory physical implementation

• In addition, KOREM performs 2 types of auctions: o “Day ahead” auctions o Forward auctions (medium-term for a week, month and long-term for a quarter,

year) • On the basis of bilateral contracts and the results of centralized trading, the System Operator

prepares the preliminary dispatch schedule • Balancing:

o is performed by the System Operator with involvement of power systems of Russia, Kazakhstan, Kyrgyzstan and Kazakhstan

o The rules for balancing market were developed in 2007-2008. The balancing market still operates in “imitation” mode. In January 2008 the Balancing Market started work in a simulation routine

• Wholesale market buyers are electricity supply organizations which resell electric power to retail consumers.

Market Participants

The market actors of the wholesale market of electricity are the following:

ELECTRICITY TRADING

17 The Ministry of Energy of the Republic of Kazakhstan is the central executive body of the Republic of Kazakhstan, which is responsible for development and implementation of state policies, coordination of management process in the areas of oil and gas, petrochemical industry, transportation of hydrocarbons, state regulation of production of oil and gas, pipeline, power, coal, nuclear energy, protection of environment and natural resources, control over management of natural resources, development of renewable energy, control over state development policies of "green economy ". http://www.primeminister.kz/page/ministerstvo-energetiki-respubliki-kazahstan 18 USAID, Kazakhstan’s Electricity Market: Distinct Characteristics, by Michael Bekker, April 14, 2011, Bishkek, Kyrgyzstan 19 The Kazakh Operator of Electric Power and Capacity Market, KOREM JSC, Republic of Kazakhstan

http://www.primeminister.kz/page/ministerstvo-energetiki-respubliki-kazahstan

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o power generation companies, supplying the wholesale market of electricity in the amount of not less than 1 Mw average power (Basic);

o electricity consumers who purchase power on the wholesale market in the amount of not less than 1 Mw average power (Basic);

o energy supplying organizations who do not have their own power grids and buy electricity on the wholesale market for resale (to retail consumers) in the amount of not less than 1 Mw average power (Basic);

TRANSMISSION

o power transmission companies20;

Wholesale market tariffs21

• In 2009, with the deterioration of the generating capacity of the power plants, “ceiling cap” tariffs were introduced (up to 2015) for all generating companies in Kazakhstan. The generating companies were divided into 13 groups and a “ceiling cap” tariffs were set for each group. No payment is to be made above this tariff to the generating companies

• “Ceiling cap” tariffs are set as a one-part rate(in Tenge/kWh) • The “ceiling cap” tariffs were introduced to address the short- term generating capacity

shortages by allowing the generating companies to refurbish their plants and meet their investment commitments. The generation companies assumed the responsibility to implement investment program and respect the commissioning dates of the modernized facilities

• After the introduction in 2009 of the limit of tariffs the bulk of electricity on the wholesale market is based on a medium-or long-term bilateral contracts between wholesalers and wholesale purchasers of electricity. The remaining submarkets of the wholesale electricity market do not operate. The only part of the Kazakhstan wholesale market where a price signal is generated is the KOREM trading platform

The introduction of the above mentioned marginal tariffs resulted to the following: exporting power to Kazakhstan has become more difficult as the replacement of more expensive Kazakhstan power by less expensive imported power resulted in a risk that the Kazakhstan power plants wouldn’t be able to meet their investment commitments

2.4.3 Key challenges of the power sector in Kazakhstan

20 Under the current ownership structure of the transmission segment, most networks above 220 kV are on the owned by KEGOC, but part of the networks with voltage 220 kV is owned by the Regional Electricity Companies (RECs), which complicates their optimization and development. The large number of power transmission organizations complicates the adoption of transmission tariffs due to the need to take into account the individual characteristics of many companies. Also, the large number of transmission companies leads to high costs for electricity transmission services due to non-use of economies of scale in the apportionment of the expenses of the maintenance of electrical networks and overhead costs (source: ‘Concept Paper’, 2014). 21 Source: Bekker (2011)

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The following key issues of the electricity market appear to be of increased importance for the development of the power industry of the Republic of Kazakhstan22:

1) the centralized electricity market, of which one the key objectives is to provide the market participants with price signals, does not appear to be not liquid enough and therefore is practically distant from this objective;

2) the balancing market, which in term should aim to stimulating participants in order for the latter to be able to plan their consumption and encouraging producers to follow instructions by the system operator, does not work;

3) the absence of an automated system for control and metering (Energy Management system - EMS) does not allow to correctly allocate among participants of the wholesale market the daily consumption, therefore, intraday price fluctuations;

4) the view that the current price caps on wholesale market do not allow for sufficient incentives for the construction of new generating capacity and that the market lacks of a mechanism for guaranteeing investments in electricity generation has gained momentum in the country , and thus establishment of a capacity market is planned from 2016 and on. However, not all market actors agree on the necessity of this approach: some stakeholders as for instance the Kazakhstan Electricity Association (KEA) which represents a number of generating and supply companies believe that such mechanisms are not absolutely necessary at the present stage.

5) regulation of wholesale generation prices does not create incentives to improve the efficiency of power producers;

6) investment commitments contained in marginal rates, are not provided with the necessary level of performance monitoring;

7) tariff caps system in conjunction with the absence of a detailed Supply Code which would regulate the relationships between the suppliers and their customers, reduces the transparency of transactions between providers and consumers in the market of bilateral contracts.

8) attracting private investment: at the current stage government is apparently dominating the capacity assurance issues for reasons related to national economic and energy policy. Private investments in the Kazakhstan electricity sector are in turn not significant due to the existence of the following key industry issues:

i. governance is characterized by moderate efficacy for stimulating the development of electric power, lengthy and cumbersome administrative procedures;

ii. lack of full competition in the electricity market because of the high percentage of public ownership and the development of financial-industrial holding companies, each with its own generating capacity;

2.4.4 Gap analysis on the legal basis governing the Kazakh and EU electricity markets

22 Source: ‘Concept Paper’, 2014 and discussions of the project experts with stakeholders.

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The purpose of this section is to provide for a gap analysis of the provisions set forth in the EU electricity Directive, organising EU internal electricity market with the legal and regulatory basis governing Kazakhstan Electricity Market. The following section will first describe the key features of EU electricity Market against the existing Kazakhstan power market.

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2.4.4.1 Key provisions of the EU Electricity Market The EU electricity market is organised around the provisions of the 2009 Electricity Directive complemented with the third energy package23. The Electricity is Directive is aimed at introducing common rules for the generation, transmission, distribution and supply of electricity. It also lays down universal service obligations and consumer rights, and clarifies competition requirements. Rules for the organisation of the sector

The rules for the organisation of the sector are aimed at developing a competitive, secure and environmentally sustainable market in electricity. EU Member States may impose on companies operating in the electricity sector public service obligations which cover issues of security and security of supply, regularity and quality of service, price, environmental protection and energy efficiency. EU Member States shall ensure that all customers have the right to choose their electricity supplier and to change supplier easily, with the operator’s assistance, within three weeks. They shall also ensure that customers receive relevant consumption data. Electricity suppliers are obliged to inform final customers about: Information of customers

• the contribution of each energy source; • the environmental impact caused; • their rights in the event of a dispute.

EU Member States shall put in place an independent mechanism (energy ombudsman or consumer body) to manage complaints or disputes efficiently. Member States are also obliged to ensure the monitoring of security of supply. They shall define technical safety criteria to ensure the integration of their national markets at one or more regional levels. In addition, the national regulatory authorities are to cooperate with the Agency for the Cooperation of Energy Regulators to guarantee the compatibility of regulatory frameworks between regions. Generation

Member States shall define criteria for the construction of generating capacity in their territory taking account of aspects such as:

23 Cf. Directive 2009/72/EC of the European Parliament and of the Council of 13 July 2009 concerning common rules for the internal market in electricity and repealing Directive 2003/54/EC.

http://europa.eu/legislation_summaries/energy/internal_energy_market/en0013_en.htm

http://europa.eu/legislation_summaries/energy/internal_energy_market/en0013_en.htm

http://eur-lex.europa.eu/LexUriServ/LexUriServ.do?uri=CELEX:32009L0072:EN:NOT

http://europa.eu/legislation_summaries/energy/internal_energy_market/l27005_en.htm

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• the security and safety of electricity networks; • the protection of health and public safety; • the contribution made towards the Commission’s “20-20-20” objectives.

Transmission system operation/ Unbundling

From 3 March 2012, Member States must unbundle transmission systems and transmission system operators. Any company must first be certified before being officially designated as a transmission system operator. A list of transmission system operators designated by Member States shall then be published in the Official Journal of the European Union.

Transmission system operators are mainly responsible for:

• ensuring the long-term ability of the system to meet demands for electricity; • ensuring adequate means to meet service obligations; • contributing to security of supply; • managing electricity flows on the system; • providing to the operator of any other system information related to the operation,

development and interoperability of the interconnected system; • ensuring non-discrimination between system users; • providing system users with the information they need to access the system; • collecting congestion rents and payments under the inter-transmission system operator

compensation mechanism.

Distribution network operation

Member States shall designate distribution system operators or require undertakings that own or are responsible for distribution systems to do so. Distribution system operators are mainly responsible for:

• ensuring long-term capacity of the system in terms of the distribution of electricity, operation, maintenance, development and environmental protection;

• ensuring transparency with respect to system users; • providing system users with information; • covering energy losses and maintaining reserve electricity capacity.

Member States have the option of putting in place a closed distribution system to distribute electricity within a geographically confined industrial, commercial or shared services site.

http://europa.eu/legislation_summaries/energy/energy_efficiency/en0002_en.htm

http://eur-lex.europa.eu/JOIndex.do?ihmlang=en

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Unbundling and transparency of accounts

Member States and the competent authorities have right of access to the accounts of electricity undertakings but shall preserve the confidentiality of certain information. Electricity undertakings shall keep separate accounts for their transmission and distribution activities.

Organisation of access to the system/ Third Party Access

Member States shall organise a system of third party access to transmission and distribution systems. The tariffs based on that system shall be published. Member States shall also lay down criteria for the granting of authorisations to construct direct lines in their territory, on an objective and non-discriminatory basis.

National regulatory authorities

Member States shall designate a regulatory authority at national level. It shall be independent and exercise its powers impartially. It is mainly responsible for:

• fixing transmission or distribution tariffs; • cooperating in regard to cross-border issues; • monitoring investment plans of the transmission system operators; • ensuring access to customer consumption data.

Retail markets

Member States shall ensure that contractual arrangements, commitment to customers, data exchange and settlement rules, data ownership and metering responsibility are defined.

Non-household customers may contract simultaneously with several suppliers.

Derogatory measures

A Member State may take the necessary safeguard measures in the event of a sudden crisis in the market or where the safety of persons is threatened. Derogations may also be obtained in the event of operating problems in isolated systems

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2.4.4.2 Gap Analysis Kazakhstan electricity market organisation differs from the EU internal market model in the sense that the steps relating to market opening, independent sector regulation, unbundling of generation/transmission/ distribution are not at the same stage of development24.

However, even though some significant discrepancies remain between the EU and the Kazakhstan models a Gap analysis shows in Kazakhstan legal framework grounds for further market opening and regulation. The following table provides for the main findings quoted above:

Grounds for meetings points with EU internal market provisions

Provision of Kazakhstan 2009 law on Natural monopolies

Assessment

Consumer protection against abuse of dominant position

Article 5. Restriction of the activities of the natural monopoly entities. Paragraphs 2, 3, 4, 5

It is not clear whether Article 5 paragraph 2 point to unbundling as set in Article 9 of the Directive 2009/72/EC. The whole Article is a mixture of different important issues and its separation into different parts would make it more clear and specific.

Price regulation in the interest of customer protection

Article 7. Obligations of a natural monopoly entity Paragraphs 1, 2, 2-2, 2-3, 3

System ability, non-discrimination, security of supply is at the front place in the EU law. These concepts could be included into KZ law in the frame of legal approximation of Kazakhstan law with the EU energy acquis.

Consumer protection Article 7. Obligations of a natural monopoly entity Paragraph 3-1

There is a good starting point for the principle of consumer protection but further legislative development is needed. Principle of non-discrimination may be further developed taking note on the provisions of the EU acquis.

Unbundling/separation of accounts

Article 7. Obligations of a natural monopoly entity Paragraph 7-1

In general, KZ law appears to have similarities with the EU law. The basis of the concept is quoted in the KZ legislation but further development is needed should increased competition is envisaged in

24 Please note that the analysis made in this section is based on an Unofficial translation of the Law of the Republic of Kazakhstan from July 9, 1998 No. 272-I On natural monopolies and regulated markets.

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Assessment

the generation and supply sectors of the electricity market in Kazakhstan. The EU acquis provides for specific (and diversified) requirements on the unbundling of the TSO and DSO.

Transparency principles for consumer protection

Article 7. Obligations of a natural monopoly entity Paragraphs 7-3, 7-4

In general, KZ law appears to have similarities with the EU energy acquis as far as this specific article is concerned. However, further rules with regards to some compliance programme or plan shall be elaborated for the broader enhancement of transparency particularly with regards to abuse of dominant position.

Consumer protection Article 7. Obligations of a natural monopoly entity Paragraphs 8, 9

The basis of the concept is quoted in the KZ legislation but further development may be needed in order to enhance consumer protection. . Further rules related to e.g. smart meters could be implemented.

Transparency of accounts Article 7. Obligations of a natural monopoly entity Paragraph 11

In general, KZ law appears quite similar with EU law in this respect.

Consumer Protection Article 7. Obligations of a natural monopoly entity Paragraphs 12, 13

Paragraph 12 is not clear. Directive contains number of provisions regarding consumer protection. However, it is not clear what the phrase “at entering into agreements for provision of regulated services” means. There are no relevant provision regarding necessity to notify the competent authority and consumers of decrease in tariffs in the EU

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Assessment

Electricity Directive. Separation of accounts Article 7. Obligations of a natural

monopoly entity Paragraph 17

No relevant rules regarding pricing on regulated market in the EU electricity acquis but rather a set of competition law /consumer protection requirements which derive from general legal protection of EU law provided to consumers.

Price regulation in order to avoid abuse of dominant position

Article 7-2. Pricing in regulated markets Paragraph 1, 2, 2-1, 3

No relevant rules regarding pricing on regulated market in the Directive. There are however provisions related to Universal Service and Public Service Obligation which may be elaborated in the detail by Member States so as to ensure that vulnerable consumers are protected.

Transparency Article 7-3. Obligations of regulated market entities 1, 2, 3

No relevant rules in the Directive.

Consumer protection Article 7-3. Obligations of regulated market entities Paragraph 4

The basis of the concept is quoted in the KZ legislation but further development is needed.. The issues should be taken separately and further developed. Moreover, right to change the supplier could be introduced in KZ law.

Consumer protection

Article 10. Rights of the consumer of services (goods, works) of a natural monopoly entity Paragraphs 1, 2, 3, 4, 5

In general, EU law comprise similarities with the KZ law in this respect. Further rules on monitoring shall be implemented.

Regulation of the sector Article 13. Functions of the competent authority

Third Party Access approach from Kazakhstan widely differs from the EU provisions. Approximation of KZ Third

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Assessment

party access rules with EU ones would need a separate approach on whether and how the KZ system may be approximated with the EU energy acquis.

Regulation of the Sector Article 13. Functions of the competent authority Paragraphs 5, 6

In general, KZ law comprises similarities with EU law taking into account that the latter provides for specific functions and responsibilities that would both response to the national and the EU context.

Regulation of the Sector Article 14. Rights of the competent authority

In general, KZ law is compatible with EU law. Practical implementation of such provisions in KZ may need to be addressed through secondary legisation.

Regulation of the Sector Article 14-1. Obligations of the competent authority

The procedure of formation of tariff is not addressed by the EU Directive, except for general rules that are already expressed in KZ law.

Competition / Price regulation

Article 15-1. The procedure of formation tariffs (prices, charge rates) or limits on regulated services (goods, works) of the natural monopoly entity

Investment procedure is not addressed in detail by the Directive.

Ground for Capacity Market

Article 15-3. The procedure for approving investment programme (project) of the natural monopoly entity and analysis of its performance Paragraph 1, 4

No relevant rules in Directive 2009/72/EC. But it worth mentioning that the concept of “natural monopoly” is specific to CIS countries (incl. KZ) and in the frame of approximation of EU energy acquis. As such the concept of monopoly is considered as illegal on the EU legal system.

Consumer Protection Article 18-1. Grounds and procedure for notification or approval of actions in the sphere of natural monopoly

In general, KZ law comprises similarities with the EU acquis.

Competition Law/ tendering process

Article 18-4. Especially the procurement of the natural monopoly entity

No detailed rules regarding further proceedings, passing materials etc. in EU law but it

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Assessment

Paragraphs 1, 2 exist at a national level in EU Member States.

Regulation of the sector Article 18-7. Decision of the competent authority following the inspection of the natural monopoly entity and the regulated market entity

In general, KZ law comprise similarities with the EU law.

Regulation of the sector Article 19. Consequences of violating this Law

In general, KZ law complies with EU law.

Consumer Protection Article 21. Compensation by the natural monopoly entity, regulated market entity for the losses caused by a violation of this Law

Not applicable to the EU law. Usually sanctions are part of the powers exercised by the National Regulatory Authority at Member State level or the Competition Authority at Member State/EU level

Source: own analysis

Table 2: Legal gap analysis comparting the Kazakhstan and EU electricity market related legislation

2.4.5 Prospects for the development of the future electricity market in Kazakhstan

If the forecasted demand growth in Kazakhstan materializes, it might be difficult to be covered from the existing (old & inefficient) stock of generation units. Activation of private investors in the electricity sector might add towards increasing efficiency and thus lowering the costs of the sector, a prerequisite for reforming the retail tariffs towards cost-reflective levels. A possible approach which used to be an industry practice (and continues to a certain extent) in the EU comprises simple and realistic options which may be followed as briefly presented below.

Estimation of generation capacity needs should be done with due care concerning electricity export prospects; risks for investments to cover such needs should be left almost in their totality to the private sector. On the other hand, domestic demand should be covered with the necessary reliability offered in modern economies. To this objective, power system planning (both generation and transmission, for a horizon in the order of ten years) should be done according to international practices and quality standards. All options (e.g. refurbishment of existing plants vs. creation of new plants) should be treated in the analysis with due attention in cost and reliability features and numbers used for the various technical options.

In the aforementioned analysis, one should try to avoid cross-subsidization in the production of heat and electricity on the CHP. Such cross-subsidization reduces investment attractiveness of projects for the construction of a thermal power plant due to the overestimation of the cost of the electricity produced in CHP plants, and electricity becomes uncompetitive in the wholesale market.

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Tariffs and revenue collection should ensure the viability of the system. Subsidisation of specific categories of consumers (low income, remote areas, etc.) should be explicitly calculated and included either in the tariffs or through appropriate financial subsistence (provided either to the electricity sector -generators, network companies- or outside of the electricity market). In both the latter options, the expenses should be covered from the public budget and foreseen on an annual basis or equivalently each regulatory period.

Unbundling of accounts (e.g. for energy, for reserves, for transmission, for distribution, for system operation, etc.) should be also a priority, given that such unbundling will help identify inefficiencies in a much easier and transparent way.

Benchmarking of the costs of the various categories in the electricity market should be performed often (e.g. on a 2 years basis) according to international standards and with participation of accredited accounting firms.

New capacity should be procured according to auctions, in quantities as they are calculated based on the aforementioned long-term plan. PPAs are considered to be an appropriate approach at the current state of the market.

A comprehensive and efficient market monitoring system should be established. Market monitoring reports should be produced on a 3-month and yearly basis.

In addition, to assigning the monitoring and regulation function of the electricity (and heat) sector in one body it might add to efficiency in the operation of the sector. More specifically, the integration of responsibilities that now belong to AREM (Agency for the Regulation of Natural Monopolies, mainly regulating tariffs) and AZ K (The Agency for Competition Protection which monitors operation of competitive markets) will improve the capabilities of the singe institution to detect market power abuses and prevent market manipulation. Such a regulatory body would, for example approve the power system development plans (both generation and transmission) which should be in turn developed by KEGOC in collaboration with the regional transmission companies.

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2.5 ELECTRICITY SECTOR INVESTMENTS UNDER A LIBERALISED MARKET REGIME

2.5.1 Background

In countries with energy only wholesale power markets, the rise of variable renewable energy production with very low marginal costs—and, in some cases priority dispatch—is depressing wholesale market prices and displacing marginal thermal power producers which cannot meet their fixed operating costs with reduced operating hours.

For example, in the California market in 2013, the Department of Market Monitoring estimated that energy market revenues for a new combined cycle plant would be $296.39/kW-yr. in comparison to the $256.78/kW-yr. in operating costs and $175.80/kW-yr. in annualized fixed costs25. The remainder of the costs would have to be covered by capacity market revenues.

As a result, an increasing number of conventional power stations are being retired, thereby removing large quantities of firm capacity from the system. At the same time, the variable or intermittent nature of renewable energy requires more firm capacity to be available on a stand-by basis to cover shortfalls in renewable energy production due to weather conditions.

Furthermore, in the EU, US and other developed markets, the impact of environmental regulation such as the Large Combustion Plant Directive or US Environmental Protection Agency (EPA) regulation has hastened the closure or limited the running of coal- fired power stations and this will only be accelerated by the forthcoming application of the EU Industrial Emissions Directive. Moreover, the delay in the commercialization of CCS technology has meant that there has been little or no recent investment in new coal-fired capacity in many EU Member States or in the US. Similarly, several countries, such as Germany, have announced the closure of their nuclear power stations and others, such as the UK, will be unable to commission new nuclear capacity before the scheduled closure of existing capacity. At the same time, the unattractive economics of operation in many EU electricity markets of gas-fired plant relative to coal-fired plant due to higher fuel costs and lower CO2 values has led to the displacement of the former by the latter in the merit order and the withdrawal of considerable amounts of gas-fired capacity, including those with high efficiency and lower CO2 emissions such as newly built CCGT plants.

These factors have led to a marked reduction of investment in replacement conventional power plants such that there is now a perceived risk in many EU Member States of substantially reduced reserve margins so that long- term generation adequacy (i.e. access to sufficient firm generation capacity to meet the highest projected demand) may be jeopardized.

Moreover, increasing levels of intermittent renewable energy production creates an additional requirement for conventional generation plants that are able to operate flexibly in back-up mode, since renewable energy cannot be relied upon as a capacity provider (given imputed firm capacity values in the order of five to ten percent of rated capacity) and therefore can only make a minimal contribution to required reserve margin levels. However, because renewable energy has a high

25 Renewable Generation and Capacity Markets, by Peter H. Griffes, IAEE

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variability, the conventional plant that has to provide the reserve margin must be capable of following a much more volatile and unpredictable demand profile than has previously been required, which calls for more technically competent plant capable of much greater flexible operation in order to provide system stability.

2.5.2 Investments in generation & Capacity support schemes

2.5.2.1 New generation capacity in liberalized markets In competitive liberalised markets, there exist several mechanisms to create new investments in generation26. These are presented in the following paragraphs.

New generation under simple ‘licensing’ requirement

The main trend is to allow investors to freely invest in generation, as a competitive activity. To exercise this right, an investor must obtain a generation or production license, usually from the respective (national) Regulatory Authority for Energy. The licensing/authorization scheme guarantees that any potential investor satisfying a set of conditions, which are in turn ex-ante regulated, may proceed with their generation investment. The scheme pre-conditions that investors receive and carefully evaluate market information and price signals in order to be able make informed decisions in relation to their investment and in particular its risk profile.

Competitive tendering – TSO auctions

Because of the specificities of the electricity as a commodity, as well as its importance for society, most countries do foresee a ‘quick’ mechanism to create new capacity, while still retaining some aspects of competition: (usually) TSOs are allowed to perform tenders for new generating capacity. Such tenders usually pay (at least a significant part of) the investment cost of the new plant and the rest is to be recovered through the unit’s participation in the electricity market.

The EU Electricity Directive 2009/72/EC already envisages Tender Procedures for new generation capacity in the interest of security of supply.

2.5.2.2 Energy-only markets versus markets with capacity mechanisms In energy-only market designs, the (only) traded commodity is electricity (MWh/h). In such markets, the supplying companies get revenues only by selling electricity, either in organized wholesale markets and/or through bilateral contracts with customers. The companies recover capital and fixed costs of power generation because the selling prices or the wholesale market prices turn out to be higher than the variable costs (mostly fuel costs) of power generation, either continuously or periodically, but in a sufficient number of hours. Generation capacity adequacy is supposed to be derived from the resulting market dynamics. In well-functioning markets generators bid their marginal cost to the market and the demand side bids according to the marginal Value-Of-Lost-Load (VOLL). (Hourly) prices are determined according to marginal bids, i.e. prices are set so that supply equals demand. If there is excess capacity, prices are set equal to the highest supply-side bid. In scarcity situations prices should increase and compel supply to increase according to marginal costs

26 Power Purchasing Agreements (PPAs) are not considered here as they exhibit only minimum elements of competition (i.e. mainly during the tendering phase)

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and demand to retract at price levels corresponding to the marginal VOLL until the market balance is restored. According to this dynamic, demand and supply responses to prices in the energy-only markets can be relied upon to secure the balance between supply and demand. Moreover, scarcity pricing ensures revenues to cover capital cost of peak (and other) generation capacity.

By contrast, market designs with explicit capacity mechanisms recognize two market commodities, namely electricity (the output) and generation capacity (the means). Introducing capacity mechanisms imply that generators receive payments for the mere availability of capacity in addition to revenues obtained from the energy market. One might say that in a market with an explicit capacity mechanism the energy market is still the main instrument for short term optimization of resources, while the capacity mechanisms is the main instrument for long term development of generation capacity.

2.5.2.3 Capacity support schemes The specific features of electricity impact on the economic mechanisms driving investment in generation capacity. In addition, electricity markets tend to create conditions which hinder or do not provide enough incentives for investments in generation capacity. Thus, under specific circumstances the investment costs in generation may become difficult to recover and this may create the need for capacity support schemes.

Capacity adequacy concerns mostly relate to distortions in the market outcome under conditions of scarcity. Scarcity hours are particularly important in the electricity industry because a large portion of some generator’s fixed costs (capital costs or CAPEX) must be recovered during these hours. In fact the generating unit with the highest variable cost in the system (the ‘marginal’ unit) should cover its entire fixed cost by producing during scarcity hours, as it is during these hours –under conditions of a market of perfect competition- that the market price is greater than the variable cost of the marginal generator. Even moderate distortions of the electricity prices prevailing during scarcity hours, or in the number of scarcity hours, could have a major impact on the generator’s profitability (and viability). Motivations supporting the introduction of capacity support schemes include:

• A large part of electricity demand is inflexible in the short run. When this part of demand exceeds available generation capacity, involuntary load shedding may become necessary. In this case the price of electricity must be set administratively and this may bias the incentives to invest in generation capacity (as, in general, politicians, dislike high prices under any conditions, they would tend to set prices below the levels which would render viable the ‘marginal’ units).

• Prices (of energy and operating reserves) not rising to levels that correctly reflect conditions of scarcity. In this case the generation capacity is under-remunerated in scarcity situations, which results in under investments.

One may distinguish between three main models of capacity mechanisms27:

1. Capacity payments, in which capacity receives a fixed payment to be available in the market

27 https://ec.europa.eu/energy/sites/ener/files/documents/20130207_generation_adequacy_study.pdf

https://ec.europa.eu/energy/sites/ener/files/documents/20130207_generation_adequacy_study.pdf

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2. Strategic reserves, in which targeted capacity is compensated to be kept in reserve and is not bid into the market

3. Capacity markets, in which a capacity requirement for the market is defined and the compensation paid is determined by supply and demand of capacity

A more general taxonomy of capacity mechanisms is as follows28:

Source: European Commission, ‘Capacity Mechanisms in Individual Markets within the Internal energy Market’, June 2013

Figure 14: Taxonomy of capacity mechanisms

All main types may be designed in many different fashions The specific design may be crucial for the market effects of the mechanism. Important characteristics include:

• Whether mechanisms are market wide or targeted: Differentiation between different kinds of capacity, and demand side participation.

• Whether obligations refer to the present or the future, or both. • How the level of (adequate) capacity is determined. • How availability is documented or certified. • How the capacity payment is determined: Whether prices are set administratively, according

to auctions or in the market. • How the costs are allocated: Whether the capacity obligation is imposed on the TSO

(centralized) or on Load Serving Entities (LSE) (decentralized). • The rules for operation and activation of the capacity, including participation in energy

markets.

2.5.2.3.1 Capacity Payments Capacity Payments are administratively set payments per MW of available capacity, regardless of whether it is dispatched to run. They constitute of direct, fixed capacity payments in addition to

28 Report by RTE – ‘French Capacity Market’, 2013

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revenues accruing from energy sales in the market. The direct capacity payment strengthens the incentives to invest in new capacity and to maintain old capacity.29

The capacity payment is defined and controlled by a regulatory body and offers great flexibility in terms of differentiation of payments and targeting of payments. The capacity payment may apply to all capacity or to specific plant types. Alternatively it can be differentiated between capacity suppliers, e.g. between base-load and peak capacity, existing and new capacity, etc. Demand side resources are typically not eligible for capacity payments.

Capacity payments may refer only to the present, but may also apply (exclusively) to new capacity. In the latter case, the payment is explicitly aimed at amplifying the investment incentives for new capacity.

Capacity payments do not require definition of a specific reliability margin. The level of payment may however be made subject to the actual reserve margin (dynamic capacity payments), in which case one must define the range of reserve margin that the payment applies for. As the capacity payment level is typically defined by a regulatory body, an explicit reliability standard or reserve obligation is not imposed on the TSO or on LSEs. The costs of capacity payments are covered by levies collected by LSEs. The fee is typically proportional to the amount of electricity supplied, usually in the form of an uplift charge on energy purchased. The uplift charge may be dynamic or fixed.

The generation from the capacity that receives capacity payments is sold in the wholesale market, i.e. it on the power exchange or through bilateral contracts. Capacity payments are often used in cases of price caps in the wholesale markets in order to avoid extreme price spikes.

Capacity payments have several drawbacks: It is difficult to determine the right level of payment and to determine the effect of the payments, and the mechanism provides no guarantee against price spikes or market power. Another important drawback is that capacity payments are very inaccurate, it is not clear what consumers pay for and what they get in return. In some cases (e.g. in Greece) the TSO provides a ‘required’ capacity study (an ‘adequacy’ study) but is not totally clear how the results of such a study relate to the amount (MW) of capacity to be remunerated or to the size (e.g. $/MW) of the capacity payment.

2.5.2.3.2 Strategic reserves Another simple capacity mechanism is to make contracts for long term reserve capacity to ensure access to sufficient reserve capacity, so-called strategic reserves. Generation capacity in the strategic reserve is held as back-up, ready to generate when called upon, and is not bid into the market. The strategic reserve is generally activated only if the (day-ahead) market is not able to cover demand.

Capacity for strategic reserve is procured through a tendering procedure for a specified amount of capacity (in MW). Hence, a strategic reserve is limited to the procured capacity and the capacity or demand response procured must be able to respond when called upon. The strategic reserve may

29 The first real-world example of this market design was the initial UK liberalized market which lasted for approximately ten years. Examples of capacity payments mechanism are found in Spain, Greece, Ireland, Chile, Colombia and Peru.

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consist of existing or new generation built for the purpose of reserve capacity, and may include demand resources.30

Strategic reserves may be procured on a year to year basis or contracted for longer-term maintenance.

The strategic reserve is implemented by imposing an obligation on a reliability ensuring body, usually the TSO, much in the same way as the TSO is obliged to obtain ancillary services. The specification of the amount and type of capacity (e.g. peak units) may be based on a so-called reliability study. The strategic reserve may also contain capacity that is owned by the TSO.

The compensation schemes are specified in the tendering documents and may vary from case to case. Strategic reserve schemes may involve direct payments, payments in the form of an option or mixed forms. Typically, capacity providers receive the market price for the electricity generated (marginal fuel cost) plus a small premium31. It effectively works as a price cap. This is the model used in Germany, Finland, Poland and Sweden. For example, in Poland as of the end of March 2014, the grid operator has procured 830 MW of cold reserve capacity via two consecutive tenders effective from 2016 for a period of two to four years. This is also the model for a recent UK grid operator’s proposal for a Supplemental Balancing Reserve for winters 2014/5 and 2015/6.

The cost of strategic reserve schemes are typically covered through system charges included in the transmission tariff.

Typically, the TSO reserves the right to call upon the strategic reserve capacity when required. As mentioned already, the generation capacity included in the strategic reserve cannot be bid into the wholesale market. Demand side resources are bid into the market, but obliged to reduce consumption to a specified level when called upon. Strategic reserve contracts contain provisions for notification time, duration of activation, compensation during activation, etc.

The market impacts of the strategic reserve depend on the rules for activation: When is it activated and, when it is activated, how does it affect market prices? Typically the activation of the reserve is linked to a predetermined threshold price or trigger price. This threshold or trigger price acts as a price cap in the market. Ideally the threshold price should be set at the level of VOLL. Alternatively, the activation of the strategic reserve could be made dependent on the physical balance in the market, i.e. only be activated when a market balance cannot be found. In that case, the resulting market price must be administratively determined, e.g. as the highest market bid plus an uplift. This market price will impact interconnector revenues.

Strategic reserves may incentivize early retirement of capacity (into the strategic reserve). Although strategic reserves may be very accurately targeted (type, location, duration, etc.), there is a risk that one pays for capacity and interruptible load that would even be available without the mechanism.

30 The Swedish strategic reserve has a provision to gradually increase the share of demand side participation to 100 per cent in 2020. 31 http://www.dentons.com/en/insights/articles/2014/october/28/capacity-markets?utm_source=Mondaq&utm_medium=syndication&utm_campaign=View-Original

http://www.dentons.com/en/insights/articles/2014/october/28/capacity-markets?utm_source=Mondaq&utm_medium=syndication&utm_campaign=View-Original


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2.5.2.3.2.1 Capacity markets Capacity markets are schemes in which capacity adequacy is secured by various market based measures. Within this category it is useful to distinguish between capacity obligations, typically imposed on LSEs, centralized capacity auctions, and reliability options.

2.5.2.3.2.1.1 Capacity obligations A capacity obligation is a decentralized measure that normally places reserve obligations on LSEs. The obligations specifically require that LSEs contract for generation capacity corresponding to a certain percentage above the volume of their contracted or expected supply obligations. This is usually set by the regulator or the system operator.

Capacity obligations may be met by holding a volume of capacity certificates or through ownership of generation plant and/or long term contracts with generators. Capacity market designs without any form of capacity certificate are however rather old market designs which have been applied, but subsequently abandoned, in the power pools of the eastern states of USA.

Capacity obligation schemes may apply to the present volume of load served or to load volumes expected to be served (or declared to be served) at some time in the future. In the former case contracting for capacity may be done on a “spot” basis, whereas in the latter case the capacity market is similar to a forward market. It is not clear how a forward obligation can be compatible with a competitive retail market.

Even if the obligation is imposed for present supply volumes, it may be in the LSEs’ interest to conclude long term contracts with generators for some parts of their expected future volume of sales; however, they may conclude “spot” contracts with generators to adjust their position and fulfil the present time obligations.32

Capacity obligation schemes imply centralized calculation or determination of a required reliability margin by a regulatory authority, usually set at a certain percentage above peak supply obligations. Hence, capacity obligations do not require a central prediction of future demand. Different rules for calculation of the capacity obligation may apply, however.

The LSEs can document fulfilment of the obligation through ownership of power plants or bilateral contracting with power generators. The format of the required documentation may be standardized, e.g. as a capacity certificate. In this case, the LSEs are required to deposit a sufficient amount of capacity certificates to a centrally managed register, usually annually.

Controlling the obligation of suppliers for holding capacities is more difficult in capacity markets with explicit forward obligations. In this case, the LSEs have to demonstrate that they have acquired sufficient power capacities several years in advance. If the certificates are tradable, however, the LSEs can adjust their position in terms of certificate holding when expectations about future sales change.

32 To control that the share of spot contracting remains marginal, regulators in some eastern USA markets have moved from present only capacity obligations to include future time obligations.

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Rules may apply for the approval of capacity in terms of reliability, etc., or there may be a system of standardized certificates. Standardized certificates specify the required availability of the power plant or part of a power plant (duration, notification time, etc.). Demand side resources may be included as interruptible load contracts.

In return for the capacity certificate payment, the generator is required to make the contracted capacity available to the market in shortage periods (shortage periods may be defined in terms of a threshold price). Failure to make capacity available results in a fine.

Capacity providers are paid for the issued capacity certificates (or bilateral contract) and the LSEs pass on the costs of the buying certificates to end users. Suppliers pay a buyout price or a penalty if insufficient capacity is contracted.

Standardized capacity certificates allow for flexibility in the way customer serving entities comply with their capacity obligations. For flexibility purposes the capacity certificates are tradable in some market designs. Trade may take place among the customer serving entities on a bilateral basis or in a centrally organized market for capacity certificates. Hence, the price for capacity certificates is determined by supply and demand in the market.

Such a centralized capacity certificate market can be either organized on a voluntary basis (similarly to private power exchanges) or by the body ensuring reliability (e.g. the TSO). Hybrid systems are also possible. If centrally organized, the aim is to ensure price disclosure and transparency in order to facilitate new entry.

The generator accepts to certify capacity availability in exchange for a current or future payment; so he receives an extra fee for capacity availability in present or future time. In decentralized systems of capacity regulations, the payment contract can take any form agreed bilaterally between the generator and the customer serving entity; for example as an option (call option or other form of option) or a contract for differences (a two-way option).

Capacity contracted under capacity obligations is expected to bid the generation into the wholesale market or sell generation on bilateral contracts, and in particular, to offer capacity to the market in scarcity situations.

Capacity obligations are implemented and have been adapted several times in the PJM market. France has recently announced such a capacity obligation scheme through Law no. 2010-1488 and Decree no. 2012-1405.

One of the theoretical advantages of a capacity obligation mechanism is that it offers a market oriented solution and so is less likely to incentivize an over-supply of capacity than centrally procured mechanisms.

Some of the experiences are that capacity prices may be volatile and sensitive to gaming, that locational signals should be included and that the mechanism may become very complex, resulting in a substantial bureaucracy.

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2.5.2.3.2.2 Capacity auctions Another form of capacity mechanism which relies on capacity certificates, but does not require capacity obligations on LSEs, is centrally organized capacity auctions. The main difference from capacity obligations is that the procurement process is centralized and the reliability body acts on behalf of total load. Centralized capacity auctions make it easier to standardize the capacity contracts and to get one common, transparent price for capacity obligations. When the capacity market is centralized, the clearing prices are disclosed to market participants, contrary to the decentralized capacity market models in which capacity prices are not necessarily disclosed.

Capacity auctions may be conducted year-by-year, but also for future capacity. Centralized capacity auctions require reliability assessments, i.e. estimates of the total need for capacity including forecasts of peak demand and reserve margins.

In this design, the reliability body auctions standard capacity payment options to generators who receive payment contracts for capacity availability certificates. In principle, interruptible loads may also participate. The regulation includes a procedure for allocation of the reliability costs to LSEs. Usually this allocation is based on administratively set rules (e.g. prorate basis depending on peak load of customers by entity), but it can also be based on auctioning procedures among customer serving entities. In this case a centralised reliability product market is established, and certificates may subsequently be tradable among LSEs.

The auctioning among generators is thus an alternative way of determining the capacity payment price. The auctions can be complex and repetitive in order to ensure cost-effectiveness and market power mitigation.

Some economists think that tendering procedures can be seen as fall-back measures and thus not an appropriate solution to the structural imperfections of the market33. They do not structurally modify the economics of electricity markets, and do not place a specific value on security of supply. And the missing money problem revealed by economic theory affects all capacities in the same way. Therefore, in an imperfect market where a missing money phenomenon reduces investment incentives, the creation of new capacities subsidised by a special tendering procedure would only add to the profitability problem for all capacities. It should also be noted that if special tenders are organised too frequently, investors could begin to wait for the tenders, which would be counterproductive:

2.5.2.3.2.3 Reliability options A reliability option scheme is a variant of centralized capacity auctions. The main difference is the design of the capacity contract. The capacity contracts offered to generators in such auctions typically have the form of a one-way call option which refers to a strike price, usually with reference to the system marginal price of a wholesale market. In this market design, the capacity providers forego the potential (but uncertain) revenues in hours in which the market price in the wholesale market is above the strike price, in exchange for the certain revenues of the option. The consumers on the other hand, pay the option premium and in return avoid prices above the strike price.

33 RTE, French Capacity Market, April 2014

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The reliability option is designed to provide incentives for generators to invest in the right capacity for the market as the hours with high prices are an important part of all generators’ revenues, and all generators may be eligible to participate in the market. In principle reliability options do not require any provisions as to the kind of capacity or general reliability of capacity that can participate in the market. The reliability option is a financial instrument and penalties only apply if the contracted capacity cannot provide generation in hours when the market price exceeds the strike price. The penalty may be equal to or higher than the market price.

Reliability options require a well-functioning wholesale market and a market-wide system price. Actually, the reliability is directly associated with bidding in the wholesale market. Well-functioning reliability option schemes do however depend on the existence of a wholesale market producing a reliable reference price as the strike price of the reliability options are linked to market prices.

Design challenges include eligibility requirements in terms of availability of contracted plant, setting the future capacity margin right, defining the right strike price, defining the duration of the scheme, and auction design. Advocates of reliability options argue that market wide reliability option schemes, even if the reliability margin is set too high, yields incentives that provide an optimal long term capacity mix.

2.5.2.4 The EU experience

2.5.2.4.1 The Legal basis and concerns about capacity markets The evolution of national capacity markets raises important questions of EU law, in particular whether a particular capacity payment mechanism may constitute illegal state aid and whether such mechanisms may act as a barrier to free movement of goods and therefore be inconsistent with single market competition rules. Any proposed new capacity mechanism must now meet the European Commission Guidelines on State Aid for Environmental Protection and Energy of April 2014. These Guidelines emphasize demand-side participation and the contribution of capacity providers from other Member States where such capacity can be physically provided and also that the proposed capacity mechanism should not impact negatively on the development of the internal market by undermining the operation of market coupling, including balancing markets, and should not reduce incentives to invest in interconnection capacity.

The EU acquis allows state intervention to ensure security of supply. The European Commission confirms this in its Communication “Delivering the internal electricity market and making the most of public intervention”:

Public intervention can be useful and effective to attain policy objectives set at Union, regional, national or local level, but it must be well designed and should be adapted to changes in market functioning, technology and society that occur over time34.

Capacity mechanisms are explicitly named within the secondary legislation among the tools for guaranteeing security of supply. The possibility for Member States to introduce capacity mechanisms

34 European Commission (2013), Generation Adequacy in the internal electricity market - guidance on public interventions, Staff Working Document.

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is notably included in the measures provided for in Directive 2005/89/EC concerning measures to safeguard security of electricity supply and infrastructure investment:

Measures which may be used to ensure that appropriate levels of generation reserve capacity are maintained should be market-based and non-discriminatory and could include measures such as contractual guarantees and arrangements, capacity options or capacity obligations. These measures could also be supplemented by other non-discriminatory instruments such as capacity payments.

It is important to emphasise that the European Commission recently expanded its analytical framework for examining public intervention to ensure security of supply through the Staff Working Document “Generation Adequacy in the internal electricity market - guidance on public interventions” accompanying its Communication “Delivering the internal electricity market and making the most of public intervention”35. This Staff Working Document features a checklist regarding (a) the assessment of needs, (b) the adoption of structural measures to improve the functioning of energy markets, and (c) design choices compatible with the internal market, as follows:

European Commission recommendations on the introduction of capacity mechanisms

JUSTIFICATION OF INTERVENTION Assessment of generation gap

1. Is the capacity gap clearly identified and does this distinguish between need for flexible capacity at all times of year and requirements at seasonal peaks? Has a clearly justified value of lost load been used to estimate the cost of supply interruptions?

2. Has the assessment appropriately included the expected impact of EU energy and

climate policies on electricity infrastructure, supply and demand?

3. Does the security of supply and generation adequacy assessment take the internal electricity market into account; is it consistent with the ENTSO-E methodology and the existing and forecasted interconnector capacity?

4. Does the assessment explain interactions with assessments in neighbouring Member

States and has it been coordinated with them?

5. Does the assessment include reliable data on wind and solar, including in neighbouring systems, and analyse the amount as well as the quality of generation capacity needed to back up those variable sources of generation in the system?

6. Is the potential for demand side management and a realistic time horizon for it to

materialize integrated into the analysis?

7. Does the assessment base the assessment of generation plant retirements on projected economic conditions, electricity market outcomes and the operating costs of that generation plant?

35 Ibid

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8. Has the assessment been consulted on widely with all stakeholders, including system

users? Causes of generation adequacy concerns

1. Has retail price regulation (with the exception of social prices for vulnerable customers) been removed?

2. Have wholesale price regulation and bidding restrictions been removed?

3. Have renewable support mechanisms been reviewed in line with the Guidance on

renewable support before intervening on generation adequacy grounds.

4. Has the impact of existing support schemes for fossil and nuclear generation on incentives for investments in additional generation capacity or maintenance/refurbishment of existing generation capacity been assessed?

5. Are effective intraday, balancing and ancillary service’s markets put in place and are

any remaining obstacles, in those markets removed? Have any implicit price caps from the operation of balancing markets been removed?

6. Have structural solutions been undertaken to address problems of market

concentration? Options other than support for capacity

1. Have the necessary steps been taken to unlock the potential of demand side response, in particular has Article 15(8) of Directive 2012/27/EU on Energy Efficiency been implemented and do smart meter roll out plans include the full benefi t of demand side participation in terms of generation adequacy?

2. Have the benefits of expanded interconnection capacity been expanded, in particular

towards neighbouring countries with surplus electricity generation or a complementary energy mix been fully taken into account.

3. Have the impacts of the intervention on the achievement of adopted climate and

energy targets been assessed holistically, and is lock-in of high carbon generation capacity and stranded investments avoided?

CHOICE OF MECHANISM Choice and design of intervention

1. Has the effectiveness of a strategic reserve been examined?

2. Has the potential for a credibly one-off tendering procedure to address the identified capacity gap been examined?

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3. Does the chosen mechanism ensure that identified adequacy gap will be filled while

avoiding risks of overcompensation (unlikely with payments)? Recommendations to avoid distortion of the internal electricity market

1. Is the chosen mechanism open to demand side participation?

2. Is the mechanism to ensure generation adequacy consistent with the long term decarbonisation of the power sector?

3. Is the chosen mechanism (other than a tendering scheme) open to existing and new

generation?

4. Are conditions for participation in the mechanism based on technical performance and not technology type?

5. Does the chosen mechanism deliver a price of zero when there is already sufficient

capacity available?

6. Has a framework for the phase out of the mechanism in line with a roadmap for addressing underlying market and regulatory failures been developed

7. Does the lead time for a capacity mechanism correspond to the time needed to

realise new investments, that is 2-4 years?

8. Is the mechanism open to all capacity which can effectively contribute to meeting the required generation adequacy standard, including from other Member States? Insofar as imports are accounted only on an implicit basis, is a mechanism established to calculate this benefit and allocate funds to this value for the development of additional interconnection capacity?

9. Is it ensured that there are no export charges or procedures to reserve electricity for

the domestic market?

10. Have all barriers to the equal treatment of national and cross border contracts been removed?

11. Are there no price caps or bidding restrictions as a result of the chosen mechanisms?

12. Is it ensured that the operation of the chosen mechanism does not lead to inefficient

production by operators?

13. Is it ensured that the capacity mechanism does not adversely affect the operation of market coupling or cross border intraday trading?

14. Does the chosen mechanism allocate the costs to consumers on a non-discriminatory

basis, taking into account their consumption patterns and without reductions for

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particular customer segments?

2.5.2.4.2 The current status in the EU The number of European countries that have introduced or are planning capacity mechanisms is growing, reflecting the possibilities offered by Directive 2005/89/EC. In some countries, the decision was taken long ago (Spain, Sweden, Finland, Ireland and, to a lesser degree, Italy). Others (United Kingdom, France) have already made considerable progress in their plans, and organised their first capacity auctions in late 2014 (UK) or finalised the rules in early 2015 (France). The idea is still being considered in some Member States.

To date, some 14 EU Member States have in place—or are considering— some form of capacity support mechanism. There are a number of different designs including short-term targeted strategic reserves, capacity obligations, capacity payments and long-term market wide, volume based capacity auctions.

The map below, created by ACER36, offers an overview of the development stage (and type) of capacity mechanism situation across Europe.

Source: ACER, 2013

Figure 15: Development stage and type of capacity mechanism in the EU

36 CAPACITY REMUNERATION MECHANISMS AND THE INTERNAL MARKET FOR ELECTRICITY, ACER, 2013

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The type of mechanism in each country in the EU is displayed below37:

Source: FRONTIER ECONOMICS, 2015

Figure 16: Types of capacity mechanisms in the EU

It needs to be noted that a tension exists between national capacity markets that are deploying increasingly sophisticated payment mechanisms to achieve generation adequacy targets and EU regulations that support the development of the internal energy market. The new State Aid Guidelines should ease this tension, although a co-ordinated approach to the introduction of capacity mechanisms by Member States is still required to ensure their compatibility with the process of EU market integration. However, this fact should be considered in relation to the requirement placed on Member States in order to meet security of supply concerns at the national level.

A brief description of current or anticipated capacity support schemes in selected EU Member-States follows. The following schemes are briefly described:

• The de-centralized capacity market (Capacity Obligation) of France • The centralized capacity market of the UK • The capacity payment in Ireland (until 2016) • The Reliability Options in Ireland (since 2017)

2.5.2.4.3 France The French capacity mechanism is a capacity obligation, which (as already described in paragraph 2.5.2.3.2.1.1) is mainly a system for allocating costs, making market stakeholders accountable and organising trading38.

37 State of play of capacity markets in Europe, Eurelectric Conference on 'Capacity markets - delivering security of supply in the IEM', FRONTIER ECONOMICS, 4 March 2015 38 RTE, French Capacity Market, April 2014

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Under the French system, which is scheduled to commence in 2016, suppliers are required to meet their capacity obligations by holding a specific amount of capacity certificates that are issued by the System Operator based upon data declared by Generators within four years prior to the relevant delivery year and following an assessment of the reliability of the declared capacity. The Generators and the System Operator enter into a certification agreement regulating the availability of the certified capacity. The system permits the trading of certificates either directly or in a secondary market with the consent of the System Operator. Capacity certificates have a duration of one year39.

The need for capacity markets in France is reported to stem from the substantial increase in peak demand and the increased sensitivity of that peak demand to temperature changes. According to the French TSO (RTE) the French demand is the most sensitive among European nations to cold spells due to a high dependence on electric heating. With each degree Celsius drop in winter temperature, demand for power rises by 2,400 megawatts.

The French capacity mechanism was designed to address this issue by modifying consumption behaviour during peak periods (demand-based approach) while encouraging adequate investment in generation and demand response capacities (supply-based approach), at a time when energy markets’ ability to stimulate such investments was being questioned in much of Europe.

The French Decree 2012-1405 of 14 December 2012 established three fundamental principles to be applied in defining the architecture of the capacity mechanism:

(i) market mechanism (market-based) based on volumes (quantity-based), (ii) mechanism to apply to all capacity (market-wide), (iii) involving the assignment of individual obligations that can be met by acquiring

certificates from a third party.

Lawmakers thus opted for a decentralised mechanism as opposed to a single buyer system. These principles lay the groundwork for a mechanism adapted to the specific characteristics of and issues faced by the French market.

Thus, under the French design:

• Capacity obligations to electricity suppliers are calculated according to a mathematical formula which reflects the contribution of their customers to the shortfall risk, notably their consumption during peak periods and their temperature sensitivity.

• Capacity certificates are issued to capacity operators (generators) based on their contribution to reducing the shortfall risk. The certificates reflect the availability of their capacities during the peak period and the technical characteristics of their capacities (for instance energy constraints).

• Market stakeholders trade capacity certificates so the security of supply target can be met at the least possible cost.

39 http://www.dentons.com/en/insights/articles/2014/october/28/capacity-markets?utm_source=Mondaq&utm_medium=syndication&utm_campaign=View-Original



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• The parameters for calculating the obligation are determined four years ahead of time. This allows obligated parties to estimate the amount of their obligation and take any necessary demand management actions based on their forecasts.

• Different certification procedures will apply to different types of capacity: a. Existing generation capacities must request certification three years before the start

of the delivery year; b. Planned generation capacities that will be connected to the grid can request

certification once the first payment is made under the connection agreement, up until two months before the start of the delivery period;

c. Demand response capacities can be certified up until two months before the delivery period begins.

Setting the deadline for existing generation capacities three years before the start of the delivery year is crucial to give market stakeholders information about the outlook for the system and for the capacity market to generate economic signals far enough ahead of time to allow enough capacities to be developed to meet the security of supply criterion. The fact that planned capacities can request certification closer to the start of the delivery period makes it possible for all capacities to participate, notably demand response and other capacities that can be developed more quickly.

France's energy minister signed on January 23, 2015 the decree implementing the national capacity mechanism from winter 2016-17. A registry along with the issuance of certificates was to be launched April 1, 2015.

France is planning to hold an auction of power capacity market certificates likely take place in November 2015.40

2.5.2.4.4 Ireland The wholesale electricity market in Ireland (Single Electricity Market - SEM) operates in the Republic of Ireland and Northern Ireland41 and is organised as a gross mandatory pool market. Potentially, a generator who sells directly to the wholesale pool market may receive the following payments:

1. Energy Payment- The market price per MW sold per half hour time slot. 2. Capacity Payments – Compensation for being available to generate upon instruction from the

grid operator (CPM) 3. Constraint Payments – Compensation for being constrained from exporting scheduled

amount of energy onto the system (due to grid stability issues).

Capacity payments are calculated based on the relatively low fixed costs of a peaking plant. As a result the payments generally cover only a portion of the fixed costs involved in building most plants. Suppliers also pay for these capacity payments and any other system charges, which are typically passed through to customers.

40 http://www.platts.com/latest-news/electric-power/london/france-plans-november-auction-of-power-capacity-26009856 41 http://www.wattics.com/the-electricity-market-in-ireland/

http://www.platts.com/latest-news/electric-power/london/france-plans-november-auction-of-power-capacity-26009856

http://www.platts.com/latest-news/electric-power/london/france-plans-november-auction-of-power-capacity-26009856

http://www.wattics.com/the-electricity-market-in-ireland/

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The Objectives of the CPM are as follows:

• Incentivise appropriate levels of market entry and exit; • Not ‘double pay’ generators; • Reduce risk premium for investors; • Reduce market uncertainty; • Be compatible with the energy market; • Be transparent, predictable and simple to administrate; • Encourage short-term availability when required; • Encourage efficient maintenance scheduling; • Not increase costs to customers for desired security margin; • Not unfairly discriminate between participants; and • Encourage an efficient mix of plant types.

The key features of the Irish CPM are as follows:

• Fixed amount of cash (the Pot) per year • Pot determined as Price x Volume :

o Price: Best New Entrant Peaking Plant fixed costs o Volume: Capacity required to meet adequacy standard

• Pot allocated for Generator Payments: o Fixed (year ahead) o Variable (month ahead) o Ex-Post (month end)

• Generators paid when available • Pot allocated for Supplier Charges:

o Based on demand

2.5.2.4.5 UK As part of its Electricity Market Reform program, the UK announced the introduction of a capacity market in 201442,43. Features of the UK scheme include a pay-as-clear descending clock auction four years ahead of the delivery year with a secondary year-ahead auction to enable adjustments to capacity positions and to permit participation of demand side operators. Participants receive the clearing price set by the marginal bidder; a distinction is made between price takers (existing generation) whose bids are restricted and price makers (new and refurbished generation and demand side operators) whose bids are not. However, there is no restriction on the amount a single bidder can bid into the auction nor on the amount that it can win at the auction, as dilution of market concentration is not one of the objectives of the UK capacity market.

In order to protect consumers from excessive costs, the auction is capped at £75/ kW-year gross capacity price. This is an administratively set level that reflects a multiple of the Net-CONE (the net

42 https://www.gov.uk/government/publications/capacity-market-rules 43 http://www.dentons.com/en/insights/articles/2014/october/28/capacity-markets?utm_source=Mondaq&utm_medium=syndication&utm_campaign=View-Original

https://www.gov.uk/government/publications/capacity-market-rules



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cost of new entry – being the gross cost of construction of new open cycle gas turbine plant less expected electricity and ancillary services market earnings, although there has been particular criticism of the underlying assumptions and methodology used to calculate these concepts). The auction is technology neutral and the only ineligible plant is low carbon plant that is in receipt of other forms of financial support, plant that currently participates in the existing short term operating reserve and currently interconnected capacity located in another Member State.

There is no suggestion that more flexible plants will receive a higher price than less capable plants although new build capacity will be offered 15-year capacity agreements with existing capacity being offered rolling one year agreements and three year agreements for refurbished plants.

Capacity payments will be paid to generators by a settlement body from payments received from licensed suppliers under a supplier levy imposed as a license condition.

Failure to generate when required will result in penalties capped at 200 percent of a generator’s monthly capacity payment revenues and 100 percent of annual revenues. This unavailability risk is a much greater concern for new entrants with a single plant or small portfolio than for the vertically integrated generators with large portfolios who can better manage such risk. There is no allowance for planned maintenance or forced outages within the design, and force majeure relief is limited to failures in the power transmission system only. Further, providers of demand side response are particularly sensitive to penalty rates given that there is no limit on the number of incidents that DSR capacity can be required to respond to. Unavailability risk mitigation measures include secondary market trading.

The first auction, held in December for capacity in 2018/2019, has resulted in contracts for £931 million for UK power generators. The UK government asked for commitments from 49GW of power generation which corresponds to the forecast maximum demand in the UK in 2018/2019. The auction resulted in a price of £19.4/kW44,45,46. The auction resulted to Demand Response getting just 174 MW of agreements with one year contracts while new generation capacity got 15 years. Stakeholders have claimed that the reason the auction attracted only small amounts of new build was because the final price (£19.4/kW) was low and that the reason the price was low was because any generator could bid and because ta auction asked for the whole 49GW block bid (not just the part that was the peak above the normal winter daytime demand).

2.5.2.5 Experience in the USA In the US, there are six mature organized electricity markets characterized by locational marginal pricing with an independent system operator (ISO) functioning as the market administrator for the clearing price markets (ISO-New England, the New York ISO, PJM Office of Interconnection (Mid-Atlantic states), Mid-Continent ISO (formerly the Midwest ISO), the California ISO and the Electric

44https://www.gov.uk/government/uploads/system/uploads/attachment_data/file/389832/Provisional_Results_Report-Ammendment.pdf 45 http://www.theguardian.com/environment/2014/dec/24/the-uk-capacity-auction-made-utility-companies-merry-this-christmas 46 http://www.energypost.eu/uk-capacity-market-market-state-aid-1-billionyear/

https://www.gov.uk/government/uploads/system/uploads/attachment_data/file/389832/Provisional_Results_Report-Ammendment.pdf

https://www.gov.uk/government/uploads/system/uploads/attachment_data/file/389832/Provisional_Results_Report-Ammendment.pdf

http://www.theguardian.com/environment/2014/dec/24/the-uk-capacity-auction-made-utility-companies-merry-this-christmas

http://www.theguardian.com/environment/2014/dec/24/the-uk-capacity-auction-made-utility-companies-merry-this-christmas

http://www.energypost.eu/uk-capacity-market-market-state-aid-1-billionyear/

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Reliability Council of Texas). The three north-eastern ISOs have somewhat mature but evolving capacity markets.

This section briefly focuses on mandatory capacity markets that are intended to address long-term reliability needs and ensure that resources have adequate opportunity to recover their variable and fixed costs over time.

Capacity markets are often backstop mechanisms that evaluate potential capacity shortfalls after considering bilateral contracts or other power purchase agreements.

In ISO-NE, NYISO, and PJM, mandatory capacity markets are characterized by47

(iv) an obligation for load-serving entities to have sufficient capacity to reliably serve load; (v) a methodology to determine a capacity reserve margin and future capacity needs both

for sub-regions within the RTO/ISO and the entire RTO/ISO; (vi) a process for soliciting qualified supply and demand resources to meet future capacity

needs; (vii) a benchmark to judge the cost of new capacity; (viii) a methodology or approach for creating a demand curve; and (ix) a process to select resources and determine a capacity price (Rose 2011).

The methods for calculating capacity prices in each of the RTO/ISOs are based on the market design choices of each region. In general, regions with capacity markets find that the capacity prices tend to be limited to the capital cost of a new gas-fired plant that can be sited and built within three years. As shown in Figure 17, prices generated by mandatory capacity markets have been considerably volatile (FERC 2013). These results are driven by a variety of market considerations that vary from one region to another.

47 “Evolution of Wholesale Electricity Market Design with Increasing Levels of Renewable Generation”, NREL Technical Report NREL/TP-5D00-61765, September 2014.

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Source: FERC 2013

Figure 17: Capacity price in RTO/ISOs

The demand for capacity is based on an administrative process that determines the total amount of capacity necessary to meet peak load requirements. NYISO, PJM, and ISO-NE all use a downward-sloping demand curve for capacity rather than a fixed target. The downward-sloping demand curve is constructed to reflect the marginal value of capacity to load, and it serves to reduce the potential exercise of market power in capacity auctions. Although the specific demand curve parameters vary between the markets, the main principles are illustrated in Figure 2-4. The curve is constructed around a target for new capacity at which the price is set equal to the cost of new entry (CONE). CONE is typically set equal to the annualized capital cost of a new peaking plant (e.g., a combustion turbine), and it may be adjusted for the expected revenue from the energy market (i.e., net CONE). Administered price caps are common and are designed to protect against potential market power and provide a backstop mechanism in case insufficient bids are received from the market.

Source: Crampton and Ockenfels, 2012

Figure 18: Illustration of demand curve for capacity

Resources participating in the capacity markets must verify their capabilities to determine the total capacity they can bid into the market. Each of the mandatory capacity markets has a process for qualifying as a capacity resource. Generally speaking, resources interested in participating in capacity markets must verify their operating capability in MW for a specified time period, usually the winter or summer peak. Each organized market has different capacity qualification rules for existing resources, new resources, external resources, demand response, and renewables. Many of the markets will require capacity market resources to offer their capacity in the day-ahead market.

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Current capacity markets typically do not require capacity resources to have specific attributes other than the provision of capacity during periods of peak demand.

The physical location of a resource is also important for capacity markets. Transmission limitations can limit the ability of a load to access a resource. Local capacity obligations are enforced in each of the markets to ensure that load-serving entities have adequate supply and transmission capacity to deliver energy to an area. The issue is most prevalent in regions with constrained export and import capabilities. Accurately identifying zones that have deliverability constraints is critical to developing efficient capacity markets.

In Box 1 below, a discussion of critical features of US capacity markets is shown from (S. Caplan, 2014).

US capacity markets used to involve little more than confirmation that each load serving entity (LSE) had sufficient generation under ownership or contract to satisfy peak demand plus reserve margin accompanied by generator dependable capability testing. In the early days of these markets (1998- 2003), if there was a surplus, capacity prices tended to plummet because all suppliers would rather have some revenues than become the one that was priced out. In parallel, in times of relative shortage, prices would jump to the penalty an LSE would have to pay if it was deficient – two to three times the all-in cost of a peaking unit. This resulted in a naturally occurring vertical demand curve with prices plummeting with relatively small surplus and prices sky- rocketing in times of slight shortage. Meanwhile, energy prices following the fallout from the California energy crisis were substantially mitigated. With limited scarcity pricing, and a boom- bust cycle in the capacity markets, there was significant concern that capacity was not being built where and when needed. There was little political will to ease mitigation so as to let energy prices reflect scarcity conditions in more hours and in greater magnitude than market power mitigation would allow. In order to shore up the revenues and price signals to facilitate new development, restructured capacity markets commenced about ten years ago. The NYISO was the first to use a demand curve structure. All supply would have to bid into the capacity market. The ISO, subject to the US Federal Energy Regulatory Commission’s (FERC) review would determine the price of capacity based on the all-in cost of new entry (CONE) of a peaking unit less the margins the unit could expect from sales of energy and ancillary services to form net CONE. This price was the theoretically economic efficient price when the market had just enough capacity to satisfy peak load plus reserve margin. The ISO would then establish a zero crossing point – an amount of capacity surplus at which the price should be set to zero; and a maximum capacity price at which the prices would be high and level off. With these three points, a linear curve can be formed to guide capacity auctions. All units that bid in below the curve would clear and receive the price at which the amount of supply below the curve crossed the curve. The demand curve structure sent price signals so that in times of surplus prices would decrease, but not vertically so and in times of shortage, prices would increase without immediately jumping to the penalty level. The demand curve also recognized that there was value in capacity in excess of the installed reserve margin.

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All capacity had to participate in the auction. In zones that were import restricted, a certain amount of capacity had to be procured within the zone. Before long, concerns arose that large or critical suppliers in such zones could withhold some of their capacity to ensure prices were higher on the capacity that cleared. In response to this threat, ISOs adopted critical supplier screens and required them to bid into the capacity market as price-takers so they could not withhold. ISO market monitoring units started monitoring for physical and economic withholding as well. After a period of time, the opposite concern arose – buyer market power or monopsony power. Some large load serving entities that had divested generation to non-affiliated entities were substantial buyers in the ISO capacity auctions. If such buyers entered into power purchase agreements at above market clearing levels they could stimulate new investment even when it was not needed. If the uneconomic entry causes the capacity prices to drop enough, then the load serving entity might pay too much on 1,000 MW, but reap much greater savings on the other 9,000 MW it purchased in the auction. Uneconomic entry had the effect of causing volatile crashes in capacity prices. In response, FERC required the three eastern ISOs to develop buyer- side mitigation to prevent uneconomic new entry from resulting in artificially low capacity prices. The rules are evolving now. In the NYISO market, a new entrant is subject to a unit-specific net CONE determination by the ISO. If the ISO determines that the unit would clear the ISO’s forecast of the capacity market prices, then it would not be mitigated and may bid as a price taker. In contrast, if the ISO determines that the net CONE is above market clearing levels, the unit must bind in to the market with an offer floor. In PJM, only gas-fired units are subject to buyer side mitigation (a/k/a the Minimum Offer Price Rule or “MOPR”). PJM calculates each new entrant’s net CONE which forms an offer floor. If the unit clears an annual capacity auction, then it is not to be mitigated. If the unit’s costs result in an offer floor above the clearing price, the unit will not clear the auction, will not receive capacity revenues and will not contribute to lowering capacity prices. This state can continue indefinitely. Needless to say, there are a number of contentious issues going into the ISO demand curve – assumptions about the reference CT capital structure, cost of capital, margins on energy and ancillary service sales, the slope of the curve, the zero crossing point and other issues. Implementing the capacity markets as structured is in some requests a throwback to ratemaking in a quasi-market context. It is at best regulated competition. All of these quasi-regulatory patches on patches are a result of energy only price signals that were constrained by supplier side mitigation measures which tended to over-mitigate. Rather than lifting energy mitigation the regulator thought capacity markets with evolving critical supplier mitigation followed by buyer side mitigation and actual offer floors were the way to go. The capacity markets range from a year-ahead auction market to a three-year ahead market, but each auction produces prices for only one year. The capacity market revenues are not liquidated for any length of time, making the revenue streams less effective to bring down the cost of non-recourse project financing. In addition to the mitigation of energy prices, over the last decade of capacity markets, the growth of intermittent renewable energy sources has been substantial in some markets. This further reduces energy market revenues which a new CCGT unit may expect. In some instances, energy prices go negative when the wind is blowing and the ISO needs to curtail or back down supply. Negative prices can result in financial obligations for some economic supplies.

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Additional flux surrounds evolving rules by which demand response (DR) may participate in the capacity markets. The rules were different for generation and DR. For example, generators must offer supply into the ISO Day-Ahead market in an amount equal to or greater than the amount of capacity which the generator has cleared in the applicable auction. If the generator were not available when needed, its equivalent forced outage rate would suffer, and the amount of capacity it could sell in the future would decrease. In contrast, DR resources were treated as an emergency resource and did not have a day-ahead offer requirement. If DR resources, however, were not available when called in some markets, they would lose half of their capacity revenues on the year, and if they failed to respond a second time, they would lose all capacity revenues on the year. Other rules affect the incentives for DR resources to participate in the capacity market. For example, there is current litigation over the mandatory response time for DR resources. On rare occasions, DR suppliers have been found to game the system. Both FERC’s Office of Enforcement and ISO market monitoring units have stepped up review of compliance and verification efforts. The potential to lose 50 to 100 percent of the annual capacity revenues by not responding— curtailing load or bringing up on-site generation—is also an incentive to achieve and maintain compliance. To conclude, capacity markets, once introduced, should not necessarily be regarded as permanent features and in theory should be phased out once generation adequacy can be permanently ensured by the energy market offering a sufficient level of pricing to deliver the appropriate investment incentives. In practice, and based on the US experience, this is unlikely to happen unless the predictability of capacity payment pricing that may be realized under a well-designed capacity market can be replicated in the energy market. Indeed, even if such a level of pricing predictability could be achieved, the pace of phase-out of any capacity payment mechanism needs to be carefully considered, particularly if one of the market design objectives is to stimulate new build plant rather than simply to delay the decommissioning of existing plant. As it is likely that longer duration arrangements will need to be offered to incentivize investors and to ensure the bankability of such arrangements, there should be no suggestion that existing commitments can be prematurely curtailed if the required level of generation adequacy is achieved earlier than anticipated. Source: “Capacity Markets: a short-term fix for security of supply or a key energy market support mechanism in the transition to a low carbon economy?”, Dentons, October 2014.

2.5.2.6 Annual cost of existing capacity mechanisms There are several methods to measure the cost of a capacity mechanism48. Generally the cost associated with a mechanism should be reviewed in relation to the overall cost of the electricity system, i.e. energy payments, transmission tariffs, balancing costs, value of lost load plus the capacity payments. Due to the differences in design and scope, available figures are not directly comparable across countries. However, Table 3 gives a general overview of cost estimates in terms of total annual capacity remuneration, total annual capacity remuneration compared to gross electricity generation and remuneration per committed capacity unit. The numbers in the table are based on 48 European Commission, ‘Capacity Mechanisms in Individual Markets within the Internal energy Market’, June 2013

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recent figures (2011-2013), drawn from several sources and do not include costs associated with ancillary services or balancing markets. Ireland seems to have the highest capacity cost per gross electricity generation. This reflects that a substantial share of generators’ revenues accrue from the capacity payment scheme.

Market design

Total cost

Mill. €

Per gross electricity gen.

€/MWh

Per committed capacity

€/MW/year

Committed capacity

MW

Greece Capacity payment

451 9.18 41,030 11,008

Ireland Capacity payment

529 20.2 78,000 6,778

Italy Capacity payment

100 – 160 0.5 - -

Spain Capacity payment

758 2.7 30,506 24,847

Sweden Strategic reserve

12 0.1 6,981 1,726

Finland Strategic reserve

19 0.3 31,216 600

Norway Strategic reserve

25 0.2 82,753 300

PJM Capacity market

4,275 5.5 31,401 136,144

Source: European Commission, ‘Capacity Mechanisms in Individual Markets within the Internal energy Market’, June 2013

Table 3: Annual cost of existing capacity mechanisms

2.5.2.7 Summary Table 4 gives an overview of the different capacity mechanism designs and their main features. Real-life capacity regulations can combine various elements of the above classification, and often do, see next section.

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The different capacity mechanism designs partly reflect that there are different motivations for implementation of capacity mechanisms in different cases, and partly that the thinking around the market design has developed in order to address various adverse incentive and cost effects of capacity mechanisms. Capacity payments may be regarded as subsidies aimed at directly fixing the “missing money problem”, i.e. increasing investment incentives by increasing the expected revenues for generators. Strategic reserves on the other hand may be regarded as an answer to need to secure and control a certain volume of reserve capacity in case the market is not able to find a solution (equalize demand and supply). Capacity markets can be seen as refinements of capacity payments. In capacity obligation schemes regulators determine the reserve margin, whereas the market agents, in a decentralized manner, find the least cost way of fulfilling the requirement. Central auctions may ensure greater transparency and standardization of capacity, i.e. greater cost-efficiency than decentralized markets. Neither capacity obligations nor capacity auctions mitigate market power in scarcity situations, however.

Reliability options are explicitly aimed at creating optimal long term investment incentives that correct for the alleged market failures of (optimal) energy-only market designs. By their very nature, reliability options would be implemented for the long term as integrated elements of optimal electricity market design, and are not aimed at fixing temporary challenges in the market.

The more sophisticated the capacity mechanisms are, the more accurate they may be, but at the same time, the more complex they become.

Overall, capacity markets have been successful in delivering long-term stability of power supply49. Even though prices for capacity are highly volatile, investments in new capacity still takes place50. On the other hand, there is substantial criticism that capacity markets result in windfall profits for the owners of existing power plants51 and cost the consumer too much (e.g. the overall price tag for the PJM capacity market is put at more than 4 billion dollars per year).

In addition, it should be stressed that significant analysis should be undertaken before the introduction of a capacity mechanism in the electricity market. In the French case52, during the consultation on the rules, special attention was paid to quantifying the effects of the technical provisions RTE was proposing. Numerous studies were executed to allow the impact of the different aspects of the mechanism to be quantified. All in all, some 30 studies and simulations were carried out, and the results were presented during the consultation to inform the discussions.

Finally, it should be noted that the interaction of capacity schemes with neighbouring electricity markets remains a crucial factor. For example, in the EU IEM case, the coupled French-Germany markets case, there exists potential for over-compensation of French generators in receipt of capacity payments that could arise as a result of France being connected with the energy only

49 http://www.cleanenergywire.org/factsheets/capacity-markets-around-world 50http://www.brattle.com/system/publications/pdfs/000/004/951/original/Characteristics_of_Successful_Capacity_Markets_Pfeifenberger_Spees_Oct_2013.pdf?1383246105 51 http://www.hks.harvard.edu/hepg/Panel%203/Erik_Paulson.pdf 52 RTE, French Capacity Market, April 2014

http://www.cleanenergywire.org/factsheets/capacity-markets-around-world%23_msocom_2

http://www.cleanenergywire.org/factsheets/capacity-markets-around-world

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markets of Germany, with a coupled market clearing price that may be driven higher in periods of scarcity by generators not in receipt of capacity payments seeking to secure scarcity rent.

Consistent with the European Commission State Aid Guidelines, an affected capacity market may include offset mechanisms to neutralize such risk of windfall profits, but this could complicate the system design significantly.

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Capacity payment Strategic reserve Capacity markets

Capacity obligation Capacity auction Reliability option

Market wide or targeted Can be both

Loads not included

Targeted. Loads may be included

Both, but typically market wide



Present or future obligation

May be both May be both May be both

Incentives for long term contracts

May be both Future, designed to strengthen investment incentives

Adequacy calculation Not required Required (reserve margin)

Required (reserve margin) Required (total capacity) Required (total capacity)

Reliability requirements Not required Required Rules for approval / standard certificates

Rules for approval / standard certificates

Linked to market price (strike price)

Payment Set by regulator

May depend on peak reserve margin

By tender / auction Market based: Bilateral contracts or certificate trade

Through centralized auction

Through centralized auction

Cost allocation Fee on LSEs (uplift on energy charges)

System charges Charge on energy sales by LSEs

Charge on energy sales, peak load or system charges

Charge on consumers (peak load)

Rules for activation None. Generation sold in wholesale market

Activated on call. Only loads bid in market

Expected to bid in wholesale markets

Expected to bid in wholesale markets

Required to bid in wholesale market when price exceeds strike price

Source: [European Commission, ‘Capacity Mechanisms in Individual Markets within the Internal energy Market’, June 2013]

Table 4: Summary table of capacity mechanisms

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2.5.3 Renewable Generation and Capacity Markets

In restructured electricity markets, the presence of a significant number of renewable generators can have a profound impact on the market. There are three areas where renewables will impact capacity markets: displacement, increase costs and reduction in prices53.

First, in bid-based energy market where the dispatch is based on generators’ bids, renewable resources can affect which resources are dispatched in the market. In comparison to conventional fossil-fired generation, renewables are likely to have a lower running cost. Consequently, renewable generators can often bid much lower than conventional generation. This will lead to renewable generation being dispatched ahead of conventional plants. Thus, renewable generation displaces conventional generation in bid-based markets. This displacement lowers the capacity factor of conventional generators and reduces the time conventional generators are selling in the market. This reduced output reduces energy revenues to conventional generators.

Second, more intermittent renewables require greater flexibility on the part of all generation on the system. More variable output produced by renewable resources requires conventional generation to operate with greater variability to accommodate the increased variation. Significant demands for flexible output, including more starts/stops per day as well as cycling more often from minimum to maximum output, will likely increase the wear and tear on conventional generators and lead to higher operations and maintenance (O&M) costs and the need to schedule more frequent maintenance outages. Increased O&M costs and less availability due to more frequent maintenance will also have a financial impact on the conventional generators, likely cutting into the profitability of the generator. Consequently, conventional generation will be operating less often as well as having to operate in a manner that increases operating costs. These factors work to reduce the net energy revenue earned by conventional generators.

Third, there is an additional impact of renewable generation on energy prices. In bid-based markets, prices are set by the running costs of the marginal plants. Because renewable generators can have low running costs, prices can be quite low in markets where a renewable generator is marginal. Also, social policies to promote renewable generation often provide non-market incentives that influence market outcomes. For example, a production tax credit can produce positive net revenues to a generator even with negative market revenues. Consequently, renewable generators can be willing to pay other market participants to produce, resulting in negative prices for the entire electricity market. As renewable generation penetration increases, the likelihood that such generation will be on the margin is greater, placing downward pressure on energy market prices. However, conventional generators will still be needed to provide flexibility to address renewable variability. This conventional generation may be subjected to very low energy prices. Therefore, ancillary services should be designed to provide needed flexibility at compensatory rates to conventional generators providing the service. If such ancillary services have not been implemented, there can be a significant impact on conventional generation revenue.

Consequently, the impacts of renewable generation in restructured, bid-based markets place a much greater need for a capacity market. Conventional generators are needed to balance renewable

53 Renewable Generation and Capacity Markets, by Peter H. Griffes, IAEE.

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intermittence, but will face lower output, higher O&M costs and lower energy prices. These factors place a premium on enhanced ancillary services products to provide flexibility and greater reliance on capacity market revenues.

2.5.3.1 Calculating the Capacity Value of Intermittent RES Generation in the US Several of the RTOs in the United States use simplified methods to calculate the capacity value for wind power54. Generally, these methods have been adopted because of their simplicity and transparency, and they define a peak time period and calculate the capacity factor during that period. For example, PJM calculates the wind capacity factor for the hours ending 3:00 p.m. to 6:00pm, June through August for the most recent 3-y period. For wind power plants with at least 3 years of operational data, actual data is used for the calculation. For new wind power plants, a default value of 13% is used initially, which is replaced as operating data become available.

The RTO/ISOs with capacity markets evaluate capacity values for wind resources as described in Table 3-1. The table shows the time periods from which the capacity value was calculated, including months, time of day, and the number of evaluation years. The table also shows the method of calculation (median generation value or average capacity factor).

Source: Rogers and Porter, 2012

Table 5: Methods for determining the Capacity Value of solar and wind in RTO/ISOs

54 “Evolution of Wholesale Electricity Market Design with Increasing Levels of Renewable Generation”, NREL Technical Report NREL/TP-5D00-61765, September 2014

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However, it should be noted that it is not possible to ensure that these simplified approaches can accurately capture the reliability aspect of resource adequacy. A simple method such as that used by PJM (or other similar approaches) may miss times of significant risk. The use of predefined peak windows may miss times of system risk when generating capacity is needed and therefore provide an incomplete picture of the state of reliability of the generation fleet.

Several possible approaches can overcome some of these obstacles, although they may also fall short of providing a true picture of resource adequacy. One approach is to use the top daily or hourly loads. For example, the top 2% of load hours, approximately 175 hours, could be evaluated post hoc, and the VG capacity factor could be calculated for that period. More information can be found in the 2014 NREL Report55 (see also Bibliography).

2.5.3.2 The capacity-based RES support scheme in Russia The wholesale electricity market arrangements in Russia are based on separate markets for energy and capacity.

2.5.3.2.1 The wholesale energy market The wholesale energy market has been fully liberalised since January 2011. Since then, most electricity has been bought and sold on a competitive basis through the centralised wholesale spot market56.

The new market model implies two ways of electricity trading at free prices.57

• free bilateral contracts, in which market participants have the right to choose contracting parties, prices and supply volumes.

• a day-ahead market , which is based on competitive selection of bids submitted by suppliers and buyers a day before the electricity is actually supplied. The competitive selection is held by the commercial operator.

If there are deviations from the day-ahead forecast, participants are obliged to sell excess amounts or buy missing ones in the balancing market. As a whole, the day ahead market replaces the free trade sector that was previously operating. The only difference between the two is that in the day ahead market participants' bids cover all power produced and consumed [while in the free trade sector suppliers (used to) bid for 15% of production, and buyers for 30% of consumption].

The spot market is divided into two pricing zones58. Price Zone One incorporates the competitive parts of the integrated electricity systems of European Russia and the Urals, while Price Zone Two includes the competitive parts of the Siberian integrated electricity system. The day-ahead market is

55 “Evolution of Wholesale Electricity Market Design with Increasing Levels of Renewable Generation”, NREL Technical Report NREL/TP-5D00-61765, September 2014. 56 “Russian Electricity Reform 2013 Update”, IEA, 2013. 57 http://www.rao-ees.ru/en/reforming/market/show.cgi?market.htm 58 “Russian Electricity Reform 2013 Update”, IEA, 2013.

http://www.rao-ees.ru/en/reforming/market/show.cgi?market.htm

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managed by the Trade System Administrator (ATS) and is settled hourly on the basis of the system marginal price determined by the marginal generator offer or consumer bid that clears the spot market. Active customer bids constitute a few percent of total demand in Price Zone One and around 10% of total demand in Price Zone Two. Locational marginal prices determined on the basis of over 8,000 separate transmission nodes across the competitive wholesale electricity market are taken into account when determining spot prices and dispatch.

2.5.3.2.2 The capacity market In Russia a separate capacity market exists with respect to participants in the wholesale market.

The product which is traded as “capacity” is the obligation of generating companies to maintain a certain level of generating capacity, which can involve obligations to maintain or repair existing generating facilities as well as to construct new ones.

Capacity market in Russia was designed to ensure resource adequacy in period of peak demand. Initially, it was planned that capacity market will be in a form of competitive capacity auctions (similar to the PJM market area in the US), where new and old generators compete to be selected to cover the peak demand and get guarantee payments. Thus, competition in the capacity market will ensure the most cost-effective entry of new generation and exit of old. Capacity market design for 2011 and following years was defined in government decree N89 on 24.02.2010 “On organization of long-term capacity market”. The immediate need for investments in new capacity as well as high market concentration forced to introduce some regulatory policies in the current capacity market design. Thus, the current capacity market combines the element of competition and regulation with the prevailing role of the last one59.

The System Operator (SO) defines the zones of free power flow that emerge during peak hours because of the inadequacy of the transmission capacity between the zones. In 2011, market was divided into 29 zones of free power flows. For each zone, the SO estimates the peak demand (or capacity demand) for each month of the following year, and selects the generators that can cover the capacity demand.

Generators (nuclear, hydro and thermal) that participate in the capacity market are divided into two main categories: old capacity and the new capacity that has been launched since 2007. Participation in the capacity market and the capacity payments are different for the old and new generation. New generators get regulated fixed capacity payments, while the old generators compete in Competitive Capacity Auctions (CCA).

New investments – Capacity Payments

Russia’s electricity sector reform was accompanied by a huge need for new investment in the generation sector. During the first period of the reform 2010-2015, the development of new generation capacity has been governed through government regulation. Mandatory investment

59“Capacity market in Russia”, Lappeenranta University of Technology, June 2013. http://www.fingrid.fi/fi/sahkomarkkinat/markkinaliitteet/Rajakapasiteetit%20ja%20siirrot/Capacity%20market%20in%20Russia.pdf

http://www.fingrid.fi/fi/sahkomarkkinat/markkinaliitteet/Rajakapasiteetit%20ja%20siirrot/Capacity%20market%20in%20Russia.pdf


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programs concern the largest generating companies and the programs are enforced through Capacity Delivery Agreements (CDA) for new thermal power plants and Long-term Agreements (LTA) for new hydro and nuclear power plants. Investors have obligations concerning punctual commissioning of new generation while the government guarantees a return on invested capital for ten or twenty years starting from the year of commissioning of the power plant (thermal power plants have ten-year guarantee and the nuclear and hydro power plants have a twenty-year guarantee). The capacity payments are regulated fixed monthly payments. The capacity payments for new thermal power plants vary from 12500-30000 €/MW-month, depending on the type and location of the new power plant. The present capacity mechanism in Russia is meant to be temporary, and it is designed to solve the problem of the immediate need for new investments in the generation sector. In 2010-2015, 40 GW of new generation will be launched through this mechanism.

The mechanism provides a generous guaranteed return on investment that initially lied between 13% and 14% per annum. These contracts provide long-term cash flow certainty while substantially reducing investors’ capital risks by enabling them to recover most of their capital within the first 15 years of operation.

Old generators - Competitive Capacity Auctions

Old generators compete in Competitive Capacity Auctions organized by the TSO a year prior for each month of the following year. In case of high market concentration (HHI(*>0.25) the price caps are applied in CCA. In 2011, the price cap was applied in 26 out of 29 zones of free power flow. Generators submit bids of monthly offered capacity (MW/month) and price (Rub/MW-month). Capacity bids of generators, technical parameters of which meet the minimum requirements set and published by the TSO before CCAs, are only considered.

The generators are selected starting from the cheapest. The last accepted capacity bid forms the capacity price of the CCA. The capacity prices formed in the CCAs is 3000-4000 €/MW-month. Generators receiving capacity payments should perform the full readiness to deliver the amount of electricity indicated in their accepted capacity bids. Generators which are not selected in CCA can still participate in a day-ahead and balancing market.

Capacity payments paid to the generators are wholly collected from the consumption on a monthly basis.

The RES capacity market

The Federal Law of the Russian Federation of 6 December 2011 amended the Federal Electricity Law60 by introducing a capacity-based support scheme in addition to the electricity premium. The amended version of Article 32 of the Federal Electricity Law now provides for the possibility to support renewable energy by concluding with investors ‘‘Agreements for the Delivery of Capacity.’’ This is a very different approach to that applied in most of the existing support mechanisms in other countries, where RES-E is promoted on the basis of the electricity output (MWh) rather than the installed capacity (MW or MW per month) of renewable energy installations. The cornerstone of the

60 Federal Law “On Electricity” No. FZ-35 of 26 March, 2003.

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new capacity scheme allows renewable energy investors to benefit from regulated capacity prices for a period of 15 years61.

The mechanism for concluding Agreements for the Supply of Capacity is similar to the contractual scheme developed to finance investments in strategic power plants in the context of the privatization of the former quasi-monopolist RAO UES. To ensure the financing of the investment program of RAO UES, investors that purchased generation assets in the context of the privatization of this company signed long-term capacity supply agreements (“DPM” in Russian) for remuneration of capacity (availability) at regulated prices.

By concluding Agreements for the Delivery of Capacity, investors commit to construct a certain type of production installation, of a certain capacity, at a certain location. Under the new capacity-based support scheme renewable energy investors will therefore, in return for long-term regulated tariffs, commit to build certain types of renewable energy installations at specific locations determined by the Government of the Russian Federation. Moreover, by concluding such Agreements, investors commit to maintaining their installations in a state of readiness to produce electricity, i.e., they guarantee the availability of their installations for electricity production.

To implement the new capacity-based support scheme further regulatory intervention by the Government of the Russian Federation, the Ministry of Energy and the Market Council was necessary: The Government must elaborate the list of renewable energy installations that will be entitled to support. It must also adopt tariff methodologies for the remuneration of renewable energy capacity – in particular, it must fix the rate of return and eligible capital costs per type of renewable energy technology – and determine the duration of support. Based on these methodologies, the Market Council will have to adopt specific tariffs for each renewable energy installation.

Recently ( 28 May 2013), the Government of the Russian Federation adopted Decree No. 449 on the Mechanism for the Promotion of Renewable Energy on the Wholesale Electricity and Capacity Market62. Decree No. 449 integrates support for RES-E into the capacity market.

Decree No. 449 tasks the Administrator of the Trading System with organizing a competitive selection of renewable energy investment projects each year and for each type of renewable energy covered by the scheme (i.e. wind, solar PV and small hydropower). The developers of the selected projects will then be entitled to sign Agreements for the Supply of RES Capacity. The object of this competitive process is to select projects up to a certain maximum amount of MW installed renewable energy capacity for each year. By limiting the amount of renewable energy projects covered by the scheme, Decree No. 449 aims to minimize the costs of this support policy and thus the impact on end user electricity prices. The Government also aims to limit the price impact of the capacity scheme by introducing limits on the capital costs of renewable energy projects. The Government of the Russian Federation determines targets for the level of installed wind, solar PV and small hydropower capacity that should be commissioned each year up to 2020. In contrast to tendering schemes in other countries (e.g. tenders for offshore wind energy in the UK and France), the choice of location of renewable energy projects is left to investors. There is one geographical

61 A. Boute, Promoting renewable energy through capacity markets: An analysis of the Russian support scheme, Energy Policy 46, 2012. 62 IFC / World Bank, “Russia’s New Capacity-based Renewable Energy Support Scheme”, September 2013.

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limit: Decree No. 449 applies to projects located in the price zones of the Russian wholesale market (i.e. parts of the Russian territory where electricity is traded at free market prices)63.

63 “Russian Electricity Reform 2013 Update”, IEA, 2013.

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2.6 Key Findings


Unbundling within energy markets refers to the unbundling of vertically integrated structures. The unbundling of generation, transmission, distribution and retail sales has an important role within the electricity market with regard to the implementation of competition. The inclination towards the unbundling of the transmission and distribution operations, which are referred to as network operations and which, as already mentioned, carry natural monopoly characteristics, from generation and retail sales activities, is based on the concern that the dominant undertaking may limit in various ways the access of other undertakings that it is competing with in generation and retail sales areas.

The above activities, initiatives and legislative framework resulted to the adoption of a ‘target model’ for the electricity sector in the EU.


In energy-only market designs, the (only) traded commodity is electricity (MWh/h). In such markets, the supplying companies get revenues only by selling electricity, either in organized wholesale markets and/or through bilateral contracts with customers. The companies recover capital and fixed costs of power generation because the selling prices or the wholesale market prices turn out to be higher than the variable costs (mostly fuel costs) of power generation, either continuously or periodically, but in a sufficient number of hours. Generation capacity adequacy is supposed to be derived from the resulting market dynamics. Moreover, scarcity pricing ensures revenues to cover capital cost of peak (and other) generation capacity.

By contrast, market designs with explicit capacity mechanisms recognize two market commodities, namely electricity (the output) and generation capacity (the means). Introducing capacity mechanisms imply that generators receive payments for the mere availability of capacity in addition to revenues obtained from the energy market. One might say that in a market with an explicit capacity mechanism the energy market is still the main instrument for short term optimization of

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resources, while the capacity mechanisms is the main instrument for long term development of generation capacity.

2.7 Ownership and Benefits of the Activity Despite the fact that the “missing money problem” has not yet hit the Kazakh wholesale electricity market, the Ministry of Energy considers establishing capacity support mechanisms. On the other hand the Market Operator of Kazakhstan evaluates different market design features with a view to propose amendments/improvements to the current market design in Kazakhstan. These include the mandatory vs voluntary participation of market actors to the Power Exchange, the impact of participation of the CHP generation to the capacity support mechanism as well as generally the enhancement of the role of the PX in the wholesale electricity market. On top of these issues which concern only Kazakhstan as the most advanced and important (in terms of its size) electricity market in the Central Asian region, INOGATE has always looking to enhance and support the central role of Kazakhstan on the creation of a regional Central Asia electricity market. These interlinked objectives have led to the combination of the originally distinct applications for technical assistance. The results can be viewed as a knowledge base enhancement which may under appropriate circumstances and with the support of other international development partners working in Kazakhstan translate into reforms and eventually the creation of a regional electricity market.

2.8 SPECIFIC ISSUES AND RECOMMENDATIONS PERTINENT TO THE FUTURE DEVELOPMENT OF THE ELECTRICITY SECTOR IN KAZAKHSTAN

2.8.1 Technical, market and organizational aspects

2.8.1.1 Mandatory vs. non-mandatory participation in PX As described in Chapter 3, organized markets for wholesale electricity are structured in the form of a Power Exchange (PX) or in the form of a Pool. The rules for participation in these organized markets differ depending on the wholesale market model adopted in each country. The international experience until now has shown that in the prevailing wholesale market models (Pool, Bilateral, Hybrids – see Ch. 3), participation of the market entities is as follows:

A. SHORT TERM WHOLESALE ENERGY MARKETS OF PHYSICAL DELIVERY (eg. Day-Ahead) • Under the Pool model for the implementation of a Day-Ahead Market of physical delivery,

participation is mandatory: all electricity to be traded (sold and bought) during the next day has to be ‘offered’ in the Pool (examples in Europe: Ireland64, Greece65)

• Under the Bilateral model o contracts for buying and selling electricity are mainly held on an OTC basis. o Participation in any PXs which operate is not mandatory

• Under the Hybrid models, participation in any PX or Pool is again not mandatory

B. LONG TERM WHOLESALE ENERGY MARKETS (FINANCIAL MARKETS – NOT FOR PHYSICAL DELIVERY e.g. Forward or Future contracts66)

64 http://www.sem-o.com/AboutSEMO/Pages/default.aspx 65 http://www.rae.gr/site/en_US/categories/electricity/market/wholesale/intro.csp?viewMode=full#1

http://www.sem-o.com/AboutSEMO/Pages/default.aspx

http://www.rae.gr/site/en_US/categories/electricity/market/wholesale/intro.csp?viewMode=full%231

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• Participation in PXs trading Futures contracts is not mandatory.

2.8.1.2 Interaction of capacity and energy markets: The issue at hand is whether a plant already participating in the capacity market with a capacity (Pcap) lower than its total nominal rated capacity (Pnom), can offer an additional amount (i.e. up to Pnom-Pcap) to the wholesale energy market.

Example: assume a generation plant of 500 MW capacity, of which 300 MW have been registered and participate in the capacity market. Then what amount of electricity can the plant sell?

• All? (i.e. up to 500 MW) • Only 300 MW? (i.e. the amount registered in the capacity market)

The ITS team is of the opinion that the plant should not be discouraged or prevented from offering any available output to the market. This policy would allow for the capacity part being less than the plant’s total ‘productive’ capacity, thus making it possible to produce and sell more energy that Pcap, e.g. in case where less ‘secure’ part of energy might be available. This wouldn’t harm the market, as the risk in this case is with the plant, given that any imbalance due to non-availability would be bought from the balancing market and settled at the respective price.

2.8.1.3 CHP in participation in capacity markets In discussing the role of cogeneration plants that are coupled to the district heating networks and in particular their potential for offering capacity we would most probably start from the European countries that have a long track record in the specific energy technology. It is of equal importance to understand which EU country(ies) are using comparable fuel and technology with those of Kazakhstan. For example the majority of cogeneration in EU comes now from natural gas and that may involve contemporary technologies including gas turbines and also internal combustion engines (ICEs). It would be misleading to regard countries with natural gas cogeneration as electricity markets with comparable characteristics with the one of Kazakhstan. The following chart provides a breakdown of cogeneration capacities per type of fuel

66 While futures and forward contracts are both contracts to deliver an asset on a future date at a prearranged price, they are different in two main respects: Futures are exchange-traded, while forwards are traded over-the-counter.

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Source: COGEN Europe website67

Figure 19: Installed cogeneration capacities in Europe in terms of fuel input

It can be construed from the above chart that it is Germany, Poland, Finland, Demark and Czech republic where we could possibly look for experiences in relation to capacity mechanisms and in particular the contribution of CHP in these.

2.8.1.3.1 Germany CHP plants for district heating in Germany are promoted in the same sense as renewable energy sources68. They receive and feed-in tariff and/or price bonuses and have a dispatch priority. In Germany there is still a lively debate on whether a capacity mechanism is required for the future development. A recent publication69 called “An Electricity Market for Germany’s Energy Transition Discussion Paper of the Federal Ministry for Economic Affairs and Energy (Green Paper)” served the purposes of a consultation among interested stakeholders. The document describes the interrelation of capacity and energy markets and also proceeds with a review of available options for introducing a capacity market in Germany. There is no specific arrangement for the participation of CHP in the flexibility mechanisms although the Green Paper foresees that CHPs can provide flexibility through technological enhancements i.e. ramp down capabilities and auxiliary heat-only-boilers for changing heat to power ratios.

67 http://www.cogeneurope.eu/what-is-cogeneration_19.html 68 http://www.iea.org/media/files/chp/profiles/germany.pdf 69 https://www.bmwi.de/BMWi/Redaktion/PDF/G/gruenbuch-gesamt-englisch,property=pdf,bereich=bmwi2012,sprache=de,rwb=true.pdf

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2.8.1.3.2 Poland In Poland at the moment there are discussions on the introduction of capacity mechanisms. According to the current forecasts for the years 2016 – 2018, the Polish power system may experience capacity shortages caused by the decommissioning of old and inefficient power units and the lack of alternative sources, which (despite the fact that they are currently under construction) will not even start operating yet70. It is not however expected that the capacity mechanism regulation will be in force before 201671. So far the electricity produced by CHPs is remunerated in on an Energy-Only-Market (EOM) with the CHP plants receiving a premium on for the environmentally harmful generation they displace. As it is also mentioned below there is no evidence that CHPs are contributing to the reserve service.

From November 2010, POLPX and the Scandinavian exchange (Nord Pool Spot) members are able to trade electricity transmitted via the DC cable cross - border connection (600 MW SwePol “Swedish Cable”) having coupled their DA markets. We can reasonably assume that this interconnection is to some extent contributing to the reserve margins of Poland as Nordel area is co-optimising reserves in the region.

2.8.1.3.3 Nordel area Around 15% of Nordic countries generation capacity comes from district heating cogeneration. Compared to the around 50% generation capacity which is coming from hydro power plants72 it would appear hard for co-generators to compete in the capacity market under supply surplus conditions.

As we discuss later in this report Sweden and Finland is using conventional generation to maintain strategic reserves. These strategic reserves are further enhanced but the overall high level of interconnection of the Nordic countries. Evidently73 in the two countries we have been able to witness only a 235 MWe CHP plant namely Inkoo3 owned by Fortum Power and Heat Oy. The strategic reserve power plants in Finland and Sweden are either owned or contracted and they can be used in possible spot market deficits after all commercial bids. In this sense the capacity adequacy in the region is guaranteed through the nuclear generation and interconnection capacity among the countries in the region and there are no lively discussions for capacity mechanisms.

Nordel market is integrated to an extent that it would allow for innovative ideas to flourish. One interesting business model which involves an aggregator comes from Denmark whose electricity and heating system is highly decentralised. Neas Energy74 is an independent international energy trading company (and Balance Responsible Party) operating in power, gas and certificate markets across Europe. Neas Energy has around 200 power producers in its portfolio whose individual electricity generation capacity ranges from 1MW to more than 300 MW. Many of these suppliers are district heating companies which incorporate CHP. The idea is that a single entity administers and controls

70http://www.pwc.pl/en_PL/pl/publikacje/assets/pwc_ing_5_myths_of_the_polish_power_industry_2014_report.pdf 71 http://polish-energy-blog.blogspot.com/2015/01/polish-capacity-market.html 72 http://www.nordicenergyregulators.org/wp-content/uploads/2013/02/Nordic_Market-report_2013.pdf 73 http://elering.ee/public/Infokeskus/Pressimaterjalid/Varustuskindluse_aruanne_2012/Pekka_Vile_Nordic-Baltic_power_market.pdf 74http://www.cogeneurope.eu/medialibrary/2014/12/03/4bb831e2/Case%20Study%20%20Neas%20Energy%20-%20December%202014%20FINAL.pdf

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over the internet a large number of decentralized units so that it can offer nearly all the products that are tradable in the Nordel market – even capacity if the development finally directs to there.

Technology wise and with particular reference to CHP generation, older units are inevitably used for peak operation (based on the simultaneous peaks for district heat and electricity. There are also plans about new CHP units with peaking capacity, e.g. topping gas turbines and even heat only boilers which can enable condensing generation at highest market prices.

Source: Avedore, Demark75

Figure 20: Generalised process diagram of an advanced type of CHP with fuel and operational flexibility

2.8.1.3.4 Czech Republic In the Czech Republic, CHP electricity is purchased for the market price plus an additional regulated price (premium). Every heat producer considering the construction or reconstruction of a heat source larger than 5 MW must determine whether CHP technology can be used, as must electricity producers for capacities over 10 MWe. In the case of gas turbines, this obligation starts from 2 MWe and with engines from 0.8 MWe. The potential of different CHP technologies is assessed, and the main development has been identified as related to DH.

Currently, as it is the case with more European countries capacity mechanisms are also under discussion in Czech Republic. With a large however variability of cross border flows owed to the increasing wind generation in neighbouring Germany and with the domestic electricity market suffering a reduction in electricity demand, the discussion just implicitly refers to CHP/DH power plants. On the contrary, stakeholders in the country argue that the capacity mechanism would be a means for reducing the continuous retirement of gas-fired generation76

75 http://www.power-technology.com/projects/avedore/avedore3.html 76http://fsr.eui.eu/Documents/Presentations/Energy/2013/131011CapacityMechanismsWorkshop/131011VondruskovaBarbora.pdf

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2.8.1.3.5 Greece A large CHP plant (330 MWe) operates in the Hellenic Interconnected (mainland) system. The CHP part of the plant (110 – 130 MW) is characterized as ‘high efficiency’ CHP and receives special Feed-In-Tariffs, while enjoying priority dispatch. The rest of the plant’s capacity (150-160 MW) participates in the wholesale market based on its daily bidding. This dispatchable part also is entitled to receive capacity payments while the CHP part is not entitled to such payments.

2.8.1.4 CHP technologies able to participate in capacity mechanisms We have so far seen, while reviewing countries or regions with an increased share of solid-fuel CHP/DH plants that the particular technology is not at the tip and of the preferences for candidate capacity mechanism providers. The generation industry77 argues that capacity mechanisms should be technology neutral and non-discriminatory i.e. give equal treatment to existing and new units for generation, storage, demand and cross-border participation, and should be coordinated at regional level to ensure consistency and minimum distortion to the internal energy market. Most of the regulators have respected technology neutrality principle with prominent cases the recent UK78 and France79 capacity market implementations.

Looking a bit further however on the particular CHP technologies that would be better off offering capacity products, it seems that the answer lies on the type of steam turbine the CHP plant is equipped with. More specifically non-condensing steam turbines are also referred to as "back pressure" steam turbines. In this turbine type steam is expanded over a turbine and the exhaust steam is used for to meet a facilities steam needs. The steam is expanded until it reaches a pressure that the facility can use.

The other type of steam turbine used in CHP applications is called an extraction turbine. In these turbines, steam in extracted from the turbine at some intermediate pressure. This steam can be used to meet the facilities steam need. The remaining steam is expanded further and condensed. Extraction turbines can also act as admission turbines. In admission turbines, additional steam is added to the turbine at some intermediate point. The steam extraction pressure may or may not be automatically regulated depending on the turbine design. Regulated or controlled extraction permits more steam to flow through the turbine to generate additional electricity during periods of low thermal demand by the CHP system. In utility type steam turbines, there may be several extraction points, each at a different pressure corresponding to a different temperature at which heat is needed in the thermodynamic cycle.

Non-condensing (Back-pressure) ST Extraction ST

77 http://www.eurelectric.org/media/153333/chp_as_part_of_the_energy_transition_final-2014-2130-0007-01-e.pdf 78 http://www.theade.co.uk/capacity-market-to-drive-a-more-wasteful-energy-system-whilst-government-shuns-efficiency_2781.html 79 http://www.wec-france.org/DocumentsPDF/3rd_european_energy_forum/T.Veyrenc.pdf

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Source: U.S. EPA, CHP Partnership: Catalog of CHP Technologies, March 201580

Figure 21: Back-pressure versus extraction Steam Turbine types

A pure back-pressure CHP plant has a fixed ratio between heat and electricity production, so if the electricity or heat output has to be adjusted, both electricity and heat production is changed. An extraction CHP plant is much more flexible and the ratio between heat and electricity can vary significantly. Modularity of the CHP is also important but there is a trade-off between flexibility of operation and investment cost. By starting and stopping some of the units the output can vary in a large range. In this case the units do not have to be operated at low capacity when its performance is lower. However the investment cost is significantly higher for several small units compared to one big unit. As we also mentioned earlier in the section where the role of CHP in Nordel market was discussed technology innovation (i.e. multi-fuel, topping gas turbines, auxiliary heat-only boilers, etc) but also business innovation (i.e. aggregators) may also contribute largely to capacity mechanisms.

2.8.1.5 Governance in the capacity market Experience from the EU from countries in which capacity mechanisms exist shows that most of the capacity mechanisms’ tasks (e.g. assessment of the power system’s adequacy, level of remuneration provide to Generators, etc.) is performed by the TSO. More specifically81:

80 http://www.epa.gov/chp/documents/catalog_chptech_4.pdf

81 European Commission, ‘Capacity Mechanisms in Individual Markets within the Internal energy Market’, June 2013.

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• In Italy, the mechanism provides compensation to producers who make back-up generation capacity available during critical days. The remuneration level is determined by the TSO depending on tightness of supply for each hour of the day;

• In Spain, the capacity mechanism has introduced availability services as contracts between TSO and plants selected for reserve purposes with one year duration and remuneration to new investment (capacity payment) for 10 years operation. The level of remuneration depends on reserve margin requirements estimated by the TSO.

• Finland and Sweden apply capacity mechanisms based on strategic reserves. In these countries the System Operator (or the agency responsible for ensuring security of supply) organizes 3-auctions for capacity contracts for three years at a time.

• Poland currently has a reserve service that resembles a strategic reserve. The arrangement includes 1700 MW of pumped storage power plants contracted by the TSO.

• In Eastern USA markets (PJM, MISO, ISO-NE) the capacity obligations are calculated for selected peak load demands expected to be served by each customer serving entity; the generating units issue capacity certificates depending on available capacity which is determined taking into account forced and unforced outages according to statistics collected in a TSO registry;

• In Brazil the System Operator auctions reliability contracts on an ad hoc basis depending on forecasts about possible energy scarcity;

In the case of Kazakhstan, a co-administration of the capacity market can be adopted. More specifically, the adequacy assessment study to identify the capacity needs should be performed by the TSO (KEKOG). However, and according to the capacity mechanisms adopted, the following approach is possible:

a) LONG-TERM MARKET (TENDERS): TSO – adequacy assessment, KOREM – auction + contract

b) INVESTMENT CONTRACTS (EXISTING PLANTS FOR EXPANSION OR REFURBISHMENT): TSO – adequacy assessment, TSO – auditing, KOREM contract

c) EXISTING PLANTS – NOT REFURBISHED: TSO – adequacy assessment, KOREM – auction + contract

2.8.2 Legal aspects

2.8.2.1 The role and legal status of Power Exchanges in the EU

2.8.2.1.1 Role of Power Exchanges in Europe The primary objectives of electricity market liberalization are the achievement of liquid competitive wholesale markets that provide market-based electricity prices to consumers, guarantee the system security and the efficient utilization and availability of the resources. Wholesale competition is enhanced on the supply side, by participation of several generation companies, and on the demand side by allowing customers to buy directly or indirectly from generators trough customer choice.

However, such competition could not be fully installed without Power Exchanges which play a key role in the liberalized electricity market in Europe. The existence of a Power Exchange is fundamental for a well-functioning of the retail market since a liquid Power Exchange gives the suppliers the opportunity to procure energy without the need to own production capacity. The main goals of the

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Power Exchanges lie in the facilitation of the trade of electricity in a short term and the promotion of information, competition, and liquidity. Power Exchanges may also provide other benefits, such as easy access, low transaction costs, neutral marketplace and price reference, safe counterpart and clearing, and settlement service. Spot Markets are created to provide an organized wholesale transactional environment where demand meets production at the lowest price.

Spot Markets may be characterized with respect to the following aspects:

• Market participation (voluntary or mandatory) • Trading timing • Traded products • Bid and offer format • Trading method and pricing criteria • Settlement and clearing • Congestion Management (in some countries the transmission capacity allocation is managed

in an implicit way in the Power exchange)

The development of facilities for electricity trading among different market operators is a key to a proper functioning of the EU liberalised energy market. Electricity can be traded physically for financial, bilateral and nowadays in many Member States it is been traded through organized electricity markets (Spot Markets organized in Power Exchanges).

2.8.2.1.2 Common (legal structure) provisions to the Power Exchanges With regards to their legal structure, Power Exchanges are governed by private corporate law which allow:

• A better their transparent and market based operation outside of any political interference from public authorities

• More independence as regards governance and room for operation without being subject to heavy public law requirements as the ones existing for public entities (independence of the budget and accounting)

• As for example, the German Power Exchange EEX is a corporation (Aktiengesellschaft) which: • Is limited by share ownership (i.e. is owned by its shareholders) and • May be traded on a stock market.

Furthermore, such corporate structure German AG’s (Aktiengesellschaft) have a “two-tiered board” structure, consisting of a supervisory board (Aufsichtsrat) and a management board (Vorstand). This allows more transparency in the Company’s governance.

• The supervisory board is generally controlled by shareholders, although employees may have seats, depending on the size of the company.

• The management board directly runs the company, but its members may be removed by the supervisory board, which also determines the management board’s compensation. Some German AGs have management boards which determine their own remuneration, but that situation is now relatively uncommon.

• The board of directors may appoint and dismiss persons entrusted with managing and representing the company.

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In many other countries have similar forms of corporate structure such as:

• Denmark (Aktieselskab, A/S) • Norway (Aksjeselskap, AS) • Sweden (Aktiebolag, AB) • Estonia (Aktsiaselts, AS) • Latvia (Akciju sabiedrība, AS) • Lithuania (Akcinė bendrovė, AB) • Russia (Открытое акционерное общество, Otkrytoie Aktsionernoie Obshchestvo, OAO) • Finland (Osakeyhtiö, OY)

The form is roughly equivalent to:

• The “public limited company” (plc) in both Ireland and the United Kingdom, • The Societe Anonyme (S.A.) in France

As regards the legal structure of Power exchanges, it worth underlying that a public or mixed (public/private structure) could hardly be seen as sustainable given the heaviness of entities/companies governed by Public law.

Furthermore, in Europe, the state of development of competition law leads to very restricted scenarios where State or public entity could own/finance companies in the form of public law. Indeed, the general ban of State Aid support from the State to private companies (with few and temporary exemptions) aims at ensuring a proper functioning of the EU Internal Market (incl. the energy sector) in a fully competitive environment which could only be foreseen through private corporate structure of power exchanges in Europe.

2.8.2.1.3 Participation in PXs (Mandatory vs. non-mandatory) The organized markets for wholesale electricity are structured in the form of a Power Exchange (PX) or in the form of a Pool. The rules for participation in these organized markets differ depending on the wholesale market model adopted in each country. There are different approaches about the two models. The differences between the two models lie in the initiative and participation:

• The power pools are the result of a public scheme and the participation is mandatory (all the energy must be traded on the pool).

• The Power Exchanges are encourage on a privately basis and the participation is voluntary.

2.8.2.1.4 Impact of the Power Exchanges on the new structure of the EU electricity market The Power Exchanges play an essential role in the new structure of the electricity industry, especially within the European wholesale Market which was until now dominated by bilateral trade.

All these Power Exchanges share the same goals. They aim to facilitate electricity trade, foster competition, ensure transparency and become recognized as a European marketplace. Finally, each Power Exchange aims to develop liquidity and credibility of its price index.

Power Exchanges are considered marketplaces, lets remark the word marketplace, is a third party which facilitate transactions between sellers and buyers, they are ruled by its own trading rules and they guarantee the payment.

As such the role of Power exchanges:

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• Facilitate trading: Power Exchanges make easy the short term trading because it gathers all the stakeholders of the wholesale market in one single market.

• Foster competition: By letting submit bids to generators, distributors, suppliers and eligible consumers. Every participant specifies the desire quantity and the price they are willing to pay/received.

• Ensure transparency: The bids are anonymously, the driver for the price is based on matching the supply and demand curves. The market clearing prices are public.

• Price index: Price in the Power Exchange is published on a daily basis and represent a useful tool for benchmark the bilateral transactions.

• Reduce credit risk: The counterpart for the transactions is the exchange’s clearinghouse. The role of the clearinghouse is to guarantee the financial regularity of the parties.

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2.8.2.1.5 Selected examples of Power exchanges in Europe Power Next

Powernext is a market undertaking based in Paris and operating under the “regulated market” (RM) status. Powernext currently designs and operates state-of-the-art electronic trading platforms for spot and derivatives markets in the European energy sector. Powernext SA, incorporated in 2001, manages several complementary and transparent energy markets:

• Powernext Gas Spot and Powernext Gas Futures launched on 26 November 2008 in order to hedge volume and price risks for natural gas in France. On 1st July 2011, GRTgaz and Powernext launched the first gas market coupling initiative in Europe between GRTgaz’s PEGs Nord and Sud. Powernext launched on 1st February 2013 a natural gas Futures market on the TTF hub in the Netherlands:

• Powernext and EEX launched PEGAS on 29 May 2013, a commercial cooperation where the 2 exchanges combine their gas markets to create a pan-European gas market; Powernext Energy Savings, a dedicated spot market for French White Certificates (Certificats d’Economies d’Energie) launched in January 2012;

• Powernext owns a 50% equity stake in EPEX SPOT and a 20% in EEX Power Derivatives.

The European Energy Exchange (EEX)

The European Energy Exchange is located in Leipzig. The current EEX emerged as a result of a merger between LPX Leipzig Power Exchange and the Frankfurt-based EEX in 2002. EEX operates market platforms for trading in electric energy, natural gas, CO2 emission allowances and coal. EEX holds 50% of the European Power Exchange EPEX SPOT located in Paris which operates short-term trading in power for Germany, Austria, France and Switzerland. Furthermore EEX's subsidiary EEX Power Derivatives GmbH offers a platform for German and French power derivatives trading. EEX currently holds shares in the following companies:

• Agricultural Commodity Exchange GmbH (100%) • Global Environmental Exchange GmbH (100 %) • European Commodity Clearing AG (98, 5 %) • EEX Power Derivatives GmbH (80 %) • Powernext SA (55, 8 %) • EPEX SPOT SE (50 %) • Gaspoint Nordic A/S (50 %) • Cleartrade Exchange Pte Ltd. (52 %) • Storage Capacity Exchange GmbH (12 %) • European Market Coupling Company GmbH (20 %)

With regards to EEX - Scope of Service, EEX collects, publishes and submits fundamental data and insider information across countries, commodities and the value chain on behalf of market

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participants. Various measures protect the data from being manipulated. Validation checks support reporting companies to achieve the highest data quality to the benefit of regulatory compliance. Insider information is released close to the marketplace to serve efficient trading decisions to the advantage of all. Data reporting to several entities according to European and national rules minimises customers’ efforts to follow further technical changes.

Nord Pool Spot

Nord Pool Spot runs the largest market for electrical energy in Europe, measured in volume traded (TWh) and in market share. It operates in Norway, Denmark, Sweden, Finland, Estonia, Latvia, Lithuania, Germany and the UK. More than 80% of the total consumption of electrical energy in the Nordic market is traded through Nord Pool Spot. It was the world's first multinational exchange for trading electric power. Nord Pool Spot offers both day-ahead and intraday market

Nordpool spot is owned by the national grid companies Fingrid, Energinet.dk, Statnett, Svenska Kraftnät, Elering, Litgrid and AST. Nord Pool Spot has the main office in Lysaker (Oslo) and offices in Copenhagen, Stockholm, Helsinki, Tallinn and London. It has wholly owned subsidiaries Nord Pool Spot AB and Nord Pool Finland Oy. In addition, in the United Kingdom Nord Pool Spot runs the N2EX power market. Nord Pool Spot AS has 380 members in about 20 countries. Members are public and private energy producers, energy intensive industries, large consumers, distributors, funds, investment companies, banks, brokers, utility companies and financial institutions.

Nord Pool Spot AS is the world's largest exchange for electrical energy measured in volume (501 TWh) in 2014. It operates the day-ahead market for electrical energy, Elspot, and the intraday market, Elbas. In 2012 Transmission system operators from the Baltic countries became Nord Pool Spot shareholders. The Estonian, Latvian and Lithuanian electricity transmission system operators (TSOs) Elering, Augstsprieguma Tīkls and Litgrid have signed a Memorandum of Understanding (MoU) on the purchase of the shares of the Nord Pool Spot, Europe´s largest power exchange. The current owners, Energinet.dk, Fingrid, Statnett and Svenska Kraftnät see the extension of ownership to the Baltic TSO´s as an important and natural step in the further process integration of the Baltic and Nordic electricity markets.

For the Baltic TSOs, the ownership of Nord Pool Spot is a strategic investment. It will enable participation in the decision-making process where the market interests of the respective Baltic countries are discussed. It allows the Baltic TSOs to contribute to the Nord Pool Spot corporate activities in development of the regional and European power

2.8.2.2 Recommendations with regards to the implementation of a capacity market in Kazakhstan


The ultimate goal of the introduction of capacity market mechanisms is to ensure the security of supply and benefit the end users has regards both the security of supply and cost -reflective tariffs.

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• The introduction of a capacity market can have the consequence to strengthening the market position of dominant operators and exclude the possibility of entrance of new players on the market. The energy and competition regulatory framework need to be given sufficient monitoring and sanction powers in order to ensure fair competition and avoid market dominance behaviour.


• The evaluation of the capacity needs should take into account opportunities connected to the interconnection system and the import of electricity. These will affects positively the security of supply and the volume of electricity import should be taken into account




2.8.2.2.1 Risks associated to the introduction of capacity mechanisms in a non-fully opened electricity market

The capacity market mechanisms are complex to introduce in electricity markets which are not fully liberalised or where the market is not opened enough to new entrants.

In case the market is still dominated by historical players (public or private companies), the introduction of capacity market mechanisms is rather complex and may only be profitable for former monopolies, big utilities or dominant market players. Therefore, the effect of the introduction of capacity market mechanisms on non-mature energy markets may impede further entrants to join the market and therefore have detrimental effect on the electricity market opening.

The ultimate goal of the introduction of capacity market mechanisms is to ensure the security of supply and benefit the end users has regards both the security of supply and cost -reflective tariffs. So far, the EU experience has not proven that capacity market mechanisms ensure such needs.

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More specifically, in markets where the opening to competition is not fully realised, capacity market mechanisms are not necessary proven to be efficient and may lead to distortion of competition, cartels and abuse of dominant position. As for example, in an opinion of the French Competition Authority of 2012, the French energy regulator evaluated that the introduction of capacity market mechanisms would raise the costs to be covered by consumers of EUR 200 to 500 Million per year.

2.8.2.2.2 Capacity market mechanisms do not necessarily bring more investment in power generation

As mentioned above, the introduction of capacity market mechanisms must be assessed according to two main objectives: foster and Incentivise investment in power generation and ensure a better control of the electricity demand, especially during peak hours.

Although there is little return of experience in this field, it is not proven that the setting up of capacity market mechanisms are necessary incentivise investment in power generation capacity.

Investing into power generation capacity implies to take into account fix and variable costs. When enquiring about the justification leading to the introduction of capacity market mechanisms and remedy to the « missing money » situation, there is no consensus among market players on the ground and extend of such « missing money»:

• Big utilities would rather see the « missing money » at all production levels (base and peak). • Alternative suppliers would rather indicate that the « missing money » is rather happening

for peak times.

Being rather new, the absence of international precedent/best practices does not allow assessing concretely the market players’ appraisal on « missing money ». This impacts any decision making process at the governmental level as regards the relevance of the introduction of a capacity market.

As for example:

• Some countries such as the Netherlands decided not to set up capacity market mechanisms on the ground of their complexity and hazardous/unproven results.

• In the United States (California and West Coast) capacity market mechanisms have been modified many times without a proven efficiency.

• In countries with longstanding market opening to competition, such as Scandinavian countries the absence of capacity market mechanisms has not been an obstacle to investment in generation capacity.

• Furthermore, it is not demonstrated that capacity market mechanisms are needed in order to be able to face high electricity consumption. Other means less expansive can be set up such as for example the promotion of energy efficiency for household customers.

2.8.2.2.3 The introduction of capacity market mechanisms need to provide new suppliers specific preconditions in order to invest in new generation capacity

Regarding access to electricity at a competitive price: new market entrants would benefit from baseload at a competitive price, for example at the level of price the historical operators such as former monopoly benefit from.

Such precondition has not always proven to exist. As for example, a foreign energy supplier entering into the French electricity market and aiming at developing a portfolio of French clients should have

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the possibility to access the base load and peak load at a competitive price, which means at a comparable level as the one benefitting to the historical operator Electricité de France. This is not currently the case. New market entrants have difficulties to access to/buy electricity produced from nuclear or hydro power, which are the cheapest ones. As for example, in France new market players only own 8 % of nuclear production capacity and manage only 19 % of hydro power plants. One of the solutions could be that the regulator imposes a better market opening.

Furthermore, regulated tariffs if not taking into account all costs supported by new market players may represent an obstacle to investment in new generation capacity.

2.8.2.2.4 The introduction of capacity market mechanisms need to be coupled with strong a competition law framework

For countries where the former monopoly/historical operator is (or are) still largely dominating the generation, supply and retail markets, there is a strong risk that such operator(s) will be the main owner and requester of capacity certificates.

The historical operator/former monopoly will de facto be the dominant operator for the emission of capacity certificates on the production side, and the main requester for capacity guarantees on the supplier side.

This results a strong power on the market and especially as regards the price formation/level of capacity certificates.

Such dominant position leads to potential risk of influence on raise or diminution of certificates prices exchanged on the market during the 4 years proceeding the reference year of capacity.

As for example, a dominant market operator (with significant production capacity) could sell its capacity certificates at a different prices whether it is for competitors (high price) or internally for its subsidiaries (low price). This would result in unbalanced pricing (ciseau tarifaire) and the potential exclusion of competitors on the supply market.

This is why the introduction of capacity market mechanism need both:

• A mature and opened market in order to avoid dominant market players, and • A strong competition and energy regulatory framework able to detect and sanction against

uncompetitive practices affecting effective market competition.

These two conditions are pre-requisites to the introduction of capacity market mechanisms. As for example, exchange of capacity certificates should be communicated to the energy regulator, in the frame of market surveillance/monitoring, including the internal cession/sale of capacity certificates.

This means that any introduction of capacity market mechanisms should include – in parallel – specific procedures allowing more transparency in the exchange of capacity certificates.

2.8.2.2.5 The introduction of capacity market mechanisms needs mechanisms for follow up, registration and monitoring of the capacity certificates trading

As regards market monitoring and surveillance, any transaction or offer of transaction for capacity guarantee needs to be reported to the energy regulator. On a corporate level, a capacity register could be useful in order to avoid market manipulation and allow statistical monitoring on the volume of traded certificates. In order to evaluate the relevance of capacity market, such level of trade

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should be benchmarked against the level of security of supply. A cost/benefit analysis will need to be regularly conducted at the Government/regulatory level.

2.8.2.2.6 The introduction of capacity market mechanisms needs to address the risks connected to the retention of capacity and artificial manipulation of the capacity market

The following example has been discussed in France by the Competition Regulatory authority in 2012 when the French Government wanted to set up secondary legislation to capacity markets.

Capacity market mechanisms rely mainly on the assumption that the market players will act in a responsible manner. However, the “bouclage centralisé” mechanisms imply specific risks:

As for example, should the TSO witness a market unbalance between supply and demand on a mid-term basis, the energy Minister could be entitled to launch a tender for investment in generation capacity.

The cost for such investment would then be bared by the suppliers according to their portfolio consumption during peak hours. Such mechanism is justified by the fact that external events could lead to a deficit of capacity threatening security of supply.

According to some energy experts, such mechanisms are contrary to the principle of capacity market where each producer should be able to manage its portfolio and forecast. Outside of Force majeure conditions (thus unpredictable), the market should not be in such a situation where new capacity is urgently needed.

As well, such mechanism could lead to market manipulation/distortion and opportunistic behaviour from operators who may see an opportunity to get their generation investment financed by the market operators whereas such investment would have been realised anyway. Additionally, electricity produced under these conditions would benefit from a guaranteed price for some years,

Needless to say that the temptation is wide for an operator to delay its investment and wait for a crisis situation where under successful tendering procedure new generation capacity would be financed by the other players at a fixed price for some years. In the end, the suppliers will include such participation to investment costs on consumers’ bill, which is contrary to the initial scope of capacity market mechanisms.

As well, the regulator should have enough inspection powers in order to check whether the generators could artificially limit their available capacity in order to ensure that sooner or later the emergency mechanisms (dispositive de bouclage) would be launched. In addition such behaviour would conduct to a rise if the wholesale electricity market prices. Again, consumer prices would be affected by this.

2.8.2.2.7 The introduction of capacity market mechanisms needs to be coupled with relevant powers granted to energy or competition regulator

Taking into account the above section, energy or competition regulatory authorities should be given enough powers to fight cartel or abuse of dominant position leading to anti-competitive practices.

Another mechanism leading to avoid market distortion could be that the regulator is given the possibility to check the available capacity of power plants for the last 4 to 5 years in order to ensure that generators (and especially dominant one(s)) are not tempted to manipulate their data by

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communicating an available capacity lower than the reality in order to unbalance the capacity market.

Indeed, in its role of market surveillance, it is crucial that the energy regulator is given the power to enquiry on whether data on forecasted certified capacity reflect the reality among generators.

A special mechanism would need to be set up where the energy regulator should be able to call for an investigation and/or fine from the competition regulatory authority in case an operator has deliberately under estimated the forecasted available capacity of their power plants.

As a matter of fact, the introduction of capacity market should lead to specific procedural changes in the powers of both energy and regulatory frameworks.

2.8.2.2.8 Electricity import should be taken into account while setting up a capacity market Import or export of electricity through interconnection allows a better management of security of supply. Historically, dominant market operators have better access to interconnection with neighbouring countries.

Capacity market imposes an obligation for local players to certify their generation capacity, but do not necessarily take into account possibility of import. For sure, it may be legally complex to set up a certification mechanism outside of national borders. As for example, allocation of interconnection rights fixed, for example at an EU or bilateral levels, make impossible for Government authorities to have a clear evaluation of the national level of security of supply during peak hours.

But in fact, mutualisation of import capacities can lead to help big utilities which have a strong portfolio of foreign clients. Dominant market players will necessarily take advantage of this situation. Interconnection should be more transparent and import volumes communicated to the energy regulator through a specific procedure and for each supplier. Another option would be to ensure that available interconnected capacity is sold through public auctioning so that small or new market entrants have a chance to purchase it as well.

2.8.2.2.9 The introduction of capacity market mechanisms should protect equality of treatment/non-discrimination among operators

The Legal framework should ensure equality of treatment/non-discrimination among all electricity market operators and avoid that competition distortion or discrimination unbalance the power market especially to the benefit of market dominant/big operators. Such provision needs to be clearly settled in any regulation or ministerial order setting up a capacity market.

2.8.2.2.10 The introduction of capacity market mechanisms should address the case of RES power generators benefiting from a Feed-in-Tariff system

Equality of treatment of operators, and therefore non-discrimination is a key legal principle for countries setting up capacity market mechanisms.

However, in most EU and Western countries, RES generators benefit from support mechanisms allowing them to sell their electricity produced at a guaranteed price, superior to average market prices and for duration up to 15 years.

Such support mechanism is meant to back-up the deployment of RES where the initial investment is much higher than the one for conventional energies. As any other power generation units, these RES installations are usually part of the capacity market/certification system. However, a competition law

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issue arise since RES installation benefit from a double subsidy system financed through the State budget:

• Support schemes allowing them to benefit of a higher price while selling the electricity • Capacity certificates

Such situation leads to unlawful advantage for RES producers which are not compliant with competition law principles.

2.8.2.2.11 Impact assessment Prior to the introduction of capacity mechanisms, a detailed impact assessment study is needed in order to assess:

• The costs of such system for the State and its sustainability in terms of public finance other the next decades

• The risk associated to reflection of the costs of capacity on the consumers’ bill • The level of market opening allowing or impeding free competition on the electricity market,

new market entrants, the risks connected to abuse of dominant position or market manipulation favouring biggest market operators

• The level of investment opportunities without any capacity market: does the forecast of investment in the power generation for the next 5-10 years allow sufficient security of supply without capacity market?

• The powers and level of independence of the regulatory framework: as mentioned earlier in this report; capacity market is not sustainable without a strong regulatory framework for both energy and competition sectors. It should be addressed whether the current regulatory structure allows sufficient to ensure a proper, fair and transparent functioning of the capacity market (namely, the Antimonopoly committee operating under the Ministry of Energy and the Committee for regulation of natural monopolies and protection of competition operating within the Ministry of Economy and Industry). Kazakhstan case differs from the EU best practices where regulation of energy is handled by the energy regulatory authority and any competition matter is dealt with at the level of the competition regulatory authority and both authorities cooperate where needed.

• The level of competition legal framework: capacity market mechanisms need to avoid market distortion, abuse of dominant position, cartels. It is of primary importance to check whether the current competition legal framework allows facing, assessing, fining and remedying any anti-competitive behaviour jeopardising the capacity market proper functioning.

• Level of State Aid related legal framework: as mentioned earlier, the raison d’etre and sustainability of a capacity market is connected to a competitive and opened electricity market. Subsidies or market distortion do not fit with a reliable capacity market. Without this pre-requisite, the capacity market faces the risk to be reduced a subsidy scheme for investment in new generation capacity. Therefore, it may be relevant to address the subsidies or state aid the public enterprise may benefit from in comparison with fully privatised generation/supply companies.

• The institutional setting for Regulatory framework. In Kazakhstan the regulation energy sector is distinct according to the players: Generation is regulated by the ministry of energy whereas the retail and tariffs are regulated by the Ministry of Economy through the

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Committee of protection of competition. The fact that no regulatory authority is in place as an independent institution (energy regulator of the one side and competition regulator on the other side) needs to be addressed.

• Mechanisms of control for each market operator of the guaranteed capacity every year • Existence and enforceability of the administrative sanctions in case of on respect of the

capacity commitment, authority in charge of this fine, existence of relevant appeal procedures

• Estimation of the role of electricity imports in security of supply. Benchmark with the setting up of capacity market mechanisms

• Existing legal provisions with regards to competition law and especially cartel, state aid and abuse of dominant position. Review of the market monitoring and enforcement measures.

• Tendering regime allowing further/new markets participants with specific precedence for new market entrants or small/medium players: As for example, analyse the opportunity to include in tender documents specific provisions allowing more points for the benefit of new market entrants (this option has been proposed in 2012 by the French Competition authority in its comment on Capacity Market implementation in France)

2.8.2.2.12 Legal recommendations in the drafting of a Ministerial order setting up capacity market

In the case of Kazakhstan, the capacity market will be set up through a ministerial order, such order should to comprise the following provisions:

• Justification for the capacity market (security of supply, investment in generation, etc.) • Duties of the operators holding capacities • Duties of the suppliers • Organisation of the capacity market and surveillance means (which authority? Which

enforcement means?) • Administrative and regulatory provisions for inspections and fines against unlawful practices • Emergency tendering mechanisms (dispositif de bouclage): purpose, conditions and limits • Setting up a regular Ministerial evaluation of the state of play of capacity mechanisms and

their consequences on electricity prices and on competition/level of opening of the sector to new market entrants in order to avoid cartel or abuse of dominant position

• Set up mandatory obligation for generators to communicate to the Ministry the internal trading price of capacity certificates vs. external prices in order to avoid market distortion

• Set up mandatory obligation for generators to declare available capacity on the basis of historical available capacity, forbid any lower level of capacity estimation unless authorised by the Ministry of Energy

2.9 REGIONAL MARKET OF CENTRAL ASIA

In the centrally planned era the regional electricity flow in the Central Asia Region used to be part of a wider economic planning context. Electricity, water, cotton, fuels and other commodities where exchanged year-round in an area which used to be part of a single state.

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With the collapse of the Soviet Union the re-scheduled deliveries were hard to be matched as commodities where now produced by different counties under different conditions. The history is more or less known and what is important to be highlighted is that the electricity flows in the region have gradually and steadily been decreasing in an area where the hydro-thermal cooperation would be beneficial - as it used to be in the past but nowadays even more due to the technological advancements.

In the discussion that took place with Kazakh stakeholders in the Ministry of Energy with the participation of the international regional electricity coordination centre namely CDC Energia. The following barriers have been identified:

1. All neighbouring states of Central Asia are at the moment in the course of pursuing single-sided energy independency strategies. This leans to overinvestment and sub-optimal use of the regional resources

2. The formerly integrated Central Asian electric power system has gradually shifted its centre of gravity towards its eastern part following the Turkmenistan and Uzbekistan disconnection from parallel operation in 2003, and 2009 respectively with the latter one imposing the disconnection the power system of Tajikistan. This tendency will be enhanced by the interconnection of the power system of Afghanistan (and perhaps later Pakistan) by means of the CASA-1000 project. Additional interconnection capacities will be required if at some point Turkmenistan, Tajikistan and Uzbekistan decide to work towards re-integration.

3. Whereas infrastructure is being building there is an absence of an institutional set-up that would ensure Third Party Access to the interconnectors allowing thus for a future level playing field on which future market actors may compete on resources under mutually-recognized, predetermined and transparent market rules

One the above premises the original motivation that drove the inclusion of the regional dimension in this assignment seems to no longer hold valid. Kazakhstan beyond any doubt comprises an important player if the future market –primarily due to its market size and level of advancement – but it is rather unlikely that it could catalytically lead the process in which the rest of the partners are not convinced to follow.

As far as the Roadmap for the development of the Regional Central Electricity Market is concerned, in the views of the ITS team this can for the time being define general directions but the detailed milestones to be accurately defined they would require all prerequisites to be in place. Instead of a full-defined Roadmap the one proposed below describes the necessary prerequisites for a process to be set up in order to guide development. Perhaps the discussions at international level e.g. the Energy Charter Treaty on which several members of the Central Region are signatories would be able to support and facilitate a process such as the one briefly described below:

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At the level of political cooperation important steps need to be made towards trust, solidarity and eventually good business relations and cooperation. At the moment the Kyrgyzstan and Kazakhstan systems which preserve synchronisation may be able to discuss these issues either bilaterally or through the activities of the Euro-Asian Customs Union. But as gradually the CASA-1000 project would engage additional countries with first of them being Afghanistan perhaps another political forum may be required. This can be a role of the Energy Charter Treaty as previously mentioned or another cooperation initiative either existing or new under the condition that it provides for the frame for a structured policy dialogue. INOGATE in its part whilst not in the place to play such a role hosted a regional event in Chisinau, Moldova in July 2015 where the process, strategy and tools for the development and monitoring of energy policies where discussed. We will continue working in this area providing the necessary knowledge and build capacities. The focus however on the specific issues in the region requires a more dedicated and higher level discussion in order to promote the objectives of regional integration.

At the level of regulatory cooperation the state of advancement is currently at an elementary stage of advancement. Some of the countries have National Regulatory Authorities with competences that mostly address the licensing and tariff issues. National Regulatory Authorities and their regional cooperation - when it comes in question - are important steps in the course of developing and strengthening a regional market. The divergence of pricing mechanisms needs to be harmonized in the countries participating in the regional market and the relevant trade obstacles should be identified and eliminated. This has always been the field of conduct of the regulatory authorities in several areas of the world.

There are two levels of cooperation that need to be established at and operational level. Ideally TSOs would work with TSOs in establishing the system security and market procedures in order to maximize the use of the interconnections – and thus their economic value. TSO practices are far from being harmonized in the region and there seem to be rather individual procedures in place to deal









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with unintended deviations of cross border schedules. Here the role of CDC Energia is crucial as it can both undertake the overall coordination in terms of security and integrity of the power systems as well as the market facilitator if and when a market based mechanism is established in the Central Asian regional electricity market.

2.10 Challenges Faced One of the biggest challenges faced in the present assignment had to do with the considerable gap of the EU and Kazakh legislation with respect to the organisation and operation of the energy sector in generally. While the organisation of the electricity market of Kazakhstan is in many ways similar to several EU countries the primary legislation is way too generic in comparison to the 3rd Energy Package. Some of the reported issues in the electricity market have also direct relevance to competition legislation and we assume that this might not only lead to unique considerations in the electricity sector but might probably affect the Kazakh economy as a whole.

Another challenge had to do with the infrequent exchange of experiences between Kazakhstan and the EU. Kazakhstan being a member of the Euro-Asian Economic Union is determined to integrate its electricity market with the other members of the union and this does not entail compliance to the EU Acquis. It is therefore rather difficult to identify and propose solutions of the reform of certain segments of the electricity markets in an isolated manner.

Last but not least, the development of cross border electricity infrastructure in Central Asia has both shifted the centre of gravity to countries that fall beyond the regional group of five Central Asian ex-soviet union countries while it currently has little in common with the regulatory framework adopted in Europe for the development of key energy infrastructure.

2.11 Impact The main role of this assignment was to raise awareness of key decision makers in the Kazakh electricity market. It is understood that several lessons learnt as well as the terminology, taxonomy and principles of the EU electricity markets might serve as an important background and basis for further thinking on questions that might appear to be in their essence similar to those discussed in this report. We hope that reform process in the electricity sector of Kazakhstan will continue with the support of other international development partners and this will also include the objectives of the creation of a regional electricity market. Looking at this work from a different perspective we hope that part of this analysis will be useful to any party that is interested in the Kazakh electricity market irrespectively of the viewpoint (EU or non-EU reader).

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2.12 APPENDICES

2.12.1 APPENDIX 1: EU Best Practices: Example of the French Wholesale Market / trading activities

2.12.1.1 Definition

2.12.1.1.1 The wholesale market In the wholesale market, electricity is traded (bought and sold) prior to its supply to the destination grid of the end customer (individual customer or commercial82).

2.12.1.1.2 The players The players on the wholesale market are:

• the electricity producers (who own the generating stations): they trade and sell their production • the electricity suppliers (who subsequently sell electricity for consumption by the end customer):

they trade and supply electricity • brokers or traders: they purchase electricity for resale and thus favour market liquidity

2.12.1.1.3 The trading places Trading can take place:

• on stock exchanges (Epex Spot France for spot products, based in Paris, and EEX Power Derivatives France for future products, based in Leipzig)

• via brokered mutual agreement, i.e. via a broker • via direct mutual agreement (pure two-way)

Transactions may be purely financial (if the product is purchased and then resold), or may lead to a physical supply to the French grid.

2.12.1.1.4 The different segments of the wholesale market Upstream, the electricity supplied to the French grid comes from:

• generating stations for over 90% • imports from other European countries

A share of production is not traded on the markets and is supplied directly to the end customer due to the presence of integrated energy companies (i.e. both producer and supplier).

The remaining production is traded on the wholesale markets, giving rise to several transactions which may lead to physical nominations.

In addition, EDF offers access to 5,400 MW of its production capacity located in France via quarterly auctions (Virtual Power Plants or VPP).

82Source: CRE (the French Energy Regulatory Commission) http://www.cre.fr/en/markets/wholesale-market/the-electricity-market

http://www.cre.fr/en/markets/wholesale-market/the-electricity-market

http://www.cre.fr/en/markets/wholesale-market/the-electricity-market

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Downstream, electricity is drawn from the grid:

• for end consumption for over 80% • for export • and a share is lost

The diagram below shows the different upstream and downstream segments in 2009.

Source: RTE (data 2011)

2.12.1.2 Products and pricing A distinction is made between spot or cash products (purchased for delivery on the same day or following day) and forward products (purchased for delivery during a given period in the future). Each product is characterised by ‘base’ supply (24 hours a day, 7 days a week) or ‘peak’ (supply from 08.00 a.m. until 08.00 p.m. from Monday to Friday).

2.12.1.2.1 Spot products Depending on the markets, spot products are:

• daily products (day-ahead) or week-end products • half-hour or hourly products or in blocks of several hours

The reference price for the spot trade is the price of the day-ahead product on Epex Spot, fixed every day at 12 noon by an auction mechanism.

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This price is negotiated on the evening before delivery the following day, which reflects the short-term supply-demand balance before adjustment (performed by RTE in real time). These short-term prices are highly volatile. The electricity cannot be stored (an excess in demand at a given time cannot be compensated by an excess supply a few hours beforehand) and the factors which influence the supply-demand balance may vary greatly, as can the climatic conditions (cold weather pushing up consumption, an absence of wind which leads to a fall in wind-power generation in Germany etc.) or events, foreseen or unforeseen, in the electrical generation park (power station breakdown, lowered interconnection capacity etc.).

Source: Epex Spot base day-ahead pricing

2.12.1.2.2 Forward products To minimise the risks inherent in the spot market, the electricity market players sign electricity sale/purchase contracts for the supply of electricity over the weeks, months, quarterly periods or years to come, at a price negotiated on the contract date.

These forward, or future contracts, cover standardised products in order to facilitate their trade (for example, supply of base electricity MW, i.e. during all hours of the month, or at peak times, i.e. from 08.00 a.m. until 08.00 pm from Monday to Friday).

With a longer horizon, and actually corresponding to an average of the spot prices anticipated for the period in question, future products are less volatile.

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These products are used to define pricing for the end customer: when a supplier signs a contract with a customer, he will generally cover himself for the majority of supplies he will have to make by purchasing the future products required.

Source: base annual product price (supply for year n+1) – EPD France

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2.12.1.2.3 Publications associated with the French Electricity law (NOME Law, new organisation of the electricity market)

List of current applicable framework agreements:

In accordance with Article L. 366-5 of the Code de l’énergie (French Energy Act), CRE publishes the list of suppliers who have signed a framework agreement with EDF (Electricité de France) on its website.

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2.12.2 APPENDIX 2: Kazakhstan Electricity Sector Profile

2.12.2.1 Brief characteristics of the Republic of Kazakhstan

Land Area - 2.7 mln. sq. km.

By land area, Kazakhstan is the second largest country in the CIS and the ninth largest country in the world. Kazakhstan shares borders with China, Kyrgyzstan, Turkmenistan, Uzbekistan, and Russia, with a total border length of 12187 km.

Population – 17.1 mln. people.

Administrative and territorial division: Kazakhstan is administratively divided into 14 regions.

Two cities, Astana – Kazakhstan capital and Almaty, have republican status.

Distance: North-South -1610 km., West-East - 2905 km.

2.12.2.2 State authorities vested with functions and powers in the area of functioning and development of the energy sector

Pursuant to the Decree of the President of the Republic of Kazakhstan dated August 6, 2014 “On the Reform of State Management System of the Republic of Kazakhstan”, a number of ministries have been created and reorganized.

State authorities vested with functions and powers regarding regulation and development of the power industry:

1. Ministry of Energy – formulation and implementation of state policy in the area of electric power industry, nuclear energy, oil and gas industry;

2. Committee for nuclear and energy supervision and control of the Ministry of energy

3. Committee for regulation of natural monopolies and protection of competition of the Ministry of National Economy (КРЭМ and ЗК МНЭ РК)

4. Statistics Committee of the Ministry of National Economy

5. Committee for protection of consumer rights of the Ministry of National Economy

6. Institute for the development of electric power industry and energy saving

NGOs: 1. Association “Каzenergy”

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2. Kazakhstan electric power organization (КЭА)

3. Union of power engineers

2.12.2.3 General characteristics of the electric power industry

Kazakhstan’s electric power industry, which occupies a central geographic position between the energy systems of Central Asia, Eastern and Western Russia, has been established in line with the key principles of USSR unified energy system, which is based on power transmission lines with voltage classes of 110-220-500-1150* (500) kV.

The Northern region plays a central role in Kazakhstan’s Unified Energy System (UES). The majority of the electricity generation (78%) and the developed power transmission networks 220-500-1150 kV linking Kazakhstan’s UES with Russia’s UES are concentrated in the Northern region.

Kazakhstan’s power transmission facilities comprise power transmission lines with voltages of 0,4-6/10-35-110-220-500 and 1150(500) kV. The length of all overhead power transmission lines (OHPL) with voltages 0,4÷1150 kV and the number of step down substations with voltages 35-1150 (500) kV are specified in Table 1.1 by voltage type.

Table 1.1 – Power transmission lines and Substations

Power transmission

lines

Length (km) Substations

OHPL 1150 kV 1421,225 ПС 1150 kV - 3 / 9384,1 unit/mVA OHPL 500 kV 5470,3 ПС 500 kV - 15 / 11828 unit/mVA OHPL 220 kV 20269,1 ПС 220 kV - 93/ 15740,03 unit/mVA OHPL 110 kV 37931,9 ПС 110 kV - 873/ 18412,76 unit/mVA OHPL 35 kV 59317,6 ПС 35 kV - 2085/ 9863,68 unit/mVA OHPL 6-10 kV 208275,1 ТП 6-35/0,38 kV - 90916/ 16949,26 unit/mVA OHPL 0,4 kV 122019,6 -

The role of the backbone network in Kazakhstan’s UES is performed by 220-500-1150(500) kV power transmission networks. Intersystem connections with the energy systems of Kyrgyzstan, Uzbekistan and the Russian Federation are organized under the 220 and 500 kV voltages (Table 1.2).

Table 1.2 – Interstate power transmission lines

Substation name Voltage (kV) Length (km)

Transmission capacity

(MW) Kostanay-Chelyabinskaya 500 (1150) 338 900

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Ekibastuzskaya-Barnaulskaya 500 (1150) 700 800 Avrora-Kurgan 500 276 500 Аvrora-Tavricheskaya 500 282 500 Sokol-Troitskaya regional power plant 500 164 900 Public JSC “ЕЭК” – Tavricheskaya 500 369 900 Public JSC “ЕЭК” – Rubtsovsk 500 331 1200 Nuclear power plant Ekibastruz-Tavricheskaya 500 371 900 Zhetikara-Iriklinskaya regional power plant 500 185 900 Stepnaya-Balakovskaya nuclear power plant 500 240 250 Ulke-Novotroitskaya 500 150 330 Ust-Kamenogorsk-Rubtsovsk 500 150 800 Avrora-Makushino 220 114 250 Aktyubinsk-Orsk 220 170 240 Kimpersay-Orsk 220 85 250 Petropavlovskaya Combined heat and poer plant-2 – Ishim

220 59 250

Priuralskaya – Troitskaya regional powr plant 220 45 250 Stepnaya-Golovnaya 220 259 120 Uralsk-Kinel 220 250 190 Shymkent-Tashkentskaya regional power plant 500 112 1200 Zhilga-Tashkentskaya regional power plant 220 77 300 Shymkentskaya-Tashkentskaya regional power plant 220 132 400

Almaty-Bishkek 500 299 700

Zhambyl-Bishkek 500 216 900

Аlmaty-Glavnaya 220 199 240

Zhambylskaya regional power plant – Bishkek 220 178 240

Zapadnaya – Bystrovka 220 80 220

Shu-Glavnaya 220 174 240

The potential of existing interstate power transmission networks of the Northern, Southern, and Western regions - as a sum of indicators on receipt, exchange and transmission of transit interstate electricity flows – is estimated to be about 30 bln. kWh per year.

In 1990, under parallel operation of the Northern and Western regions within the unified energy system of USSR and operation of the Southern region within the interconnected energy system of Central Asia, these flows reached practically the maximum limit and totaled about 28 bln. kWh.

In 1997, these flows dropped to 7.8 bln. kWh. This downturn resulted from the decreased demand but also the abandoning of the parallel operation with the Russian Federation under the transit Siberia – Kazakhstan – Ural.

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2.12.2.4 Current status of Kazakhstan electric power industry

Kazakhstan’s electric power industry is currently characterized by the following:

• High concentration of power generation capacities – up to 4000 MW at one power plant; • Location of large power plants usually close to fuel deposits • High share of combined electricity and heat generation for industrial and public utility needs • Insufficient share of hydro power plants in the balance of Kazakhstan electric power generation

capacities • A well-developed scheme of power transmission lines where 500 and 1150 kV voltage overhead

power transmission lines serve as backbone lines • Functional power system protection securing reliability of the unified energy system in case of

emergency and post-emergency situations • A unified vertically integrated system of operational dispatch management performed by the

Central Dispatch Administration, regional dispatch centers and electricity consumers’ dispatch centers.

Coal is the main fuel and energy resource in Kazakhstan and is based on Ekibastuz deposits of cheap coal. Coal deposits, as well as major power plants, are mostly concentrated in Northern and Central Kazakhstan. These regions are self-sufficient in terms of electricity and potentially have electricity excess, which can be offered to domestic and foreign electricity markets.

Kazakhstan’s unified energy system consists of three zones: Northern, Southern, and Western, analysed below:

• The Northern zone comprises the energy systems of Akmola, Estern-Kazakhstan, Karaganda, Kostanay, and Pavlograd regions united by a common power network and operating in parallel with Russia’s unified energy system

• The Southern zone comprises the energy systems of Almaty, Zhambyl, Kyzylorda, and South-Kazakhstan regions united by a common power network, has a well-developed electric connection with Kyrgyzstan and Uzbekistan, and is part of Central Asia’s unified energy system. In case of repair or emergency mode, the Southern zone operates separately from Kazakhstan’s Northern zone;

• The Western zone comprises the energy systems of Aktyubinsk, Atyrauysk, Western-Kazakhstan, and Mangistausk regions and has an electric connection with Russia. Mangistausk, Atyrausk, and Western-Kazakhstan regions are united by a common power network, and Aktyubinsk regional energy system (which operated separately till the end of 2008) is connected to Kazakhstan’s unified energy system after the 500 kV interregional power transmission line “Northern Kazakhstan – Aktyubinsk region” was put into operation.

Following the completion of the project “Construction of the second 500 kV power transmission line for the transit North-South of Kazakhstan” in 2009, the volume of electricity transmission to the southern regions during the winter time totals up to 1350 MW. A schematic map illustrating power networks with

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over 220 kV voltage is presented in Fig. 1.1

Figure 1.1 - Diagrammatic map of 220-1150 kV power transmission networks (source: JSC “KOREM”)

2.12.2.4.1 Power plants Currently, the number of power plants installed in Kazakhstan is 76. The largest power plant, Ekibastuzskaya regional power plant -1, has an installed capacity of 4,000 MW (8 х 500 MW). The largest power generation unit is 500 MW. The largest hydro power plant is the Shulbinskaya hydro power plant with 702 MW of installed capacity. The number of multiple-unit power plants is 5, while the number of installed units is 27 in total.

The total installed capacity of all power plants, as of 01.01.2014, is 20591.5 MW, including:

1. Combined heat and power plants – 18002.4 MW (87,4 %), including steam turbine CHPs with 16576,5 MW capacity and gas turbine combined heat and power plants with 1425,9 MW capacity

2. Hydro power plants - 2583 MW (12,5 %), including small hydro power plants with 110,8 MW capacity (0,54%)

Карта-схема электрических сетей 220- 1150 кВ

Центральная Азия

К и т а йКарта-схема электрических сетей 220- 1150 кВ

Центральная Азия

К и т а й

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3. Wind power plants - 5,6 MW (0,03%) 4. Solar power plants - 0,5 MW (0,01%)

Total installed capacity of power plants (01.01.2014)

Type Capacity (MW) %

1 Combined heat and power plants 18,002.4 87.43% 1.1 Steam turbine CHP 16,576.5 80.50% 1.2 Gas turbine CHP 1,425.9 6.92%

2 Hydro power plants 2,583.0 12.54%

2.1 Large HPPs 2,472.2 12.01% 2.2 Small HPPs 110.8 0.54%

3 Wind power plants 5.6 0.03% 4 Solar power plants 0.5 0.00%

Total 20,591.5 100.00%

The installed capacity of power plants as divided by Kazakhstan zones is as follows:

• Northern zone - 14597,9 MW • Southern zone - 3329,1 MW • Western zone - 2664,5 MW

Available capacity of power plants in winter time totaled 17108 MW, while in the summer capacity is 15320 MW.

Average age of power generation equipment of combined heat and power plants is 28,3 years with equipment over 30 years old being the 61% of the total equipment installed, while average age of power

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generation equipment of hydro power plants is 36,5 years with equipment over 30 years old being the 57,1% of the total equipment installed.

Information on some of the largest power plants is presented in Table 1.3 below.

Table 1.3 - Largest Power Plants

№ Thermal power plants

Turbine generator capacity

(МW)

Number of turbine

generators

Installed capacity of the

power plant

(МW) 1 LLC “AES Ekibastuz” (Ekibastuzskaya regional

power plant -1) 500 8 4000

2 Public JSC “ЕЭК” (Ermakovskaya regional power plant)

300/310 7/1 2410

3 “Zhambylskaya regional power plant after Baturova”

200/210 3/3 1230

4 Public JSC “Stantsiya Ekibastuzskaya” (Ekibastuzskaya regional power plant -2)

500 2 1000

5 Combined heat and power plant -2 МАЭК 50/60/80/100 10 630

6 Heat power plant - 3 МАЭК 200/210/215 3 625

7 Regional power plant of corporation Kazakhmys (Karagandinskaya regional power plant -2)

50/86/100 7 608

8 Almatinskaya combined heat and power plant - 2

50/80/110 6 510

Within the structure of total volume of energy generation in 2013 (91,9727 bln. kWh) the share of thermal power plants was 77,622 bln. kWh (84,4%), hydro power plants - 7,701 bln. kWh (8,4%), gas turbine power plants - 6,6458 bln. kWh (7,2%), wind power plants - 0,0031 bln. kWh, solar power plants - 0,0008 bln. kWh. The share of electricity generation by zone was as follows: Norther zone - 78 %, Southern zone -13 %, and Western zone -11%.

The aggregate volume of electricity consumption in 2013 totaled 89,6408 bln. kWh. Electricity consumption share of the Northern zone was 68%, Southern zone -21%, and Western zone -11%.

The structure of electricity consumption in 2013 is presented in Table 1.4 and electricity consumption by large consumers in Table 1.5.

Table 1.4 – Structure of electricity consumption - 2013

Consumers Consumption

volume mln kWh

% of total consumption

volume

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Large consumers 33697,1 37,6 Power grid companies 5607,9 6,3 Power supply organizations –guarantee suppliers

24379,4 27,2

Power plants’ own needs 8221,2 9,2

Other consumers 17735,2 19,7 Total 89640,8 100 %

Table 1.5 – Electricity consumption by large consumers

N Name Annual [MWh] 1 JSC “ArcelorMittal Temirtau” 3866,8 2 JSC AZF (Aksuysky) “TNK Kazkhrom” 5748,6 3 LLC “Corporation Kazakhmys”, Zhezkazagansky

site 1562,4

4 LLC “Kaztsynk” 2728,5 5 S-Sarbaysky GPO 2431,9 6 LLC “Corporation Kazakhmys”, Balkhaskaya site 629,6 7 JSC AZF (Aktyubinsky) “TNK Kazkhrom” 1458,7 8 Regional state enterprise “Channel after

Satpaev” 322,9

9 LLC “Kazphosphate” 1993,1 10 JSC “NDFZ” (part of LLC “Kazphosphate”) 1759,6 11 LLC “Tarazsky Metallurgical Plant” 58,8 12 JSC “Ust-Kamenogorsk Titanium-Magnesium

Integrated Plant” 574,7

13 Tengizshevroyl 1792,1 14 Pavlograd Aluminum Plant 1034,6 15 Kazakhstan Electrolysis Plant 3626,2

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The historical evolution of consumption, electricity generation and net power flows over a period of more than 20 years is shown in Fig. 1.2 and the dynamics of maximum capacity in Fig. 1.3.

The peak of electricity consumption in Kazakhstan was in 1990 prior to the collapse of the Soviet Union (105 bln. kWh) while the largest decline in consumption was in 1999 (50,3 bln kWh).

The transition to market-driven principles of power industry operation in early 90’s (in light of twofold capacity excess and high transmission capacity of power networks resulting from the sharp decline of consumption in practically all the branches of industry and the agricultural sector) predetermined the further development of Kazakhstan’s power industry.

Fig. 1.2 Dynamics of consumption, generation and net power flows

bln kWh 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001

Consumption 105 97.2 93.3 86 77 70.6 62.1 52.2 52.9 50.3 54.4 56.7 Generation 87.4 81.8 79.2 74.5 64 63.2 55.3 57.1 49.1 47.5 51.4 55.2 Net power flows

17.6 15.4 14.1 11.5 13 7.4 6.8 -4.9 3.8 2.8 3 1.5

bln kWh 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 Consumption 58.1 62 63.7 68.1 71.9 76.4 80.1 78 83.8 88.1 91.4 89.6 Generation 58.2 63.7 66.7 67.6 71.6 76.4 80.6 78.4 82.3 86.2 90.2 91.9 Net power flows

-0.1 -1.7 -3 0.5 0.3 0 -0.5 -0.4 1.5 1.9 1.2 -2.3

Fig. 1.3 Maximum load dynamics

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2.12.2.4.2 Export-import electricity supply Electricity net power flow in Kazakhstan in 2013 was as follows:

Volume, mln. kWh Electricity import 884,2 including from Russia 510 to Central Asia 374,2 including, from Kyrgyzstan

374,2

from Tadzhikistan 0 Electricity export 3216,1 including, to Russia 2810,6 to Central Asia (Uzbekistan)

405,5

Net power flow -2331,9 including to Russia -2300,6 to Central Asia -31,3

2.12.2.5 Existing Market Model and Tariff setting Principles

2.12.2.5.1 Legal and regulatory framework

Laws and regulations governing electric power industry of the Republic of Kazakhstan are as follows:

1. The law of the republic of Kazakhstan “On Electric Power Industry” dated July 9, 2004 N588-II (As

amended as of July 4, 2013)

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2. The law of the Republic of Kazakhstan “On Amendments and Alterations to Certain Laws of the Republic of Kazakhstan Related to Electric Power Industry, Investment Activity of Natural Monopoly Subjects, and Regulated Markets” (dated July 4, 2012)

3. The law of the Republic of Kazakhstan “On Supporting the Use of Renewable Energy Sources” dated July 4, 2009 N 165 –IVЗРК

4. The law of the Republic of Kazakhstan “On Energy Saving and Enhancing Energy Efficiency” dated January 13, 2012 N 541 –IV ЗРК.

5. The law of the Republic of Kazakhstan “On Competition” dated December 25, 2008 N12 –IV

6. The law of the Republic of Kazakhstan dated July 9, 1998 N 272 –I “On Natural Monopolies and Regulated Markets” (as amended as of September 29, 2014)

7. Resolution of Kazakhstan Government dated March 10, 2009 № 277 “On Approval of the Rules for Determining the Estimated Tariff and Approval of Marginal/Threshold and Individual Tariffs”

There is a number of implementing regulations based on the above legislaiton, which are available on web sites of respective state agencies, companies etc.

2.12.2.5.2 Stages of electric power industry reform A stage-by-stage restructuring of the electric power industry aimed at the transition of the industry’s functioning and development, based on market principles, has been performed in accordance with the state’s program for restructuring and privatization of the electric power industry’s objects:

1st Stage (1994-1996)

• Establishment of the state-owned energy company “KazakhstanEnergo” called to perform the functions of the unified buyer and transfer of 22—1500 kV transmission networks and power plants of national significance to this company;

• Creation of 9 regional state enterprises (RSE) and transfer of local power plants and 0,4-110 kV power distribution networks to these enterprises. RSEs enjoy the monopoly to supply electricity in their respective territory.

2nd Stage (1996-2000)

• Transformation of RSEs into power distribution companies (PDC); • Separation of power stations of national significance from state-owned company

“KazakhstanEnergo” and transformation of the latter into national power distribution company (public JSC “KEGOC”) called to perform the functions of dispatch administration;

• Privatization of the majority of power plants; • Initiating the establishment of wholesale electricity market providing the freedom of choice with

regard to sale-purchase of electricity; • Abandoning the regulation of wholesale suppliers’ prices; • PDC monopoly in the retail market.

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3rd Stage (2000-2003)

• Establishment of the market operator (JSC “KOREM”) to organize centralized trade for electricity; • Assigning the following functions to JSC “KEGOC”: transmission and consumption of electricity

through power networks with voltage of 110 kV and higher; compilation of a daily schedule of electricity generation and supply; compilation of actual electricity supply-consumption balance based on the results of calculation/accounting period (month); functions of technical operator for centralized operational and dispatching management of the modes of electricity generation, transmission and consumption within the unified energy system.

As a result of stage-by-stage market reforms in the electric power industry, a tow-tier electricity market has been established, which comprises wholesale and retail electricity markets. The structural scheme of wholesale market is presented in Annex 1.

2.16.2.1.1 Subjects of the wholesale electricity market The subjects of the wholesale electricity market are:

• Power generation organizations, which supply electricity to the wholesale electricity market with a volume of no less than 1 MW of average daily (base-load) capacity;

• Electricity consumers, which purchase electricity on the wholesale market with a volume of no less than 1 MW of average daily (base-load) capacity;

• System operator, the functions of which are currently performed by Kazakhstan’s company for management of power networks JSC “КЕGОС”;

• Power transmission organizations; • Power supply organizations that don’t have their own power networks and purchase electricity

on the wholesale market for its subsequent sale with a volume of no less than 1 MW of average daily (base-load) capacity;

• Operator of centralized trade in electricity (JSC “KOREM”).

2.16.2.1.2 Electricity market segments Kazakhstan’s wholesale electricity market comprises the following sub-markets:

• The market of decentralized sale-purchase of electricity, which functions on the basis of electricity sale-purchase agreements concluded by market participants under the prices and supply conditions established upon the agreement of the parties;

• The centralized sale market – electricity trade on the unified trade facility performed through auctions held to conclude the contracts: short-term (for each hour of forthcoming day) and forward (a year, month or week ahead);

• The balancing market of sale-purchase deviations from the agreed volume of electricity supply and consumption functioning in real time mode. Currently the balancing market is operating in simulation mode;

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• The market of system and ancillary services to sell the services required for securing the reliable operation of Kazakhstan’s unified energy system and compliance with electricity quality standards.

Relations between the subjects of wholesale market related to sale-purchase of electricity and electricity transmission are executed through:

• Electricity sale-purchase agreements between the sellers and the buyers concluded on decentralized market and deals closed on centralized trades;

• Agreement on transmission of electricity concluded by electricity buyer (in separate cases – by electricity seller) with system operator. In case of electricity transmission through regional level electricity networks, additional agreement on electricity transmission is concluded with power distribution companies.

Relations between the subjects of the retail market are executed through electricity sale-purchase agreement.

Electricity transmission services pertain to the sphere of natural monopolies and tariffs for such services are established by the respective regulatory authority in accordance with relevant laws and regulations.

2.16.2.1.3 Tariff setting principles Prior to the introduction of marginal tariffs in 2009, prices for power plants on the wholesale electricity market were formed on a competitive basis. Part of the electricity volume was sold through centralized trade facility of JSC “KOREM” functioning in line with the exchange principles, while another part of the electricity volume (over 80%) was sold based on bilateral contracts.83

Despite the competitive principle of pricing in electricity market, the existing market model failed to secure the formation of price signals for the attraction of investment to the industry and wholesale prices did not make it possible for the power plants to carry out modernization of existing assets.

Although the dynamics of maximum load over the last years has not reached the level of 1990, the depreciation of power industry assets, including key equipment of power plants mostly built in the Soviet Union times, predetermined the adoption of a number of regulatory documents governing the development electric power industry by the Kazakhstan Government.

To secure the attraction of investment in electric power industry, the pay-back of investments, as well as to speed up the construction and commissioning of new power generation capacities, the Resolution of Kazakhstan Government dated March 10, 2009 № 277 “On Approval of the Rules for Determining the Estimated Tariff and Approval of Marginal and Individual Tariffs” adopted in line with sub-clause (3-1) of Article 4 of the Law of the Republic of Kazakhstan dated July 9, 2004 “On Electric Power Industry”

83 Reference: JSC “KOREM” is the only centralized electricity trade facility in Central Asia region, which functions in line with the exchange principles.

155

introduced the mechanism of pricing for mid-term period (2009 - 2015) in the area of electricity generation:

1) Prices for electricity sold by power plants must secure the recovery of investment attracted for construction of new assets, as well as expansion, modernization, reconstruction, and technical re-equipment of existing assets.

2) Power plants can operate under three types of electricity tariffs: marginal, estimated and individual.

3) Marginal tariff is established separately for each group of power plants – annually and for seven years period. Power plants are divided into 13 groups formed depending on power plants’ type, installed capacity, type of fuel used for electricity generation, and remoteness from the location of the source of fuel.

4) Marginal tariff is established at a level, which secures the fulfillment by power plants of this group of investment obligations on creation of new assets, expansion, modernization, reconstruction and technical re-equipment of existing assets.

5) The Government, upon recommendation of the state agency supervising the electric power industry (hereinafter – the authorized agency), will approve the marginal electricity tariffs for a term of 7 years with annual breakdown.

6) If the level of marginal tariff does not make it possible for certain power plant to fulfill its investment obligations, such a power plant is entitled to operate under the estimated or individual tariff. These tariffs must be higher than the marginal tariffs.

7) An estimated electricity tariff is determined in the investment program’s feasibility study and is valid over the period of fulfillment of the investment obligations. It can be increased in case of agreement on making changes to design specifications and estimates.

The main power plants were divided into 13 groups depending on the type of power generation organizations, installed capacity, type of fuel used for electricity generation, and remoteness from the location of the source of fuel. Marginal tariffs until 2015 were established for each group.

The adopted legislation made it possible for suppliers to agree the tariffs with due account of the required funding for modernization. At these tariffs, power generation organizations sign the agreements and assume the accountability to implement the investment programs and timely commission of the modernized objects. Tariffs by group of power plants are presented in Table 2.1 below.

Table 2.1 - Marginal tariffs approved by the Resolution of the Government of the Republic of Kazakhstan № 392 dated March 15, 2009.

Group Base tarif

f

Marginal tariffs by years

2009 2010 2011 2012 2013 2014 2015

1st group (EGRES -1,2, ЕЭК) 3,5 3,6 4,68 5,6 6,5 7,3 8,0 8,8

2nd group (ZhGRES) 5,9 5,9 6,5 6,9 7,9 8,3 8,5 8,7 3rd group (Kar. combined heat and power plant/CHPP -1-3, Pavl CHPP -1,3, UK CHPP, Astana-Energiya CHPP

3,6 4,3 4,94 5,4 5,9 6,4 6,9 7,5

156

1,2)

4th group (Kar. Regional power plant/RPP -2, Pav. CHPP -2, Balhash, Zhezkazg. CHPP)

3,25 3,5 3,8 4,1 4,55 5,1 5,5 6,0

5th group (Petropavl. CHPP, Ridder. CHPP, Rudnens. CHPP) 3,0 3,6 4,1 4,8 5,45 6,25 7,15 8,05

6th group Sogr. CHPP, Kar. RPP -1, Stepn. CHPP 5,51 6,3 7,3 7,7 7,9 8,1 8,2 8,3

7th group (Shymk. CHPP -3, Atyrau, Aktobe, Zhamb. CHPP-4, Kzylord. CHPP)

4,7 4,9 5,4 5,9 6,3 6,7 7,0 7,3

8th group (Kentau CHPP, Tekel. CHPP, Shaht. CHPP, Ekib. CHPP) 3,8 4,5 4,95 5,4 5,98 6,6 7,2 7,5

9th group (Arkalyk CHPP, Kustan. CHPP, Uralskaya CHPP) 4,89 5,28 5,56 5,88 6,28 6,7 7,12 7,6

10th group “AlES” 4,38 5,74 6,74 7,1 7,4 7,8 8,2 8,6 11th group “MAEK” 7,23 7,23 7,23 7,23 7,23 7,23 7,23 7,83 12th group – gas turbine power plants (Akturbo, Zhanazholskaya) 4,1 5,3 5,8 6,4 7,0 7,7 8,4 8,8

13th group – hydro power plants (Bukhtarm, Ust-Kamenog., Shulbinskaya, Shardar.)

2,7 2,79 3,0 3,3 3,63 3,9 4,3 4,5

Following the introduction of marginal tariffs on electricity generation services in 2009, most of the electricity volume on the wholesale market is supplied based on mid-term or long-term bilateral contracts concluded between wholesale electricity sellers and wholesale electricity buyers.

Furthermore, following the introduction of marginal tariffs for power plants, the competitive principle of pricing on wholesale market was replaced by the regulation principle.

It is worth noting that the introduced principle of tariff regulation for power plants has disadvantages that hamper further development of Kazakhstan’s electric power industry, which was based on open market principles previously adopted and specified in the state program for restructuring and privatization of electric power industry objects:

1) The centralized electricity market that was designed to provide price signals to market participants is not liquid and does not perform its functions;

2) The balancing market, which even prior to the introduction marginal tariffs functioned in a simulation mode, does not operate due to the lack of price incentives for market participants to effectively plan their electricity consumption and generation.

3) The lack of an hourly automated system of electricity control and accounting (hereinafter - ASECA) does not make it possible to correctly distribute, among wholesale market participants, the intra-daily volume of consumption and, accordingly, intra-daily price fluctuations.

157

4) The current mechanism of marginal tariffs does not provide sufficient incentives for the construction of new generation capacities.

5) There is a lack of mechanism to guarantee investments in electricity generation;

6) Tariff regulation does not provide incentives to enhance the effectiveness of power producers.

7) There is a lack of well-developed mechanisms for the functioning of the wholesale electricity market after 2015;

8) Investment obligations behind the marginal tariffs have no mechanisms to control the fulfillment of investment obligations.

9) The system of marginal tariffs undermines the transparency of deals between the suppliers and consumers in the market of bilateral contracts due to the lack of principles and mechanisms for the distribution of wholesale electricity buyers among power plants that have a different level of marginal tariffs.

10) There are legal aspects concerning the introduction of marginal tariffs related to investment of consumers’ financial resources in the assets of power plants’ private owners. These financial resources could be attracted by power plants owners through the stock market, investment of own funds, shares, loans etc., while financial resources from consumers could be received through the prices for generated electricity.

11) The same problems also apply to the retail market.

158

The existing pricing principle is shown on the structural scheme of wholesale market (Fig. 2.2):

Fig. 2.2 – Existing pricing principle in the wholesale market

Each element of the structural scheme of the wholesale market, presented above, is analysed below with its corresponding number:

1- Power plants are divided into 13 groups. Marginal tariffs for these groups have been established by the Ministry of Energy.

2- KEGOC tariffs are regulated as for the subject of natural monopoly. They are regulated by KREM (КРЭМ) and ZK MNE RK (ЗК МНЭ РК).

3- Power distribution companies. Tariffs are regulated as for the subjects of natural monopoly. They are regulated by KREM (КРЭМ) and ZK MNE RK (ЗК МНЭ РК).

4- Power supply organizations. Tariffs of the 40 PSOs are regulated as dominants on the wholesale market. They are regulated by KREM (КРЭМ) and ZK MNE RK (ЗК МНЭ РК).

Sale tariff to consumers equals to the sum of the following components:

Тcons. = Тp.p. + ТKegoc + Тpdc + Тpso

It is obvious that all tariff components for consumers are formed under the regulated principles. These tariffs can be called “leftward” regulated tariffs (i.e. tariffs regulated “to the left” from consumers). The degree of competition is narrowed to the range of variation of supply markup of power supply organizations. Other power supply organizations, which are not dominants due to small volumes of electricity sale, do not escalate the competition.

It also worth noting that ultimate tariff for consumers depends on the tariffs established by the regulator based on consumption rate or zones of a day. They can be called “rightward” regulated tariffs (i.e. tariffs regulated “to the right” from consumers).

Consumers

Tcons.

Power plants

(13 groups)

Тp.p.

Power networks of JSC KEGOC

(subject of natural monopoly)

Power networks of PDCs (subject of

natural monopoly)

Тpdc

Power supply organizations PSO

(40 PSO – dominants)

Тpso

1 2 3 4

5 Tariff setting depending on

consumption rate or zones of a day

159

Tariffs established based on consumption rate or zones of a day must clearly correlate to the level of “leftward” regulated tariffs. For example, tariffs based on zones of a day must be associated with consumer groups’ contribution coefficient under maximum system load, as the introduction of tariffs based on zones of a day is primarily called to reduce capacity peak load by aligning overall power system load curve (Fig. 2.3).

It is also worth noting that the principle of tariff differentiation for consumers based on zones of a day is not clear, since fixed marginal tariffs have been established for power plants as if any power plant permanently operates under a flat and unvaried schedule throughout a year. The price of electricity generated by power plants and based on zones of a day must be different depending on the mode of power plants’ operation.

Tariffs’ level based on electricity consumption rate is also not linked with the level of “leftward” tariffs. At that level, the consumption rate for different regions and for the same types of consumers is different without taking into consideration climate conditions of the regions.

Fig. 2.3 - Contribution coefficient

2.16.2.1.4 KEGOC tariffs KEGOC tariffs have been approved by the Order N 295 dated September 17, 2013 of the former Agency of the Republic of Kazakhstan for regulation of natural monopolies (currently KREM and ZK MNE RK / КРЭМ и ЗК МНЭ РК):

1. On electricity transmission through power networks

Consumers Тcons. = Тp.p. + ТKegoc + Тpdc + Тpso

“Leftward” regulation

Tariffs based on consumption rate and zones of a day

“Rightward” regulation

Psystem

Psystem

max

Contribution coefficient = Pconsumers max/ Psystem max T (hours) T (hours)

Pconsumers

Pconsumers

max

160

• from Nov. 1, 2013 through Oct. 31, 2014 in the amount of 1,305 tenge/kWh (net of VAT); • from Nov. 1, 2014 through Oct. 31, 2015 in the amount of 1,469 tenge/kWh (net of VAT);

2. On technical dispatching of electricity output to the network and electricity consumption


3. On organizing balancing of electricity generation and consumption


Note: In some countries the functions of the system operator are performed by an independent system operator, who should not have any commercial interest in electricity market. This provision is stipulated in the respective legislation. JSC KEGOC as a large subject of the wholesale market for transmission of electricity and as natural monopolist, will always have a commercial interest in the market. This issue has been under discussion for many years in Kazakhstan.

2.16.2.1.5 Tariffs of power distribution companies

Tariffs of power distribution companies are also attributed to the subjects of natural monopoly. Currently, 40 power distribution companies are operating in Kazakhstan. Most of them are privatized and privately owned.

Since Jan. 1, 2013, the tariffs of power distribution companies have been regulated based on comparative analysis (benchmarking) method. Under this method, the tariffs are approved for the period of three years with possibility of annual adjustment. One of the main goals of this method is to enhance the effectiveness of power distribution companies. It is also worth noting that in practice, when approving the tariffs of power distribution companies, the reflection of all cost values in the tariff is often impossible due to the limitation of the increase of tariff for ultimate consumers, as well as due to the fact that the tariffs of power distribution companies are approved pursuant to “leftover” principle after the approval of tariffs for power generation companies.

However, in current practice the method of comparative analysis gives rise to a number of questions and doubts with regard to the expediency of its applications. Additional study and research are required.

Table 2.2- Approved tariffs of power distribution companies

N Region Name of power Type of Date of Tariff

161

distribution company

service tariff introductio

n

amount (tenge

/kWh) net of VAT

1 Aktyubinsk region LLC “Energosistema” Electricity

transmission and distribution

01.01.2014 3,8

2 Almaty region. TATEK (ТАТЭК) -//- 01.01.2014 4,13 3 Almaty JSC Alatau Zharyk -//- 01.01.2014 5,01

4 Akmala region. Akmolinskay power

distribution company (PDC)

-//- 01.01.2014 2,92

5 Astana JSC Astana PDC -//- 01.01.2014 2,54 6 Аkmolinskaya PDC JSC Kokshetauenergo 4,91 7 Atyrau region Atyrau Zharyk -//- 01.01.2014 4,22

8 East-Kazakhstan region EK PDC -//- 01.01.2014 3,17

9 Zhambyl region. LLC Zhambyl power networks -//- 01.01.2014 4,2

10 West-Kazakhstan region

JSC West-Kazakhstan PDC -//- 15.01.2014 3,68

11 Karaganda LLC Karagandy Zharyk -//- Since 01.01.2014 4,51

12 Karaganda region JSC Zhezkazgan PDC -//- Since 01.01.2014 1,97

13 Karaganda LLC Karaganda energy complex -//- Since

01.01.2014 4,06

14 Karaganda region LLC KREK -//- Since 01.01.2014 5,02

15 Kostanaj region EPK forfeit -//- Since 01.01.2014 4,225

16 Kyzylorda region Kyzylorda PDC -//- Since 01.01.2014 3,75

17 Mangistau region Aktausk power

network administration

-//- Since 01.01.2014 2,56

18 Pavlograd region Pavlograd PDC -//- Since 01.01.2014 3,306

19 North-Kazakhstan region SK PDC -//- Since

01.01.2014 3,416

20 South-Kazakhstan region Ontustik Zharyk -//- Since

01.01.2014 4,77

162

Electricity losses in the main power transmission lines are somewhat higher than in developed economies. It should be considered, however, that most of them are characterized by smaller distances of electricity transmission and higher market volume.

In contrast, Kazakhstan is characterized by long-distance networks between the key centers of electricity generation and consumption. Furthermore, Kazakhstan is characterized by distinctly continental climate, which has a negative impact on corona losses in 220 kV and higher voltage power networks. In connection therewith, taking into account the specified objective factors, normative technical losses in the national power network (main power transmission lines) at a level of about 6 – 7% are practically optimal for the networks of this class.

Currently, Kazakhstan’s distribution networks are characterized by quite substantial losses. Based on the results of 2013, the level of regional power distribution company losses varied from 4,76% to 18,6%. However, it should be taken into account that different levels of normative technical losses are explained by different volumes of transmitted energy, differences in the classes of voltage of transmission lines, length of power networks, number of substations, and topology of power networks.

2.16.2.1.6 Tariffs of power supply organizations

In order to control and regulate the activity of market subjects, the Agency keeps the State registry of market subjects that dominate the market or that have a monopoly status. As of January 20, 2014, the Registry includes 617 market subjects (without regard to duplication in sectors).

To date, 179 power supply organizations (hereinafter – PSO) have been registered. Of these, about 40 PSOs are subject to the regulation in accordance with the Law of the Republic of Kazakhstan “On Natural Monopolies and Regulated Markets”. Currently, the tariffs of power plants and power distribution companies are approved at a different time over a year, which results in the need to agree the PSO tariffs with Kazakhstan Agency for Regulation of Natural Monopolies several times over a year. In addition, the mechanism for determining the value of sales mark-up is calculated in accordance with pricing rules for regulated markets.

Table 2.3 - PSO tariffs by region

N Region PSO

Marginal effective tariffs,

tenge /kWh., including VAT

Note

1 Astana AstanaEnergoSbyt 14,19 1. This is not the full list of all 40 PSOs recorded in the registry of dominants.

2 Almaty region LLC “ZhetysuEnergoTrade”

16,69

LLC “AlmatyEnergoSbyt”

14,36

163

3 Mangistau region LLC “MAEK-KazAtomProm”

5,13 2. Depending on the consumption volume and day zone, incentive/ feed-in tariffs are established separately for legal entities and individuals proceeding from the approved marginal tariff. Tariffs effective in certain regions and depending on day zone and consumption volume are specified as an example*

4 Atyrau region LLC “AtyrauEnertgoSatu” 5,95 5 Aktyubinsk region LLC “AktobEnergo” 13,15 6 Karaganda region LLC “Karaganda

Zhylusbyt” 14,02

7 LCC “ZhezkazganEnergoSbyt”

13,83

8 LLC «Balhashenergo» 6,41 9 Kustanay region LLC

“KostanayEnergoTsentr” 17,57

10 Akmola region LLC “KokshetauEnergoTsentr”

17,25

11 Kyzylordy region LLC “DauletEnergo” 16,56 12 West-Kazakhstan region LLC

“BatysEnergoResursy” 16,31

13 East-Kazakhstan region LLC “VostokEnergoSbyt” 10,866 14 Pavlodar region LLC “PavlodarEnergoSbyt" 10,89 15 North-Kazakhstan

region LLC “SevKazEnergoSbyt” 12,56

16 Zhambyl region LLC “TarazEnergoSbyt” 14,19 17 South-Kazakhstan

region LLC “Ontustik-Zharyk” 16,46

18 LLC “Energopotok” 16,42

164

2.16.2.1.7 Tariffs depending on a day zone and consumption volume approved in certain regions

In Astana

The Astana Department of Kazakhstan Agency for Regulation of Natural Monopolies, having considered the notification from LLC “AstanaEnergoSbyt” on the increase of electricity prices, in accordance with sub-clause 2 of clause 3 of Article 7-2 of the Law of the Republic of Kazakhstan “On Natural Monopolies and Regulated Markets” approved the marginal tariff for electricity in the amount of 14,19 tenge per 1 kWh including VAT effective from Jan. 1, 2014 for the following consumer groups:

• The tariff for population – 11,84 tenge/kWh including VAT; • The tariff for other consumers – 15,28 tenge/kWh including VAT.

Based on the marginal price for the groups of consumers, the following differential electricity tariffs have been agreed to be used from Jan. 1, 2014: depending on the day zones and the volume of electricity consumption by individuals:

Differential electricity tariffs depending on the volume of electricity consumption by individuals (for population):

1. For individuals using electric cookers:

o Minimal tariff (up to 90 kWh) – 8,48 tenge including VAT per 1 kWh; o Average tariff (90-180 kWh) – 14,20 tenge including VAT per 1 kWh; o Maximum tariff (over 180 kWh) – 17,76 tenge including VAT per 1 kWh.

2. For individuals not using electric cookers:

o Minimal tariff (up to 70 kWh) – 8,55 tenge including VAT per 1 kWh; o Average tariff (70-140 kWh)- 14,20 tenge including VAT per 1 kWh; o Maximum tariff (over 140 kWh) – 17,76 tenge including VAT per 1 kWh.

Differential tariffs by day zones:

1. In case of 2-zone consumption accounting system: o Night zone tariff – 3,37 tenge including VAT per 1 kWh; o Day zone tariff –15,21 tenge including VAT per 1kWh.

2. In case of 3-zone consumption accounting system: o Night zone tariff – 4,36 tenge including VAT per 1 kWh; o Day zone tariff – 15,28 tenge including VAT per 1 kWh.; o Evening zone tariff – 32,08 tenge including VAT per 1 kWh.

165

Differential electricity tariffs depending on the volume of electricity consumption for private entrepreneurs-natural persons, attorneys, private notaries, and judicial enforcement agents, who use premises to carry out their professional activity:

1. For persons using electric cookers: Minimal tariff (up to 90 kWh kWh) – 9,12 tenge including VAT per 1 kWh; Average tariff (90-180 kWh) – 18,33 tenge including VAT per 1 kWh; Maximum tariff (over 180 kWh) – 22,92 tenge including VAT per 1 kWh. 2. For persons not using electric cookers:

Minimal tariff (до 70 kWh) – 11,03 tenge including VAT per 1 kWh;

Average tariff (70-140 kWh) – 18,33 tenge including VAT per 1 kWh;

Maximum tariff (over 140 kWh) – 22,92 tenge including VAT per 1 kWh.

Note: Differential electricity tariffs in Astana has been effective since July 1, 2009

In Almaty region

The Almaty region Department of Kazakhstan Agency for Regulation of Natural Monopolies, having considered the notification from LLC “ZhetysuEnergoTrade” on the increase of electricity prices has agreed the average sale electricity tariff in the amount of 16,69 tenge including VAT per 1 kWh with 6.11% increase compared to currently effective tariff (currently effective tariff - 15,67 tenge including VAT) to be introduced from Jan. 1, 2014.

Based on this average sales tariff, the following differential electricity tariffs have been approved: by day zones to be introduced from Jan. 1, 2014:

Differential tariffs by day zones:

Almaty region (operation zone of LLC “AlmatyEnergoSbyt”)

1) In case of 2-zone consumption accounting system:

Night zone tariff – 4,57 tenge including VAT per 1 kWh;

Day zone tariff –20,78 tenge including VAT per 1 kWh;

2) In case of 3-zone consumption accounting system: Night zone tariff – 4,57 tenge including VAT per 1 kWh; Day zone tariff – 16,20 tenge including VAT per 1 kWh; Evening zone tariff – 33,95 tenge including VAT per 1 kWh;

Taldykorgansky region (operation zone of LLC “ZhetysuEnergoTrade”)

3) In case of 2-zone consumption accounting system:

166

Night zone tariff – 5,34 tenge including VAT per 1 kWh;

Day zone tariff –19,36 tenge including VAT per 1 kWh;

Other – by the tariff for population (KSK, horticultural cooperative etc.) – 14,02 tenge including VAT per 1 kWh;

4) In case of 3-zone consumption accounting system: Night zone tariff – 7,37 tenge including VAT per 1 kWh; Day zone tariff – 19,33 tenge including VAT per 1 kWh; Evening zone tariff – 41,60 tenge including VAT per 1 kWh.

Differential electricity tariffs depending on the volume of electricity consumption by individuals:

Almaty region (operation zone of LLC “AlmatyEnergoSbyt”)

1) Tariffs for individuals not using electric cookers:

1st level (consumption volume – up to 70 kWh) – 14,36 tenge including VAT per 1 kWh;

- for individual pensioners, disabled people, veterans of the Great Patriotic War and equal-status persons (consumption volume – up to 100 kWh) – 14,36 tenge including VAT per 1 kWh;

2nd level (consumption volume – from 70 to 130 kWh) – 19,44 tenge including VAT per 1 kWh;

- for individual pensioners, disabled people, veterans of the Great Patriotic War and equal-status persons (consumption volume – from 100 to 130 kWh) – 19,44 tenge including VAT per 1 kWh;

3rd level (consumption volume – over 130 kWh) – 24,31 tenge including VAT per 1 kWh;

- for individual pensioners, disabled people, veterans of the Great Patriotic War and equal-status persons (consumption volume – over 130 кВтч.) – 24,31 tenge including VAT per 1 kWh;

2) Tariffs for individuals using electric cookers: 1st level (consumption volume – up to 80 kWh) – 14,36 tenge including VAT per 1 kWh;




3rd level (consumption volume – over 130 kWh) – 24,31 tenge including VAT per 1 kWh

- for individual pensioners, disabled people, veterans of the Great Patriotic War and equal-status persons (consumption volume – over 150 kWh) – 24,31 tenge including VAT per 1 kWh;

Taldykorgan region (operation zone of LLC “ZhetysuEnergoTrade”)

1) Tariffs for individuals not using electric cookers: 1st level (consumption volume – up to 70 kWh) – 13,93 tenge including VAT per 1 kWh;

http://www.multitran.ru/c/m.exe?t=2666055_1_2&s1=%F1%E0%E4%EE%E2%EE%E4%F7%E5%F1%EA%E8%E9%20%EA%EE%EE%EF%E5%F0%E0%F2%E8%E2

167




3rd level (consumption volume – over 130 kWh) – 21,02 tenge including VAT per 1 kWh;

- for individual pensioners, disabled people, veterans of the Great Patriotic War and equal-status persons (consumption volume – over 130 kWh) – 21,02 tenge including VAT per 1 kWh;

2) Tariffs for individuals using electric cookers: 1st level (consumption level – up to 80 kWh) – 14,00 tenge including VAT per 1 kWh;


2nd level (consumption level – from 80 to 150 kWh) – 16,82 tenge including VAT per 1 kWh;


3rd level (consumption level – over 130 kWh) – 21,02 tenge including VAT per 1 kWh

- for individual pensioners, disabled people, veterans of the Great Patriotic War and equal-status persons (consumption level – over 150 kWh) – 21,02 tenge including VAT per 1 kWh.

In Pavlodar region

Starting from Jan. 1, 2014, the average sales tariff for power supply services of LLC “PavlodarEnergoSbyt” will be 10,89 tenge/kWh:

o for individuals – 8,84 tenge/kWh; o for legal entities – 12,95 tenge/kWh.

Based on this sales tariff, the following differential electricity tariffs depending on the day zones and the volume of consumption by individuals have been approved to be introduced from Jan. 1, 2013:

Differential electricity tariffs for consumers of LLC “PavlodarEnergoSbyt” depending on the volume of electricity consumption by individuals

Indicators Tariffs, tenge/kWh Net of VAT Including VAT

1st level tariff for individuals using electric cookers (up to 110 kWh per person per month)

8,25 9,24

168

1st level tariff for individuals not using electric cookers (up to 90 kWh per person per month)

8,27 9,26

2nd level tariff: - from 110 to 180 kWh per person per month for those using electric cookers; - from 90 to 150 kWh per person per month for those not using electric cookers

10,61 11,88

3rd level tariff: - over 180 kWh per person per month for those using electric cookers; - over 150 kWh per person per month for those not using electric cookers

13,26 14,85

Differential electricity tariffs for the consumers of LLC “PavlodarEnergoSbyt” depending on the day zone

1) for consumers with connected capacity below 750 kVA using three-zone accounting system:

Indicators tenge/kWh, net of VAT

tenge/kWh, including VAT

Tariff for day consumption zone (MD) 12,95 14,50 Tariff for night consumption zone (N) 3,51 3,93 Tariff for evening consumption zone (E) 27,23 30,50

2) for household consumers using two-zone accounting system:

Indicators tenge/kWh, net of VAT

tenge/kWH, including VAT

Night zone and night consumption tariff (N) 3,40 2,69 Day zone and day consumption tariff (MDE) 11,24 12,59

Data on differential tariffs of PSOs from Kyzylorda region by day zones and depending on the volume of electricity consumption by individuals (net of VAT)

№ PSO name Curren

t tariff

1st level tariff up to

70 kWh

2nd level tariff

from 70 to 150 kWh

3rd level tariff over 150 kWh

Household consumers 3-zone system

Night Day Night

Day Evening

1. LLC “DauletEnergo

”

14,79 14,44 17,75 22,19 4,72 19,50 4,88 14,79

40,34

2. LLC “Zhieli-Zharygy”

14,02 13,44 16,82 21,03 5,29 20,25 5,29 14,02

30,62

169

3. Subsidiary LLC “Energoservis”

13,41 11,03 16,09 20,11 3,64 17,05 4,41 13,41

29,51

2.16.2.1.8 Generation and distribution of heat energy

Kazakhstan’s heat supply system, comprising the sources of heat energy, heat supply networks and heat consumers, is developed within the framework of implementation of a centralized heat supply approach.

Heat energy generation in Kazakhstan is carried out by 40 combined heat and power plants (CHPs), 28 large boiler-houses (heating capacity over 100 Gcal/h), and 5.6 thousand small boiler-houses (heating power below 100 Gcal/h).

Heat energy generation can be broken down by sources as follows:

1. Combined heat and power plants -45%

2. Large boiler-houses - 35%

3. Small boiler-houses - 20%

The length of heat-supply networks in Kazakhstan is 12 thous. km. two-pipe. Boiler-houses and heat supply networks are mostly state-owned.

There are two key issues that can be singled out in the segment of heat energy generation and transmission, namely:

1. Fixed assets depreciation of combined heat and power plants, boiler houses and heat transmission networks: The main problem of heat supply system in Kazakhstan is high depreciation resulting from

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ineffective management of the industry and consequent underinvestment. Existing depreciation of equipment leads to high losses during the transmission of heat energy through the heat transmission networks. Only 75% of produced heat energy reaches the ultimate consumer. In Baltic states this indicator is ca. 85 – 90% and in Scandinavian countries – up to 95%. Depreciation of heat generating equipment is estimated to be at a level of 70%.

2. Tariff setting system is aimed at preventing unjustified increase of tariffs for consumers: The services on heat generation, transmission, and distribution are attributed to the area of natural monopolies. Kazakhstan’s Agency for Regulation of Natural Monopolies (KARNM) approves the tariffs for organizations providing such services no more than once a year. It is worth noting that the activity of KARNM as the regulator in the area of natural monopolies is aimed at achieving the balance of interests between consumers and natural monopoly subjects. Within the framework of social and economic development efforts, KARNM continuously works on curbing inflation processes by observing the indicator of contribution to inflation (resulting from the change of tariffs for regulated services, including heat supply services). The main advantage of the existing heat energy tariff setting system is as follows: differential tariffs for consumers that have heat energy meters and those who do not have heat energy meters. This practice creates energy saving incentives for consumers. Heat tariffs for combined heat and power plants are regulated as for the subjects of natural monopoly, while marginal tariffs for electricity are established by the Ministry of Energy.

2.16.2.1.9 Development of renewable energy sources and their integration into the energy system of the Republic of Kazakhstan

Plans regarding construction of generation capacities with the use of alternative and renewable energy sources influence the development of heat power plants’ capacities. There are a number of conditions for the development of renewable energy sources in the Republic of Kazakhstan:

o The need to improve environmental situation and reduce the emission of pollutants. Kazakhstan ranks among the top three countries by CO2 emission intensity.

o The adopted concept on the transition of the Republic of Kazakhstan to a “green economy” requires that 30% of electricity is generated from alternative and renewable energy sources by 2030, and 50% – by 2050.

o The natural conditions of the Republic of Kazakhstan create opportunities for the development of electricity generation through the use of wind, solar, hydro and nuclear energy.

- Hydro potential of medium and large rivers constitutes 55 bln. kWh, and that of small rivers – 7,6 bln. kWh annually.

- Estimated solar energy potential is about 2,5 bln. kWh annually, and number of solar hours is estimated to be 2200–3000 out of 8760.

- Wind potential is estimated at 1820 bln. kWh annually.

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- Heat potential of geothermal waters constitutes 4,3 GW, however their use is mostly advisable for heat supply purposes.

Thus, the aggregate potential of renewable energy sources with regard to electricity generation is 1885 bln. kWh, and thermal potential – 4,3 GW. Generation on the basis of wind energy has the largest potential.

Kazakhstan also has a significant potential on the development of nuclear power generation. This is facilitated by the fact that Kazakhstan is the world leader in the area of uranium production, which totals about 20 thous. tons annually. Currently there are plans on the development of nuclear fuel production. Construction of a nuclear power plant in Kazakhstan has been planned long ago but the first steps in this direction were made in 2012. Industry development plans include the option for construction a nuclear power plant with capacity from 600 to 2 000 MW by 2030. However, at this stage Kazakhstan does not have the required technologies and will have to attract a foreign partner.

As a result, the installed capacity of power plants generating electricity through the use of alternative and renewable energy sources will increase from 2,7 GW in 2012 to 8 GW by 2030. At this stage the required measures have been taken in Kazakhstan to develop power generation through the use of renewable energy sources, including the formation of legal and regulatory framework and adoption of the action plan for the development of this segment.

2.16.2.2 Brief description of parallel operation with energy systems of neighboring countries (Russia, Kyrgyzstan, Uzbekistan)

2.16.2.2.1 Brief description of unified energy system of Central Asia The Unified Energy System of Central Asia (UES CA) was formed in 1970’s and comprised energy systems of Southern Kazakhstan, Kyrgyzstan, Tajikistan, Turkmenistan, and Uzbekistan and was part of the Unified Energy System of the USSR.

The structure of UES CA is shown in Fig. 3.1 below.

Fig. 3.1 - Structural scheme of UES CA

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Energy system relations among the sectorial state agencies of the Republic of Kazakhstan, Kyrgyzstan and Uzbekistan are partly related to the regulation of the use of Naryn river water resources. Supply of energy resources are governed by annual Intergovernmental agreements, which stipulate the volume of electricity export, import of natural gas, fuel oil and coal linked with water pass from Toktogulsky water reservoir. The first Intergovernmental agreement on the use of water and fuel and energy resources in the region was concluded in 1995.

It is a well-known argument that the social and economic stability in Central Asia greatly depends on the fair and reasonable access of the region’s countries to water and energy resources.

The presence of large trans-border rivers in the region, which include Syr Darya and Amu Darya (Afghanistan, Kazakhstan, Kyrgyzstan, Tajikistan, Turkmenistan, Uzbekistan), Chu and Talas (Kyrgyzstan and Kazakhstan), Tarim (Kyrgyzstan, Tajikistan, China), Ili (China, Kazakhstan), Irtysh (China, Kazakhstan, Russia), Ural, Ishim, Tobol, (Kazakhstan, Russia) requires the development of a common legal framework for distribution of water energy resources, justification and agreement of large projects for construction of hydropower objects in the region, refinement of investment and environmental legislation, methods for assessment of system risks, and development of new decision making models.

Kazakhstan southern zone

Northern Kyrgyzstan

Turkmenistan Southern

Kyrgyzstan

Southern Tajikistan

Northern Tajikistan

Surhandarinsky region

Kazakhstan northern zone

Uzbekistan

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Interstate institutes for regional cooperation have been established to address environmental and water resources problems. The most reputable of them are the International Fund for Rehabilitation of the Aral Sea and the Interstate Commission for Coordination of Water Management. The framework agreement on the use of water energy resources of Syr Darya basin concluded in 1998 between Kazakhstan, Uzbekistan, Kyrgyzstan and Tajikistan stipulated the creation of compensation mechanisms for regulating the operating mode of Toktogulsky water reservoir and establishment of inter-state water energy consortium. However, this agreement failed to achieve its primary objective – securing the sustainable management of operating mode of Naryn - Syr Darya chain of hydro power plants in the interests of all participating states. Within the framework of EurAzEC, the roadmap on the establishment of mechanism for interaction among EurAzEC member-states during the regulation of water energy issues has been developed. However, this roadmap is still to be implemented.

Previously, the distribution of water energy resources was performed within a single state (USSR) and on a different economic basis, but currently other approaches are required. Currently, the urgency for addressing water energy problems is obvious judging by the number of publications in the press and Internet resources, which often present adverse opinions of experts from Central Asia’s countries.

Major contradictions result from the conflicting interests of the “upper” countries of water runoff formation in Central Asia (Tajikistan, Kyrgyzstan) with the interests of the three other “lower” countries of the region (Kazakhstan, Turkmenistan, Uzbekistan), which are located in the lower reaches of the Amu Darya and Syr Darya and are the major water consumers.

Being rich in energy resources, Central Asia is characterized by the extremely uneven distribution of these resources across the region’s territory. The “lower” countries are rich in oil and gas, while the “upper” countries are practically deprived of such resources. However, the “upper” countries control the origins of rivers and have at their disposal a no less important (and given the dry climate of Central Asia - even more important) resource – the water. They strive to increase their hydro power potential through the construction of new hydro power plants justifying it by the lack of other energy resources (except water), while the countries of Amu Darya and Syr Darya (lower) have apprehensions that the construction of such power plants will have a negative impact on the development of their agriculture, environmental situation, and undermine the safety of their water development facilities.

Advocates of the construction of new hydro power capacities in Central Asia believe that, in the case of an agreed and coordinated water energy policy, the introduction of renewable energy sources in the region (in light of the global trends towards the increase of prices for organic energy resources and given their limited deposits) will enhance the energy safety in the region and secure sustainable economic development for all Central Asia countries.

Central Asia countries occupy a territory of 4 mln. sq. km. and have a population of about 72 mln. people. The density of the electricity market (just as that of the entire economy) is not high. The costs for the generation of electricity and heat energy irrespective of the country of large power plants’ location (large hydro power plants, combined heat and power plants, regional power plants) are similar. The cost factor of the power supply network is very high and in some cases it is comparable with the unit costs of power plants. Given the global trends towards the increase of prices for energy resource and price fluctuations, the unit cost of fuel is growing.

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The entire infrastructure of Central Asia’s power industry was established in the times of the USSR. Current depreciation of energy infrastructure is 60-70% and countries keep “eating away” the strength reserve of old soviet-times energy equipment. Reconstruction and modernization of fixed assets in the power industry require large financial resources.

Based on the international economic research, the period of investment for such large infrastructures in sectors such as energy and transport (which serve as the foundation for stability and sustainable development of the entire economy of any state) associate with the period of economic cycles.

In other words, it is possible to say that, in prospect, there will be no cheap electricity in Central Asia. It is also worth noting that the countries in the region do not produce the primary energy equipment. It is imported from foreign countries thus leading to the increase of electricity prices. There are issues that deserve a separate research: securing of power industry with highly qualified specialists (one of the key elements for sustainability of power industry); determining of optimal structure for power industry management under market conditions, etc.

Due to different economic and social conditions, as well as different pace of power industry reform, a significant mismatch in prices and tariffs is currently observed in Central Asia countries. This is one of the barriers for resolution of hydro energy problems and issues related to reliable functioning of electric power industry in the region.

Correspondence of tariffs and prices for any product to the costs for the production of such product is the key principle of financial balance for sustainable industry functioning and development. A breach of this principle, accordingly, disrupts the sustainability of the industry’s functioning and development. The problem of compliance with this principle is one of the key problems inherent to all former soviet states. Therefore, trying to resolve the problems of the power industry within a separate Central Asia state and without integration processes is an extremely difficult task. The issue is further aggravated by the fact that the power industry is a high-cost, capital intensive, slow-response and sophisticated industry, has a long investment cycle, is closely related to other systems, and its stability has a significant impact on the entire economic stability of a country.

In Kyrgyzstan, which is called the “water tower” of Central Asia, the major flow of the Syr Darya river is formed. Syr Darya is the river for Naryn-Syr Darya chain of hydro power plants (Fig. 3.1), including a large Toktogul water reservoir and Toktogul hydro power plant. Water energy balance of the region greatly depends on the operation mode of these power plants.

2.16.2.2.2 Description water resources and water management structure

2.16.2.2.2.1 Water Resources Water resources available for use in the Aral Sea basin are formed in the surface and underground sources, mainly in the basins of the region's two main rivers - Amu Darya and Syr Darya. Independent hydrographic basins (gravitating towards Amu Darya and Syr Darya rivers) form the rivers Qashqa Darya, Zerafshan, Murghab, Tedjen, Chu, Talas, that many centuries ago lost contact with the main rivers.

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By the conditions of formation and transformation of overland flow/runoff in the region, its territory can be divided into three main areas:

• flow formation zone (catchment basin in the mountainous areas); • transit and flow dispersion zone; and • delta zones.

Numerous glaciers are located in the mountain systems of Central Asia, they give rise to almost all major rivers of the region, whose waters are used extensively in the national economy. Most of the glaciers are located in the territories of the Republic of Tajikistan and the Kyrgyz Republic.

In general, the water resources of the Aral Sea basin are formed unevenly in different countries of the region. Thus, within the boundaries of Tajikistan, about 55.4% of the total runoff of the Aral Sea basin is formed, in the Kyrgyz Republic - 25.3%, in Uzbekistan - 7.6%, in Kazakhstan - 3.9%, in Turkmenistan - 2.4%, in the territory of Afghanistan and other countries, the share of which is very small (China and Pakistan) - about 5.4%. In general, the surface waters of major rivers and their major tributaries in the Aral Sea basin are trans-border waters.

Syr Darya

Syr Darya is the second in water content and the first longest river in Central Asia. From the origins of the Naryn, its length is 3,019 km, and the basin area is 219,000 km2. The origins of Syr Darya lie in the Central (internal) Tian Shan. After confluence of Naryn with Kara Darya, the river is called Syr Darya. The river alimentation is glacial and snow, with a predominance of the latter. Hydrological regime is characterized with spring and summer flood, which starts in April. The biggest flow is in June. The main Syr Darya flow is formed in the territory of the Kyrgyz Republic. A small part of the headwaters is located in the territory of China. Then, Syr Darya crosses Uzbekistan and Tajikistan and flows into the Aral Sea in Kazakhstan.

The assessment of the mean annual flow of rivers, according to hydrometric observations, is characterized by the following values: for the rivers of Syr Darya basin – 37,203 million m3/year; for the rivers of Amu Darya basin (including stagnant rivers of Afghanistan, Iran and Zerafshan) – 79,28 million m3/year. Thus, the total mean annual resources of surface (river) waters in the Aral Sea basin constitute 116,483 million m3/year.

Annual amount of water resources, due to fluctuations in water content, varies from dry years (95% probability) to the high-water years (5% probability) within the following limits: for Amu Darya - from 58.6 km3 to 109.9 km3, for Syr Darya – from 23.5 km³ to 51.1 km³.

Fig.3.2 Scheme of Naryn-Syr Darya HPP Chain

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Aral Sea

Charvak reservoir

Farkhad diversion PP

Р=126 mWt

Qusf=5.2 bn. m3

__________________

Andijan reservoir

Qusf=19.5 bn.m3

Toktogul HPP

Р=1200 mWt

Kambaratin HPPs -1,2,3

Kurpsay HPP, Р=800 mWt,

Qusf=0.37 bn. m3

Tashkumyr HPP, Р=450 mWt Qusf=0.144 bn. m3

Qsp =5 0 m3/mWt

Shamaldysay HPP, Р=240 mWt

Qusf =0.041 bn. m3

Aral

Qusf=5 5 bn m3

Charvak reservoir

Sher Darya HPP Р=100 mWt

f k 3

Kayrakkum HPP, Р=126 mWt

Vusf=2.7 km3

Qusf =3 4 bn m3

V usf=1.75 km3

Uchkurgan HPP, Р=180 mWt

Qusf =0.015 bn. m3

Kyzyl Kum reg.

Arnasay

Chirchiq

Syr Darya

Kara Darya

Yuzhnogolodostep. channel

Syr Darya

Naryn

UZBEKISTAN TAJIKISTAN

UZBEKISTAN

UZBEKISTAN

KYRGYZSTAN

KAZAKHSTAN

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2.16.2.2.2.2 Syr Darya River Basin Water Management Structure The main tasks of the water basin system are flow control, water supply to water users through the irrigation system and water supply system, and environmental protection. Runoff control in the water management system of Syr Darya is conducted in 13 reservoirs with a total capacity of 35.0 km3 and useful volume of 27 km3.

Five main reservoirs are located on Syr Darya and its tributaries:

• Toktogul reservoir: total volume – 19.5 km3, including useful capacity of 14 km3. • Andijan reservoir: total volume – 1.9 km3, including useful capacity of 1.75 km3. • Kayrakkum reservoir: total volume – 4.03 km3, including useful capacity of 2.55 km. • Charvak reservoir: total volume – 2.05 km3, including useful capacity of 1.6 km3. • Chardara reservoir: total volume – 5.4 km3, including useful capacity of 4.4 km3.

Irrigated Area in Syr Darya Basin, Thousand Hectares

Country Irrigated area Total Local sources Trans-border sources

Kazakhstan 778.02 288.02 490.0 Kyrgyzstan 460.09 256.09 204.0 Tajikistan 268.32 93.32 175.0

Uzbekistan 2139.3 1093.3 1046.0 Total 3645.73 1730.73 1915.0

Many international organizations are currently taking part in the study of water and energy problems in Central Asia.

Under the auspices of the United Nations Development Program (UNDP), the report "Regional Risk Assessment in Central Asia" was developed. The report was focused on finding the most effective ways of joint international aid to the poorest countries of the region in the conditions of growing threats in the area of water, energy and food security in Central Asia.

The report noted that "today, already half the irrigated land in some regions of Central Asia is turned into salt marshes and swamps”.

The common energy system and the joint water use in Central Asia have gone into oblivion together with the Soviet Union. Turkmenistan, Uzbekistan and Kazakhstan that used to deliver fuel in those days to Tajikistan and Kyrgyzstan for electricity and heat generation, today, dispose of oil and gas at their own discretion, increasing transit tariffs and export prices for Tajikistan and Kyrgyzstan.

Due to political reasons, Tajikistan currently operates in isolation from the Central Asia United Power System. In summer, during high-water period, due to a locked-in capacity, the country is forced to make

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idle water discharge from the Nurek hydropower plant reservoir. The volume of discharged water is estimated as 6 billion kWh. In winter, due to the deficiency, restrictions for the consumers are introduced. In this situation, Tajikistan public authorities are taking numerous measures to encourage investments in the energy sector. A new Dushanbe combined heat and power plant (CHP) has been put into operation. Negotiations on construction of the second CHP are being conducted, a 500 kV North-South line has been constructed, with the prospect of its connection to CAPS through Kyrgyzstan. Work with involvement of international experts is being done to validate the construction of Rogun hydro power plant and export of electricity to Afghanistan and Pakistan under the regional CASA-1000 projects.

Kyrgyzstan is currently conducting negotiations on the construction of several hydro power plants by RosHydro company.

According to the results of the 5th Session of the Kyrgyz-Kazakh Intergovernmental Council held on 13 October in Astana, it was agreed on additional supply of electricity to Kyrgyzstan in autumn-winter period of 2014-2015. The Parties will ensure parallel operation of power systems of Kyrgyzstan and Kazakhstan in this period.

In Kyrgyzstan, hearings on the tariff increases were held.

In 2013, non-contractual out-feeds by the energy system of Uzbekistan continued, which leads to emergencies in CA UES (Central Asia Unified Energy System). This especially affects stability of the power system of Kazakhstan. Exceeding the maximum allowable cross-flows of Kazakhstan North-South transit triggers the emergency control automatics, disconnects the consumers of the Southern region. Non-contractual volumes of Uzbekistan in 2013 amounted to 405.5 million kWh.

Today, observance of operational discipline, observance of contractual obligations in cross-border trading in Central Asia is a hot topic and requires creation of mechanisms based on a legal foundation.

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