Russian Electricity Reform 2013 Update

Russian Electricity Reform 2013 Update:

Laying an Efficient and Competitive Foundation for Innovation and Modernisation

Douglas Cooke

2012 The views expressed in this IEA Insights paper do not necessarily reflect the views or policy of the International Energy Agency (IEA) Secretariat or of its individual member countries. This paper is a work in progress and/or is produced in parallel with or contributing to other IEA work or formal publication; comments are welcome, directed to

OECD/IEA [email protected].

The International Energy Agency (IEA), an autonomous agency, was established in November 1974. Its primary mandate was – and is – two-fold: to promote energy security amongst its member countries through collective response to physical disruptions in oil supply, and provide authoritative research and analysis on ways to ensure reliable, affordable and clean energy for its 28 member countries and beyond. The IEA carries out a comprehensive programme of energy co-operation among its member countries, each of which is obliged to hold oil stocks equivalent to 90 days of its net imports. The Agency’s aims include the following objectives: n Secure member countries’ access to reliable and ample supplies of all forms of energy; in particular, through maintaining effective emergency response capabilities in case of oil supply disruptions. n Promote sustainable energy policies that spur economic growth and environmental protection in a global context – particularly in terms of reducing greenhouse-gas emissions that contribute to climate change. n Improve transparency of international markets through collection and analysis of energy data. n Support global collaboration on energy technology to secure future energy supplies and mitigate their environmental impact, including through improved energy efficiency and development and deployment of low-carbon technologies. n Find solutions to global energy challenges through engagement and dialogue with non-member countries, industry, international organisations and other stakeholders. IEA member countries: Australia Austria Belgium Canada Czech Republic Denmark Finland France Germany Greece Hungary Ireland Italy Japan Korea (Republic of) Luxembourg Netherlands New Zealand Norway Poland Portugal Slovak Republic © OECD/IEA, 2013 Spain International Energy Agency Sweden 9 rue de la Fédération 75739 Paris Cedex 15, France Switzerland Turkey www.iea.org United Kingdom Please note that this publication United States is subject to specific restrictions that limit its use and distribution. The European Commission The terms and conditions are available online at also participates in http://www.iea.org/termsandconditionsuseandcopyright/ the work of the IEA. © OECD/IEA 2013 Russian Electricity Reform 2013 Update: Laying an Efficient and Competitive Foundation for Innovation and Modernisation

Table of Contents

Acknowledgements ...... 3 Executive Summary ...... 4 1. Introduction ...... 12 Page | 1 2. Wholesale Market Development ...... 13 Wholesale market structure ...... 13 Wholesale market arrangements ...... 26 Wholesale energy markets ...... 28 Wholesale capacity markets ...... 35 Toward a long‐term wholesale market model ...... 42 Cost‐reflective pricing ...... 45 Financial markets ...... 47 Transparency ...... 50 3. Retail Market Development ...... 56 Retail market structure ...... 57 Retail market arrangements ...... 64 Key retail market processes and practices ...... 66 Access to information ...... 67 Consumer awareness and engagement ...... 69 Enabling technologies ...... 73 Extending customer choice ...... 76 Cost‐reflective end‐user pricing ...... 77 Unwinding cross‐subsidies ...... 80 Reforming end‐user price controls ...... 88 Acronyms, Abbreviations and Units of Measure ...... 95 References ...... 97

List of Tables Table 1 • Russian wholesale electricity market structure indicators ...... 14 Table 2 • Wholesale market structure analysis for price zone one ...... 17 Table 3 • Russian electricity generator ownership trends: 2008‐2011 ...... 20 Table 4 • Average market shares of retail suppliers in 2010 ...... 58 Table 5 • Retail market structure of the Volga federal district ‐ 2007 & 2010 ...... 59

List of Figures Figure 1 • National concentration comparisons: market share of the three largest generators ... 16 Figure 2 • National concentration comparisons: Herfindahl‐Hirschman capacity indices in 2010 16 Figure 3 • 2012 trading zones for existing generating capacity ...... 27 Figure 4 • Wholesale electricity spot prices and traded volumes 2008 and 2009 ...... 28 Figure 5 • Potential wholesale electricity capacity trading zones by 2020 ...... 37

Russian Electricity Reform 2013 Update: © OECD/IEA 2013 Laying an Efficient and Competitive Foundation for Innovation and Modernisation

Figure 6 • Peak demand and generation growth in the Australian national electricity market: 1998‐2011 ...... 42 Figure 7 • Weekly volume‐weighted average wholesale spot prices for key regions in the Australian national electricity market: 2007‐2012...... 44 Figure 8 • Volume of trade in Nordic electricity markets: 1998‐2011 ...... 49 Page | 2 Figure 9 • Organisation and content of the Texas electric choice program website ...... 72 Figure 10 • Peak usage reductions in response real time prices: impact of enabling technologies . 74 Figure 11 • Russian end‐user electricity price trends by customer class: 2001‐12 ...... 78 Figure 12 • International comparison of residential end‐user electricity prices in 2011 ...... 78 Figure 13 • International comparison of industrial end‐user electricity prices in 2011 ...... 79 Figure 14 • Growth in Russian household income and electricity costs: 2001‐2011 ...... 81 Figure 15 • Key features of an effective tariff rebalancing program ...... 82 Figure 16 • Residential demand reductions in response to peak prices ...... 90 Figure 17 • Impact on residential charges of moving from flat rate to time‐varying products ..... 92

List of Boxes Box 1 • An overview of Electricité de France’s virtual power plant auction program ...... 23 Box 2 • Competition supervision case study – InterRAO acquisition of OGK‐3 ...... 25 Box 3 • An overview of capacity mechanisms deployed among IEA countries ...... 39 Box 4 • An overview of the Swedish strategic capacity reserve model ...... 41 Box 5 • Key features of the Australian national electricity market ...... 43 Box 6 • An overview of the Nord Pool power exchange ...... 48 Box 7 • European regulators' group for electricity and gas guidelines to improve electricity market transparency ...... 52 Box 8 • An overview ofe th AEMO supply‐demand calculator ...... 54 Box 9 • Council of European energy regulators recommendations on good practice switching and billing processes ...... 67 Box 10 • Spanish standards for sharing retail‐level electricity information ...... 69

Acknowledgements

The project manager and author of this report is Douglas Cooke, Senior Counsellor, Energy Markets and Security Directorate. The author wishes to especially thank Isabel Murray and Alexander Antonyuk for their exceptional contributions to this project, especially their expert research assistance and logistical support which proved vital in bringing this project to a Page | 3 successful conclusion. Thanks also to Steven MacMillan for his input in relation to the Australian and Nordic markets and on capacity mechanisms in IEA member countries. The project and final report benefited greatly from comments received from IEA member countries through the IEA Standing Group on Long‐term Cooperation and from extensive consultations during 2011 and 2012 with senior executives and experts representing a range of Russian stakeholders including representatives from the Russian Federation, federal regulators, the wholesale market operator, the system operator, industry participants, major users, finance and industry analysts, academics and research institutions, notably:  Russian Ministry of Energy;  RosAtom;  Russian Ministry of Economy;  Lukoil;  Federal Antimonopoly Service of Russia;  EOS Russia;  Federal Tariff Service of Russia;  RusAl;  Russian Market Council;  Sberbank Investment Research;  System Operator of the United Power  Carana Limited; System of Russia;  Russian Energy Forecasting Agency (APBE);  Federal Grid Company; and  Fortum Russia;  Energy Research Institute of the Russian  ENEL Russia; Academy of Sciences. Special thanks go to the Russian Market Council for hosting an international conference with the IEA in December 2012 titled Russian Energy Market: the Present and the Future where the preliminary findings from this report were presented and discussed with Russian stakeholders and representatives of the Council of European Energy Regulators and Eurelectric. The IEA is grateful to the Fortum Corporation for providing a voluntary contribution which made this conference and final round of consultations possible. The report also benefited from submissions received through a public consultation process conducted during the second quarter of 2012 and from comments received from OECD and IEA colleagues, notably John Davies and Dennis Volk. Special thanks also to Keisuke Sadamori, Director, Energy Markets and Security, whose strong support ensured the publication of this report. Thanks also to Muriel Custodio, Bertrand Sadin, Angela Gosmann and Janet Pape for their editorial contributions and production assistance.

Russian Electricity Reform 2013 Update: © OECD/IEA 2013 Laying an Efficient and Competitive Foundation for Innovation and Modernisation

Executive Summary

Russia is in the process of one of the most ambitious electricity reform programs ever undertaken. The reform is a key policy priority and crucial for Russia, with the potential to facilitate innovation and modernisation that can transform the sector into a key driver of longer‐ Page | 4 term economic growth and prosperity. Achievements to date have been impressive by international standards, however the outcome remains uncertain. Electricity reform is entering another critical phase in Russia which has prompted the IEA to update its 2005 work. This report examines the key remaining challenges affecting the development of competitive wholesale and retail markets including: market structure, market design, pricing, investment and related regulation. The report draws extensively on the experience of IEA member countries and on views expressed during consultations with key Russian stakeholders including government officials, regulators, the wholesale market operator, the system operator, industry participants, major users, finance and industry analysts, academics and research institutions.

Wholesale market structure Liberalisation experience indicates that the strength and dynamism of competition in wholesale electricity markets is greatly affected by the market structure, with a less concentrated market structure more likely to deliver efficient and innovative outcomes. IEA analysis of Russia’s current wholesale market structure suggests relatively diversified ownership consistent with a moderately concentrated market structure on a national basis. However, effective levels of concentration are likely to be much higher given that up to two‐thirds of the generating capacity serving the wholesale market is subject to priority dispatch and therefore does not directly participate in competitive spot market price formation and merit order dispatch. In addition, network congestion can lead to fragmentation of the national market into smaller regional markets, especially during peak periods or at other times when the power system is under stress. The radial nature of much of the transmission system may serve to magnify the impact of congestion. Congestion and technical network limitations are already adversely affecting the integrity of the Russian wholesale market, as evidenced in the structure of the wholesale capacity market which incorporated 27 separate trading zones in 2012. Analysis of the potential impact of priority dispatch and congestion on the underlying competitiveness of the wholesale market structure in price zone one spanning European Russia and the Urals, using the five integrated electricity systems within price zone one as a proxy to simulate the potential impact of congestion, suggests that priority dispatch and congestion could significantly increase concentration at a wholesale level, with some regions recording levels of concentration consistent with the presence of substantial potential market power. Ultimately, a competitive wholesale market structure is best achieved through diversity of ownership. Although the very successful 2008 privatisation brought several new entrants and greater diversity of generation ownership, government‐owned enterprises continue to own or control over 60% of total generation assets. A trend toward consolidation of ownership within government‐owned entities is also beginning to emerge. Consolidation into government ownership after unbundling and privatisation is an unusual development based on IEA experience and may have implications for competitive neutrality and efficient market operation and development in the longer term. Government ownership is not a problem of itself, so long as government‐owned enterprises are operated on an arm’s‐length basis subject to normal corporate governance requirements,

© OECD/IEA 2013 Russian Electricity Reform 2013 Update: Laying an Efficient and Competitive Foundation for Innovation and Modernisation regulation and commercial practices. Several stakeholders suggested that scope may exist to improve the operational and investment performance of government‐owned enterprises. IEA experience suggests that increasing the level and diversity of private ownership can result in substantial efficiency improvements. Considerable scope exists for the Government to improve diversity of ownership and wholesale competition through further divestment, or through other initiatives such as virtual power plants Page | 5 or similar mechanisms to sell rights to the output of publicly owned generators. Virtual power plants may provide a practical option for assets that may prove difficult to privatise for wider public policy reasons, like nuclear and some hydro facilities. Beyond this, there is always the potential to strengthen market integration through network augmentation and development. IEA understands that the Federal Grid Company has embarked on a major network development program that will help to substantially improve regional power flows by the end of the decade. IEA electricity markets have generally experienced considerable rationalisation post reform, involving horizontal and vertical re‐integration both within the electricity value chain and into upstream fuel supply chains. Complex ownership structures have emerged including considerable cross‐ownership and the creation of mixed technology portfolios that have the potential to weaken transparency and dilute competition and efficient market development. Similar structures are beginning to emerge in Russia. Effective competition regulation has a crucial role to play in maintaining a competitive wholesale market structure and efficient outcomes. The Federal Antimonopoly Service (FAS) has performed well to date and will need to provide objective and consistent supervision to ensure a competitive market structure is maintained over time.

Wholesale market arrangements Russian wholesale electricity markets incorporate separate markets for energy and capacity. 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 market. The competitive wholesale spot market is one of the most successful components of the electricity reforms implemented to date. Energy prices have generally reflected movements in underlying supply‐demand fundamentals and short‐run marginal production costs driven largely by changes in upstream fuel costs. This was particularly evident in the wake of the Global Financial Crisis and economic slowdown in 2009. Notwithstanding this positive performance, opportunities may exist to improve the efficiency and robustness of spot price formation by increasing the underlying competitiveness of the spot market. Several options could be considered in this context including:  Improving intra‐regional market integration: This has the potential to improve competitive spot price formation while helping to strengthen market flexibility, resilience and reliability at least cost.  Strengthening transparency and competition in upstream fuel supply markets: Access to competitively priced fuel on fair and reasonable terms is a key pre‐requisite for minimising wholesale electricity prices over the longer‐term. Several possibilities exist to help improve transparency, flexibility and competitiveness of upstream fuel markets including: strengthening third party access arrangements, possibly including the introduction of regulated reference tariff services to support more informed and effective negotiations; improving transparency and access to spare pipeline capacity for third parties; and reopening the wholesale gas trading exchange, with sufficient liquidity and depth to support more efficient price formation and risk management.

Russian Electricity Reform 2013 Update: © OECD/IEA 2013 Laying an Efficient and Competitive Foundation for Innovation and Modernisation

 Reviewing priority dispatch bidding restrictions, especially for reservoir hydro plant: Nearly two‐thirds of generating capacity is subject to priority dispatch which has the potential to greatly reduce the depth of competitive bidding and adversely affect efficient spot price formation. Russian policymakers may wish to consider the potential for extending bidding for dispatch to some or all of this capacity, especially reservoir hydro plant which can have a Page | 6 critical role in promoting efficient marginal price formation due to the technical flexibility of this technology.  Encouraging more efficient combined heat and power (CHP) participation in wholesale electricity markets: CHP is a key resource in the Russian electricity system, representing around one‐third of total generating capacity. Much of the fleet is old and offers considerable scope for efficient modernization. However, municipal interests and regional regulation of the heating sector has distorted incentives for efficient operation and development of CHP facilities. A reform package is being implemented which has the potential to begin to address the key distortions. Russian policymakers and regulators are encouraged to move quickly to develop and implement the remaining rules and regulations required to operationalize heating sector reforms, and to do so in a way that encourages more efficient CHP participation in the electricity and heating sectors, and timely and efficient modernisation of CHP facilities.  Improving system operation: Transparent and objective system operation is needed to deliver efficient dispatch and network operation that supports competitive and efficient wholesale market outcomes. Russian policymakers, regulators and system operators could consider ways to extend market‐based procurement of ancillary services to help reduce costs and improve market efficiency. Consideration could also be given to reviewing the power system management practices, modelling and situational awareness capabilities of system operators, with a view to upgrading system operation capabilities as required, to help improve power system operation and performance at least cost. A transitional capacity mechanism has also been introduced including a series of legally binding bilateral contractual obligations to secure incremental capacity investment requirements up to 2018 and a capacity obligation component to provide a return on capital for existing capacity. By contrast, the experience to date with the wholesale capacity mechanism has revealed some significant shortcomings. According to various stakeholders, the bilateral contractual mechanism for new generating capacity has proven to be expensive, relatively inflexible and reduces the scope for competitive new entry, while the capacity mechanism for existing generation under‐ rewards some plant and may reduce incentives for innovative modernisation of existing facilities. Some large users suggested that the capacity obligation had restricted their ability to exercise choice. In our view it can be argued that the transitional arrangements introduce a form of central planning that is ultimately incompatible with delivering the policy goal of developing efficient, innovative and dynamic electricity markets reflecting the commercial choices of many individual buyers and sellers. Russian policymakers are aware of the shortcomings of the transitional capacity mechanism and are developing options to increase its transparency and competitiveness. Although work is progressing to address many of these issues, it is possible that some may not be fully resolved before the next major increment of generating capacity is required. In the interim, there appear to be several opportunities to refine existing arrangements including:  further integrating trading zones for existing capacity to strengthen underlying competition and reduce the need for regulated pricing intervention;

 strengthening market‐based arrangements for securing capacity using bilateral contractual mechanisms, possibly supported by longer‐term forward capacity auctions and the development of secondary capacity trading arrangements; and  removing undue legal and regulatory barriers to more innovative investment responses, including renovation, refurbishment and retirements, driven by independent decentralised decision ‐making. Page | 7

Toward a long‐term wholesale market model The Government is examining options for securing investment beyond 2018, with the intention of moving to a more market‐based approach that will deliver more efficiently timed, sized and well located investment, operational and end‐use outcomes at least cost. Achieving these outcomes will involve moving from the current centrally planned and closely regulated approach towards more liberalised arrangements where generation investments are undertaken by independent decentralised decision‐makers in response to incentives created by cost‐reflective and competitively determined prices. Options under consideration include replacing the current energy and capacity model with an energy‐only wholesale market model. IEA experience suggests that a well‐functioning energy‐only market provides an effective means of delivering the efficiently timed, sized and well located generation investment needed to develop a competitive, dynamic and innovative electricity sector at least cost. However, there are some key pre‐conditions that need to be met for energy‐only markets to deliver the desired outcome including:  A competitive wholesale market structure needs to be in place to ensure market‐based incentives and disciplines are sufficient to elicit timely, efficient and innovative responses, as discussed previously;  Prices need to be cost‐reflective through the value chain to create strong incentives for efficient investment, operation and end‐use, with price regulation allowing sufficient room for efficient price formation;  A liquid, deep, transparent and efficient financial market is needed to facilitate efficient risk management, price formation and to help increase access to capital at least cost; and  Efficient market responses need to be informed by accurate and timely information, including credible medium‐term demand projections that facilitate greater market transparency and more effective decision‐making. Russian policy makers are encouraged to position the wholesale market for a move to an energy‐ only model in the longer‐term once these key pre‐conditions have been met.

Retail market structure Competitive retail markets are in an early phase of development in Russia. At present they are dominated by regulated Guaranteeing Suppliers (GS), which tend to operate localised franchises primarily to supply regulated residential consumers and to fulfil universal service obligations. The dominance of GS’s and the localised nature of retailing activities are generally reflected in a highly fragmented and concentrated retail market structure. Several stakeholders expressed concerns about the inherently uncompetitive retail market structure and the resulting capacity of incumbent GS’s to exercise market power to extract excess profits at the expense of end‐users including:  limited competition reflected in passing through of all costs with few incentives for developing more cost‐effective, efficient or innovative products or services;

Russian Electricity Reform 2013 Update: © OECD/IEA 2013 Laying an Efficient and Competitive Foundation for Innovation and Modernisation

 various forms of price gouging leading to substantially higher profits for incumbent GS’s and higher retail charges for end‐users compared to retail businesses operating in more contestable markets;  limited effective choice and weakening consumer engagement, reflecting a lack of competition, and market and regulatory barriers to switching suppliers; and Page | 8  substantial barriers to new entry including: high transaction costs associated with accessing the wholesale market; monopoly status of GS’s; limited transparency; opaque price formation; limited access to information and customers; and continuing uncertainty over the roles, responsibilities and rules applying to retail market entities and retail market transactions. Together these factors have helped to strengthen the effective market power of GS’s while distorting competition and efficient retail market development at the expense of end‐users. Russian policy makers recognize the importance of creating a robust, competitive retail market structure. Recently announced reforms, notably those contained in the May 2012 Resolution on retail market development and GS regulation will help to address many of the issues underlying these concerns. Other opportunities could be considered to help reinforce and complement the regulatory and commercial incentives created by the new rules and regulatory arrangements. For instance, structural reforms might also be considered to complement and reinforce regulatory behavioural incentives on GS’s, possibly including restructuring of incumbent GS’s over the longer term so that they can become more efficient and competitive participants in retail markets. IEA experience suggests that competitive electricity retailing tends to be a high volume, low margin business, and is likely to result in the development of fewer, larger retailers with a regional, or national marketing presence. This can be a positive development where it reduces market fragmentation and strengthens competition across multiple regions among larger retailers that can take advantage of economies of scale to reduce operating costs and deliver more competitive benefits to end users. However, excessive consolidation, reflected in undue horizontal and vertical integration, could result in less competition and lower benefits for end users, especially if it becomes a material barrier to new entrants, who are critical for driving the development of innovative products and services. IEA experience also suggests that relatively small legal, regulatory, market or administrative requirements that add undue transactions costs can serve to discourage new entrants. Similarly, access to accurate and timely information has proven crucial to support new entry, innovative product development and to inform customer choice. Close monitoring and supervision of retail markets will be required to identify and eliminate barriers as they emerge especially during the early stages of the development and evolution of contestable retail markets. Effective competition supervision will be especially important at a regional level given the highly localised and relatively fragmented nature of the retail sector at present. SFA is taking a proactive approach to retail market monitoring and enforcement and will need to build on this foundation to ensure that competition supervision remains effective and continues to support the development of competitive retail markets.

Retail market arrangements Russian policymakers recognise the importance of developing a competitive retail sector that promotes innovation and effective customer choice to help maximise the benefits delivered to end‐users. The May 2012 Resolution is a very positive step that addresses many of the market rules and regulatory gaps which had served to limit the development of competitive retail

© OECD/IEA 2013 Russian Electricity Reform 2013 Update: Laying an Efficient and Competitive Foundation for Innovation and Modernisation markets and more effective customer choice. In particular provisions addressing access to the wholesale market, contracting standards; metering, billing, switching and disconnection standards; and clarity around pricing and price regulation are welcome developments and a necessary precondition for the effective functioning and development of competitive retail markets for electricity. However, much will depend on how effectively the market rules and regulations are translated Page | 9 into commercial incentives and practical processes that support efficient, competitive and innovative market operation and development. IEA experience suggests that a well‐functioning marketplace that creates strong incentives for efficient and innovative commercial behaviour is a key precondition for success in this context. Similarly, a framework that clearly defines roles, responsibilities and obligations on parties is needed to establish an appropriate contractual basis for supply, supported by effective dispute resolution and default mechanisms. Contracts for smaller volume consumers need to be simple and standardised to the greatest extent possible to help clarify and protect counterparty rights at least cost. Russian policymakers have taken positive steps in this direction with the initiative to develop model retail supply contracts as part of the program to improve customer service quality standards. IEA experience also suggests that translating the legal and regulatory framework into practical rules and processes that minimise transaction costs, while supporting competitive entry, innovation and exercise of choice is a challenging task. An integrated and seamless approach is needed to address these practical challenges in an effective manner. Key issues that could be considered in this context include:  Establishing effective market processes and practices: Simple and seamless rules and processes are needed to encourage competition, choice and demand response. ‘Back office’ processes need to be efficient, ensuring effective data exchange to support timely switching processes. Information needs to be provided to the market in a timely, efficient and non‐ discriminatory manner, while protecting consumer privacy and commercial confidentiality. Similarly, billing processes need to provide accountability and transparency and be implemented in a manner that does not discourage choice. Russian policymakers, regulators and market institutions will need to actively engage with market participants in the context of developing key retail market processes to ensure that they facilitate dynamic retail competition and promote effective customer choice.  Access to accurate and timely information: Access to data and data exchange are emerging as key practical issues affecting the development of liberalised retail markets. Data collection, management and dissemination needs to be undertaken in a manner that: ensures non‐ discriminatory access; provides timely access to sufficient information to support effective decision‐making by all stakeholders; protects privacy and confidentiality; and minimises data collection and management costs. The Market Council may be well placed to offer a more centralised service and possibly act as a neutral facilitator promoting access to information and information exchange. Policy makers, regulators and market institutions should look to develop data standards and management processes in close consultation with market participants to deliver effective and least cost solutions that promote greater transparency, competition, innovative product development and effective choice.  Building customer awareness and engagement: Developing a knowledgeable and active consumer base that effectively exercises choice has proven to be a practical challenge in liberalised electricity retail markets, especially among residential customers. Priority needs to be given to raising awareness and understanding, especially among small volume customers, so that they are able to effectively exercise choice and experience tangible benefits from

Russian Electricity Reform 2013 Update: © OECD/IEA 2013 Laying an Efficient and Competitive Foundation for Innovation and Modernisation

competition. Key requirements for an effective consumer information program include: improving customer ability to understand and compare offers; improving awareness of consumer rights and responsibilities; plane language presentation of information; and access to independently verified product comparison tools. The Market Council may be well placed to develop information and comparison tools that are comprehensive and can deliver Page | 10 independent and credible advice to the market. Web‐based information should be complemented with plain language materials and call centre options as proposed under the customer service quality standards initiative. Policymakers and regulators might also review regulatory arrangements to protect consumers including rights of appeal and recourse procedures to ensure their effectiveness.  Effective use of enabling technologies: Many IEA jurisdictions are in the process of introducing a range of enabling technologies that provide cost‐effective, real‐time metering information, verification and control capability to support the development of innovative products that deliver greater demand‐side flexibility and more effective customer choice. Russian authorities are pursuing a roll‐out of meters as mandated under the Energy Efficiency Law. This is a welcome development. However, much of the benefit of advanced metering systems can only be fully realised with ‘smart’ meters that provide real‐time information, communications and control capabilities. In the longer‐term as retail markets develop consideration could be given to rolling‐out ‘smart’ metering systems and supporting the deployment of complementary enabling technologies, especially in those wealthier regions with higher average levels of consumption and greater capacity to respond to price signals.

Efficient and cost‐reflective end‐user pricing Cost‐reflective pricing is a key pre‐condition for creating strong incentives for efficient investment, operation and end‐use. It is also a key precondition for delivering electricity sector modernisation and the Government's wider economic policy objectives at least cost. Considerable progress has been made to rebalance end‐user tariffs since 2001 with average prices increasing three to five‐fold for most customer classes over the period, albeit from a very low base. However, there is still some way to go to achieve cost‐reflectivity. Cross‐subsidies from contestable industrial and commercial users to regulated residential customers are in the order of Euro 5.2 billion per annum, or less than 10% of total annual electricity sector revenues. Although this is a relatively modest amount, it is concentrated within a relatively small proportion of the load which means that regulated residential tariffs will need to increase by between 50% and 70% to approach cost‐reflective levels. At the same time, evidence is emerging of large and medium‐sized businesses choosing to invest in distributed generation rather than pay the inflated distribution charges resulting from these cross‐subsidies. According to the Ministry of Energy it would be profitable for 40% to 50% of industrial users to exit the centralised power system and build their own generating facilities under the current cross‐subsidy arrangements. Such an outcome would place efficient, timely and least cost sector development at risk, with the potential to jeopardise achieving the Government’s sector modernisation and wider economic policy goals. Unwinding the remaining cross‐subsidies and moving to cost‐reflective pricing will be a challenging but necessary task if the full benefits of electricity reform are to be realised. A coherent and well managed implementation strategy will be required to successfully complete the rebalancing. Russian policymakers have recognised the need to address cross‐subsidies and are implementing a proposal to replace existing cross‐subsidies with a better targeted, budget funded subsidy for regulated users delivered through a modest volume of subsidized consumption. This is a positive step that could help to quarantine subsidies and reduce overall

© OECD/IEA 2013 Russian Electricity Reform 2013 Update: Laying an Efficient and Competitive Foundation for Innovation and Modernisation costs, while allowing for more cost‐reflective pricing. Opportunities exist to build on this foundation by adopting an integrated transitional approach that: aligns increases in end‐user rates to capacity to pay; delivers assistance directly to low income and vulnerable users through direct payments; and progressively moves the obligation for funding subsidies from end users to the Government. IEA experience suggests that an effective rebalancing strategy should also pursue sector Page | 11 efficiency in parallel to help reduce cost‐reflective price levels and the magnitude of the rebalancing challenge. An integrated reform program addressing the whole supply chain could be expected to deliver the best results. Such a program is currently being implemented in Russia. Issues relating to progressing reform of contestable wholesale and retail markets have been discussed previously and are the focus of this report. Reform of monopoly network services can also make a substantial contribution to reducing the overall cost‐reflective level of end‐user prices. Rapidly increasing network charges were a major contributor to the recent excessive rate of growth in end‐user prices, and may offer considerable scope for further productivity improvement. Russian policy makers have implemented several measures to address deficiencies experienced with the roll‐out of the RAB incentive regulatory regime, which had substantially contributed to the rapid price increases. These are welcome initiatives that should strengthen incentive regulation and result in more efficient and cost‐ effective outcomes that will lower the cost‐reflective level of end‐user prices over time. Opportunities may exist to build on these initiatives including: strengthening the economic assessment methodologies employed to assess capital expenditure proposals; developing a comprehensive database to support more effective application of benchmarking; expanding quality of service and reliability incentive programs to include demand response; and improving transparency and effectiveness of decision‐making through greater use of public consultation. Russian authorities are also exploring privatisation as a means of improving network performance and managerial responsiveness to incentive regulation. The Tomsk distribution system was placed under private management in 2012 and two distribution systems may be privatised in 2013. These are welcome developments, with the potential to deliver more cost‐ effective operational and investment performance that reduces prices for end‐users over time. Russian policymakers are encouraged to move quickly to expand private participation in the provision of distribution network services, subject to the successful implementation of the proposed pilot projects. Regulation of end‐user electricity prices remains relatively common in liberalised electricity markets, especially regulation of residential consumer prices. Russia is no exception. For instance, authorities capped end user prices in 2011 largely to address strategic behaviour associated with the roll‐out of RAB regulation. Price regulation needs to be handled with care. Irrespective of the merits, such interventions invariably magnify uncertainty and regulatory risk from the perspective of market participants which can distort responses and jeopardise efficient market development. Empirical evidence is also emerging which suggests that the consumer protection arguments for price controls become less compelling as competition develops, and are better addressed through some form of targeted payment. However, during the transition toward cost‐reflective end‐user prices, price regulation can provide a ‘safety net’ to assure policy makers and the community that sufficient regulatory protection is in place to address potential excesses or abuse. Russian authorities could undertake to review price regulation as retail markets mature, with a view to removing regulation where retail markets are sufficiently competitive to deliver and sustain efficient, cost‐reflective prices that benefit consumers. This could help to reassure market participants about the Government’s determination to complete the pricing reforms.

Russian Electricity Reform 2013 Update: © OECD/IEA 2013 Laying an Efficient and Competitive Foundation for Innovation and Modernisation

1. Introduction

Russia is in the process of one of the most ambitious electricity sector reforms ever undertaken, reflecting the importance of an efficient and reliable electricity sector for promoting economic growth and prosperity. The outcome of this process will have a substantial impact on Russia’s Page | 12 energy sector and longer‐term economic performance. It will help to determine the nature and pace of investment, the nature and pace of sector modernisation and will help to shape incentives for efficient, flexible and innovative operation and end‐use. Reform achievements since the IEA’s 2005 study of Russian electricity sector restructuring (IEA, 2005) have been impressive, including:

 Unbundling and USD 30 billion privatisation of generation infrastructure;  Implementation of a wholesale energy spot market and capacity mechanism covering much of European Russia, the Urals and Siberia;  Introduction of incentive‐based economic regulation and open access arrangements for transmission and distribution networks;  Progress toward retail market reform and more cost‐reflective pricing; and  The establishment and strengthening of key market and regulatory institutions. However, the outcome remains uncertain at this stage. Electricity reform is entering a critical phase in Russia where IEA experience suggests that government commitment to reform may be tested and the risk of undue compromises that can jeopardise successful implementation may increase. This paper examines some of the key remaining challenges affecting the development of competitive wholesale and retail electricity markets including: market structure; market design; pricing; investment and related regulation, drawing from the experience of IEA member countries to inform the analysis as appropriate. The analysis draws extensively from consultations with key Russian stakeholders including representatives from the Russian Federation, federal regulators, the wholesale market operator, the system operator, industry participants, major users, finance and industry analysts, academics and research institutions. Chapter Two examines issues affecting wholesale market development including wholesale market structure, wholesale energy and capacity market arrangements and considers the development of a more market‐orientated wholesale market model for the longer‐term, focusing on the potential to employ an energy‐only wholesale market model to promote more efficient and timely investment to deliver the Government’s sectoral efficiency, modernisation, innovation and wider economic policy goals. Chapter Three examines issues affecting the development of retail markets for electricity including retail market structure, retail market design and the challenge of introducing more cost‐reflective pricing for end‐users.

2. Wholesale Market Development

IEA experience suggests that transparent and competitive wholesale markets are a crucial foundation for the successful implementation of electricity sector reforms. Competitive wholesale markets are a key driver for efficient, timely and innovative investment, operational and end‐use responses, which can help to improve sector productivity while improving reliability Page | 13 and service quality at least cost.

Wholesale market structure

IEA experience indicates that the strength and dynamism of competition in wholesale electricity markets is greatly affected by the wholesale market structure, with a less concentrated market structure more likely to deliver efficient and innovative outcomes and requiring less regulatory intervention. The original restructuring proposal envisaged creating up to 26 wholesale and territorial generation companies which, in principle, would have been able to compete among themselves across the entire wholesale market. The proposal included spreading ownership as evenly as possible by technology, location and size, in an effort to maximise competition and competitive outcomes at a wholesale level. IEA examination of the structural diversity of the original proposal using a standard Herfindahl‐Hirschman Index (HHI) analysis1 yielded a HHI score of around 650, which suggested a diversified structure with the potential to deliver considerable breadth of ownership and a highly competitive wholesale market structure (IEA, 2005). The 2008 privatisation program substantially implemented this proposal and remains one of the most successful electricity sector privatisation programs to date. According to the Ministry of Economy, the program attracted around USD 30 billion of private capital to the electricity sector, including contractual agreements to deliver around USD 15 billion of new generation investment needed to meet projected capacity requirements, while the Federal Antimonopoly Service noted that the privatisation had resulted in a five‐fold increase in diversity of ownership2. IEA analysis of Russia’s current wholesale market structure suggests relatively diversified ownership consistent with a moderately concentrated market structure on a national basis. Table 1 summarises the results of this analysis. The largest three generators by capacity are Gazprom Energoholding, Rosatom and InterRAO. Together they control over 84 GW, representing around 43% of total Russian generation capacity within the competitive wholesale market covering European Russia, the Urals and parts of Siberia. Each of these companies is either government owned or majority government controlled. Six generators have individual market shares greater than or equal to 5% of total generating capacity within the competitive wholesale market. IEA analysis suggests a moderately concentrated wholesale structure nationally with a HHI score of 1 0313.

1 The Herfindahl Hirschman Index (HHI) is a conventional indicator of concentration in product markets. It is calculated by adding the sum of the squares of the percentage market shares of each market participant. For example, a market consisting of five competing firms, each with a 20% share of the market ewould hav an HHI score of 2000 (i.e., 202 x 5). HHI is typically used to help assess the degree of market dominance and potential for market power abuse. Views vary on the interpretation of HHI scores. This study uses the scale developed by the European Union (see footnote 3 for details). 2 Raised during consultations with Ministry of Economy and Federal Antimonopoly Service officials, April 2011. 3 The European Commission has adopted a scaled approach to interpreting the HHI with scores of 750‐1800 considered indicative of moderate concentration; scores of 1800 to 5000 indicative of high levels of concentration and scores above 5000 indicative of very high concentration consistent with the presence of substantial potential market power.e Se European Commission 2011 for details.

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However, under the market rules nuclear and hydroelectric generators are subject to priority dispatch, with combined heat and power generators added to priority dispatch during the heating season. Priority dispatch generators can only submit quantity bids, with any volumes that are dispatched receiving the system marginal price4. As a result, these generators do not participate directly in the wholesale spot price formation process. It can be argued that their Page | 14 exclusion from a concentration analysis is likely to yield a more realistic indication of effective concentration and underlying levels of competition (Pittman, 2007).

Table 1 • Russian wholesale electricity market structure indicators Price Zone One Price Zone Two National (European (Siberia) Russia & Urals)

Share of 3 Largest Generators (%) 43.4 53.1 62.4

Number of Generators Controlling >=5% All generation 6 7 6 Capacity

HHI Index 1031 1317 1773

Share of 3 Largest Generators (%) 56.4 63.7 65.2 Excluding summer price Number of Generators Controlling >=5% 6 6 7 takers (nuclear Capacity & hydro) HHI Index 1365 1703 1851

Share of 3 Largest Generators (%) 69.4 76.1 58.9 Excluding summer & Number of Generators Controlling >=5% 5 4 7 winter price Capacity takers (CHP) HHI Index 1975 2285 1892

Note: Around 12.5 GW of capacity allocated for block stations was excluded from this analysis. Source: IEA analysis based on generating capacity and ownership data provided by the Energy Research Institute of the Russian Academy of Sciences. The national wholesale market structure is significantly less diversified if priority dispatch generators are removed. The maximum volume of generation capacity submitting competitive bids for dispatch in the wholesale market falls by over 65 GW to around 128.5 GW with the removal of nuclear and hydro facilities, while the share of the largest three generators increases by nearly 30% and market concentration as measured by the HHI score increases by nearly one‐ third. Rates of concentration increase further with the removal of combined heat and power facilities over the winter heating season. This results in the maximum volume of competing generating capacity falling by a further 62 GW to 66.5 GW, an increase in the market shares of the top three generators by a further 23% and an increase in the HHI score by nearly 45%. The combined removal of these facilities results in a reduction in the volume of competing generation capacity by around 127 GW to around one‐third of the level with all generation included, while increasing the effective market share of the top three generators by nearly 60%. The HHI score also increases considerably, by over 90%, moving the national HHI indicator of wholesale concentration from the moderate range into the high range. In practice, the wholesale energy market is divided into two price zones for spot trading and

4 See Federal Law #35‐FZ, On the Electric Power Industry (26 March 2003), Article 32. This Article includes the dispatch priority for certain classes of generation. First priority is given to generators providing reliability services and to nuclear generation (to the extent required to meet safety and other operational requirements). Second priority is given to hydroelectric generators (to the extent that they need to run to meet technological or environmental requirements) and combined heat and power plants (where operation is driven by heating demand). Third priority is given to output associated with registered bilateral contracts. In each case ATS must factor such volumes into the optimal dispatch schedule. Generators dispatched on this basis are price‐takers from a spot‐market perspective and cannot set the spot price.

© OECD/IEA 2013 Russian Electricity Reform 2013 Update: Laying an Efficient and Competitive Foundation for Innovation and Modernisation settlement purposes. Price Zone One covers European Russia and the Urals, typically representing around 80% of total volumes traded on the sport market. Price Zone Two covers the Siberian integrated power system which is dominated by larger industrial loads, typically representing around 20% of volumes traded on the day‐ahead spot market. Separate zones were established to reflect the limited transfer capability between these zones which results in persistent congestion and chronic price separation. Over the last year, system marginal spot Page | 15 prices for Price Zone One have tended to be around 20% to 30% higher than in Price Zone Two. The Russian wholesale market structure is significantly less diversified when analysed on the basis of these price zones. IEA analysis presented in Table 1 shows that the share of the three largest generators increases from around 43% nationally to around 53% in Price Zone One and to over 62% in Price Zone Two, representing an increase of around 22% and 44%, respectively. Similarly, concentration of capacity also increases considerably in both zones, with the HHI score in Price Zone One rising to around 1 320, representing an increase of around 27%, while the HHI score in Price Zone Two rises to around 1 770, representing an increase of nearly 72% compared to the combined national result. Concentration rates increase further with the removal of price taker capacity, rising to relatively high levels consistent with the presence of significant potential market power. Analysis undertaken by FAS draws similar conclusions, with Price Zone Two recording concentration levels consistent with the presence of significant potential market power without excluding price taking plant (FAS, 2012a). Nonetheless, the diversity of the Russian wholesale market structure compares favourably from an international perspective. Figures 1 and 2 present indicators of wholesale electricity market concentration for Russia and a selection of European IEA member countries in 2010. This comparison suggests that the Russian wholesale market structure, taken as a whole, is the most diversified among this group, with the lowest market share for the top three generators, among the largest diversification of ownership and the lowest HHI score. Even with all price takers removed, Russian wholesale market concentration levels remain comparable to median performers like Germany and Spain. Network congestion is emerging as a significant policy issue in Russia with the potential to limit the degree of national market integration, and the depth and strength of competition at a wholesale level. It is most evident in the highly fractured structure of the wholesale capacity market. In 2012, the market included 27 separate pricing zones, with system marginal capacity prices determined by competitive bids in only three of these zones, representing nearly 50% of total capacity within the competitive wholesale market. Prices in the other zones are determined by the Federal Antimonopoly Service (FAS). The number of zones and high degree of regulatory intervention in price formation reflects the prevalence of congestion and technical constraints that limit power flows and effective competition between generators to supply capacity. In addition, several stakeholders noted that congestion and other technical constraints are affecting spot market dispatch on a regular basis with negative implications for the development of efficient wholesale price formation and competition5. For instance, the System Operator of the United Power Systems advised that of the more than 8 000 nodes covering the competitive wholesale market, around 700 suffered from significant congestion in 20116.

5 References to comments from stakeholders throughout the document refer to observations raised during meetings with key Russian stakeholders. Consultations were conducted in Moscow in April, July and November 2011 and in December 2012. Consultation parties included senior representatives from the Ministry of Energy, the Ministry of Economy, the Federal Antimonopoly Service,e th Federal Tariff Service, the Market Council, the system operator, industry participants, major users, finance and industry analysts, academic and research institutions. 6 Raised during consultations with the System Operator of the United Power Systems, November 2011.

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Figure 1 • National concentration comparisons: market share of the three largest generators in 2010

Page | 16

Source: European Commission 2011 and IEA analysis based on generating capacity figures provided by the Energy Research Institute of the Russian Academy of Sciences.

Figure 2 • National concentration comparisons: Herfindahl‐Hirschman capacity indices in 2010

Source: European Commission 2011 and IEA analysis based on generating capacity figures provided by the Energy Research Institute of the Russian Academy of Sciences. IEA analysis used the five integrated electricity systems included within Price Zone One as a proxy to illustrate the potential impact of congestion and regionalisation on the underlying

© OECD/IEA 2013 Russian Electricity Reform 2013 Update: Laying an Efficient and Competitive Foundation for Innovation and Modernisation competitiveness of the wholesale market structure and spot price formation in this pricing zone. The results are summarised in the following table.

Table 2 • Wholesale market structure analysis for price zone one Central North South Urals Volga west Page | 17 Regional All Share of 3 largest 73.9 95.6 78.9 49.7 83.9 capacity generation generators (%) with no Number of generators trade 5 3 5 7 4 between controlling >5% capacity regions HHI index 2114 3771 2307 1381 2629

Excluding Share of 3 largest 74.8 98.5 98.3 52.9 100.0 summer generators (%) price takers Number of generators (nuclear & 5 3 3 7 2 hydro) controlling >5% capacity HHI index 2622 5108 3832 1525 6332

Excluding Share of 3 largest 81.9 97.9 98.3 73.4 100.0 winter price generators (%) takers Number of generators (nuclear, 4 2 2 5 1 hydro & controlling >5% capacity CHP) HHI index 2799 5723 6071 2264 9114

Regional All Share of 3 largest 65.3 88.8 61.0 44.5 64.8 capacity generation generators (%) with trade Number of generators between 4 3 5 7 4 regions controlling >5% capacity HHI index 1732 3305 1648 1162 1881

Excluding Share of 3 largest 66.5 86.6 63.5 47.0 66.0 summer generators (%) price takers Number of generators (nuclear & 4 3 3 7 2 hydro) controlling >5% capacity HHI index 2192 4099 2212 1268 2904

Excluding Share of 3 largest 60.3 70.5 52.6 62.5 24.8 winter price generators (%) takers Number of generators (nuclear, 5 2 2 5 1 hydro & controlling >5% capacity CHP) HHI index 1922 3752 2883 1755 3569

Note: Around 12.5 GW of capacity allocated for block stations was excluded from this analysis. Source: IEA analysis based on generating capacity and ownership data provided by the Energy Research Institute of the Russian Academy of Sciences. IEA analysis suggests that congestion could significantly affect the level of generator competition and competitive spot price formation in Price Zone One, with some regions within Price Zone One recording levels of concentration consistent with the presence of significant market power. Overall, the Central, Northwest, South and Volga regions recorded HHI scores in the highly concentrated range, consistent with the presence of potentially significant levels of market power. Conversely, the HHI score in the Urals region is only marginally greater than the results recorded for Price Zone One. Concentration rates increase considerably with the removal of price taker capacity with all regions moving into HHI ranges consistent with high or very high levels of concentration. HHI scores rise by around 30% in the Central region and by over 60% in the Urals region, to record results consistent with high levels of concentration. The increase in the concentration rate is

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more substantial in the Northwest where the HHI score rises by around 50% into the very high concentration range. While the HHI score for the Southern region increases more than two‐and‐ a‐half fold to record very high levels of concentration. The situation is especially challenging in the Volga region, where the HHI score increases more than five‐fold to reach extreme levels that approach the maximum HHI value of 10 000, raising substantial concerns about the potential for Page | 18 market power abuse to materialise, especially during the peak winter period. By contrast, concentration increases only marginally in the Siberian region, by around 7% to record a HHI score at the low end of the highly concentrated range. However, this analysis probably overstates the real situation. Structural diversity scores increase considerably when adjustments are made to reflect potential inter‐regional power flows and trade. For instance, the HHI score for the Volga region more than halves when inter‐regional trade is considered. Similarly, the HHI score for the Southern region falls by over 40%, while other regions record significant falls of between 10% and 20%. However, even with trade some regional power systems may experience high or very high effective levels of concentration under certain circumstances, which could adversely affect competition and wholesale spot price formation in Price Zone One. IEA electricity markets have generally experienced considerable rationalisation post reform, involving horizontal and vertical re‐integration both within the electricity value chain and into upstream fuel supply chains. Policy makers in OECD countries are becoming increasingly concerned about vertical integration and its implications for the operation and development of competitive wholesale electricity markets. It would also appear to be an emerging policy issue in Russia. For example, Gazprom Energoholding is the dominant supplier of gas for power generation in Russia and is also the largest generator in the competitive wholesale market, owning or controlling over 37 GW of generating capacity or nearly 20% of the competitive wholesale market. Around 36 GW of this plant is located in the first wholesale pricing zone spanning European Russia and the Urals, representing around 24% of total installed capacity. Over 17 GW of this capacity is bid‐for‐ dispatch gas‐fired plant, which is the key marginal supplier determining wholesale spot price formation in the first price zone. Although these assets represent around 11.5% of total capacity in the first price zone, they represent over 30% of available bid‐for‐dispatch capacity once price‐ takers are removed. As a result, Gazprom Energoholding could have considerable potential to apply various strategic bidding practices in an attempt to influence wholesale spot price formation7. There can be sound commercial reasons for a degree of vertical integration in competitive electricity markets. For instance, vertical integration may be pursued as a legitimate corporate strategy to extract economies of scale and scope, to reduce transaction costs, or to strengthen capitalisation to support efficient business growth and more cost‐effective access to equity and debt markets. It might also be pursued to provide cost‐effective physical hedging of risk, especially in the absence of liquid and deep primary and secondary financial markets. However, undue levels of vertical integration which threaten market transparency and open opportunities for market manipulation and foreclosure have the potential to substantially restrict potential new entry and other responses that might serve to discipline commercial behaviour in a more competitive environment. Excessive vertical integration can also undermine the development of liquidity and depth in financial markets, which can increase counter‐party risk

7 Market participants may have strong incentives to exercise market power to drive up spot prices in an effort to recoup losses incurred in capacity markets or in the heating sector. Some stakeholders suggested that this is a particular issue for generators with large portfolios of combined heat and power generation.

© OECD/IEA 2013 Russian Electricity Reform 2013 Update: Laying an Efficient and Competitive Foundation for Innovation and Modernisation and risk management costs. This in turn has the potential to discourage efficient wholesale trade which serves to reduce liquidity, jeopardise efficient price formation and potentially increase price volatility. The combination can create a vicious cycle where market participants are increasingly encouraged by uncertainty, risk and rising transaction costs to consider l vertica integration as an alternative to trading in wholesale markets. Undue levels of vertical integration between a dominate upstream fuel suppler with substantial interests in downstream thermal Page | 19 generation may also raise concerns about the potential for discrimination against competing thermal generators, either by denying them access to sufficient competitively‐priced gas, or by favouring its electricity generating subsidiaries. Similar concerns were raised in the European Commission energy sector competition inquiry, and have been echoed recently in the debate in the United Kingdom and Australia over the causes of rising end‐user prices. These inquiries have raised concerns about the negative impact of high degrees of vertical integration on market transparency and financial market liquidity, and their potential to increase barriers to entry, distort efficient price formation processes and generally reduce competitive pressures through the contestable parts of the value chain (European Commission, 2007; AER, 2011). Complex ownership structures have also emerged ind liberalise IEA electricity markets including considerable cross‐ownership and the creation of mixed technology portfolios that have the potential to weaken transparency and dilute competition and efficient market development. Generators controlling mixed technology portfolios including base load and peaking capacity can influence spot price formation through bidding strategies that push up the system marginal price, especially in times of tight supply. Extensive cross‐ownership can have a similar effect to increasing concentration of markets by distorting incentives for efficient, competitive commercial behaviour. In particular, high levels of cross‐ownership suggest a greater potential for collusion and may encourage the adoption of other anticompetitive behaviours that have the potential to distort efficient, innovative commercial behaviour and market development. A study undertaken by Nordic competition regulators suggested that levels of cross‐ownership in the Nordic market in the early 2000s had reduced effective wholesale market competitiveness by an amount equivalent to a 28% increase in ownership concentration (Nordic Competition Authorities, 2003). Similar structures appear to be emerging in the Russian wholesale market. For instance, InterRAO UES, which is the third largest generator operating in the competitive wholesale market, has a technologically and geographically diverse portfolio of generation assets including controlling interests in two of the original wholesale generation companies, Bashkirenergo and Territorial Generation Company 11. It also has considerable minority cross‐ownership interests spanning all its major wholesale market competitors including seven of the original territorial generation companies, two of the remaining wholesale generation companies and RusHydro (FAS, 2012; Troika Dialogue, 2012). Overall, analysis highlights the potential for a more integrated regional market to greatly reduce effective levels of wholesale market concentration and to support the development of a more competitive and dynamic wholesale market over time. Russian policymakers are aware of the need to strengthen regional market integration, which is reflected in the priority given to eliminating persistent points of transmission network congestion and technical network limitations that currently restrict more efficient integration of capacity zones and competitive spot price formation. This priority is reflected in the Federal Grid Company’s recently upgraded investment program for 2013‐17 which proposes to allocate RUB 775.5 billion to commission over 66 000 MVA of new transformer capacity and nearly 17 000 kilometres of new transmission lines (FGC, 2013). These investments will, among other things, focus on network reinforcement to help facilitate amalgamation of free flow capacity zones to strengthen and deepen competitive capacity markets.

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Ultimately, a competitive wholesale market structure is best achieved through diversity of ownership. Greater diversity of ownership has the potential to help reduce horizontal and vertical integration, while also helping to address the negative implications from undue levels of cross‐ownership. It would also improve market transparency, which would help to strengthen commercial discipline while supporting more efficient market responses and more effective Page | 20 competition supervision. Although the 2008 privatisation brought several new entrants and greater diversity of generation ownership, government‐owned enterprises continue to own or control over 60% of total generation assets, with the four largest – Gazprom Energoholding, Rosatom, InterRAO and RusHydro – controlling over 105 GW of generating capacity, representing over half of the generating capacity within the competitive wholesale market. A trend toward consolidation of ownership following a major unbundling and privatisation has been a common experience among IEA member countries to date. However, in Russia consolidation of generation ownership to date has largely been back into government ownership. Table 3 charts the development of this trend since liberalisation.

Table 3 • Russian electricity generator ownership trends: 2008‐2011

Generating companies Largest owners (2008) Largest owners (2011) OGK 1 RusHydro InterRAO OGK 2 Gazprom Gazprom OGK 3 NorilskNikel InterRAO OGK 4 E.On E.On OGK 5 Enel Enel, InterRAO (26.5%) OGK 6 Gazprom Gazprom TGK 1 Gazprom, Fortum Gazprom, Fortum TGK 2 Sintez Sintez TGK 3 Gazprom Gazprom TGK 4 Kvadra Kvadra TGK 5 IES IES TGK 6 IES IES, InterRAO TGK 7 IES IES TGK 8 Lukoil Lukoil TGK 9 IES IES TGK 10 Fortum Fortum TGK 11 SUEK,Lukoil InterRAO TGK 12 SUEK SUEK TGK 13 SUEK SUEK TGK 14 Energopromsbyt Energopromsbyt RusHydro Russian Federation Russian Federation Rosatom Russian Federation Russian Federation Note: TGK = territorial generating company; OGK = wholesale generating company; SUEK = Siberian Coal Energy Company; IES = Integrated Energy Systems. Source: Gore et al., 2012. This is an unusual trend based on international experience and may have implications for competitive neutrality and efficient market operation and development in the longer term. Several stakeholders consulted during this study suggested that scope may exist to improve the operational and investment performance of government‐owned enterprises.

Government ownership may not be a problem of itself, so long as government‐owned enterprises are operated on an arm’s‐length basis subject to normal corporate governance and regulatory requirements and commercial practices. However, international experience to date suggests that this may be the exception rather than the rule in many cases. On balance, the evidence suggests that government‐owned enterprises are generally less efficient than their private sector peers. Government‐owned enterprises are often exposed to many additional Page | 21 requirements, including non‐commercial goals, ministerial directions, local procurement obligations and generous employment benefits; many of which can be incompatible with normal commercial objectives and operations. At the same time, the incentives of government shareholders are often complicated by multiple and disparate objectives, which serve to weaken corporate governance. Corporate governance can be further weakened where board members are appointed for reasons other than merit. Governments have also intervened to affect the capital spending of government‐owned enterprises by changing reliability standards or by constraining expenditure through austerity or debt reduction programs. Cycles of under‐spending followed by reliability problems and then periods of overspending have been observed in some jurisdictions, which is not consistent with the timely and efficient provision of electricity services that meet the long‐term interests of consumers or the economy at least cost (Productivity Commission, 2012). IEA experience suggests that increasing the level and diversity of private control and ownership can result in a more dynamic and innovative electricity sector that can deliver substantial efficiency improvements (Productivity Commission, 2012 for further discussion). In principle, there appears to be considerable scope for the Russian Government to improve diversity of ownership and wholesale competition through further divestment, particularly from among those assets that are wholly owned by government‐owned enterprises. Recent positive statements about the potential for further privatisation of some InterRAOd an possibly RusHydro assets in the medium‐term are a welcome development. However, there may be some practical difficulties that limit the potential for further large‐scale divestment at this time. Global capital markets remain weak in the wake of the global financial crisis and continuing European debt crisis. As a result, access to capital remains limited and borrowing costs remain relatively high, especially for capital intensive projects. Any privatisation program initiated at this time may yield disappointing results both in terms of improving diversity of private ownership and revenue collected from asset sales, reflecting the combination of weak global financial conditions and the additional risk and uncertainty associated with investing in the Russian electricity sector as it progresses through the current transitional period. In addition, arguments could also be made for keeping ‘strategic’ assets in public ownership. For instance, keeping nuclear facilities in public hands may represent a more effective way to deal with national security and politically sensitive issues such as nuclear safety and the secure disposal of nuclear waste. The 2011 Fukushima Daiichi nuclear incident has served to highlight the potential limitations of private ownership of nuclear facilities and the ultimate responsibility governments must bear in the event of a low probability‐high impact event that is beyond the financial capability of private interests to quickly and effectively manage. IEA experience suggests that the case for long‐term public ownership and control of hydro assets is less clear. Privately owned and managed hydro generators operate successfully in a competitive bid‐for‐dispatch environment in several liberalised IEA electricity markets including in the United Kingdom, Scandinavia, Australia and in New Zealand. Sensitive matters, such as the provision of technical and balancing services to maintain reliability and system security; public safety; and environmental, agricultural and fisheries management, can be dealt with through contractual agreements and licensing arrangements that specify operational restrictions and clarify the boundaries for commercial activities.

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Given the importance of hydro generators for flexible, reliable and efficient operation of wholesale markets and for supporting efficient spot price formation, and given the concerns about the continuing high level of government ownership, the Federal Government should give consideration to the combination of licensing with further unbundling and the eventual privatization of hydro assets once the current asset development program is complete and the Page | 22 long‐term wholesale market is operating effectively. For instance, scope may exist to restructure RusHydro to facilitate the development of a more competitive wholesale market structure that would add depth to spot price formation, especially during periods of relative scarcity, consistent with the original 2003 proposal to establish four hydro generation companies (IEA, 2005a). A more competitive structure for the supply of hydro power might also facilitate relaxation of the price taker rules, which is discussed further under wholesale market arrangements below. In the interim, there are a range of other mechanisms that could be employed to introduce private management or to increase effective diversity of private ownership of the output of publicly owned generators. For instance, virtual power plant auctions may provide a practical alternative to help increase competitive new entry and wholesale market liquidity without divestment. Virtual power plant auctions involve the sale of ‘virtual’ generating capacity by one or more dominant firms in a market. Under these arrangements the dominant owner retains management and control of the physical plant and offers contracts that replicate the output of the plant to competitors and new entrants. Virtualr powe plant auctions were first introduced by Electricité de France (EDF) to meet the requirements of an undertaking given to the European Commission following EDF's acquisition of the German electricity utility EnBW in 2001. EDF offered up to 5 400 MW of nuclear capacity through 42 quarterly capacity auctions between 2001 and 2011. EDF ceased quarterly auctions under the virtual power plant program following the sale of the German asset that had originally prompted the competition authorities to impose the VPP requirement. The EDF scheme remains the longest‐running and most successful program of its kind among IEA member countries to date, and will continue to operate until the last of the existing contracts expires at the end of 2015. Key features of the EDF’s auction program are summarised in Box 1 below. Virtual power plant auctions have been used by regulators in Germany, Spain, Portugal, Belgium, Denmark and the Netherlands to help:  facilitate access to wholesale electricity markets by new entrants;  promote the development of wholesale markets by adding liquidity and depth; and  reducing market power in electricity spot markets. The European Union noted in its Third Directive on the development of the internal European electricity market that regulators should be able to introduce virtual power plant programs as “one of the possible measures … to promote effective competition and ensure proper functioning of the market.” (European Parliament, 2009) Evidence to date suggests that virtual power plant auctions provide an effective means for facilitating new entry and improving wholesale market liquidity. They have perhaps been less successful at reducing market power, reflecting the relatively short‐term nature of the products offered to date and the limited volumes that could be offered without raising concerns about market saturation. Considerable potential exists to improve their effectiveness in this regard by more effectively integrating them with forward capacity auction markets (Ausubel & Cramton, 2010). The European Union energy sector competition inquiry drew similar conclusions (European Commission, 2007).

Box 1 • An overview of Electricité de France’s virtual power plant auction program

Between September 2001 and November 2011, Electricite de France (EDF) auctioned the rights to between 5 400 MW and 5 600 MW of generation capacity in France through its virtual power plant (VPP) capacity auction program. Auctioned capacity represented around 40 TWh per year, representing a little over 9% of EDF’s total nuclear generation in 2010. Page | 23 Under the program, ‘Virtual’ capacity was acquired by generators, suppliers and traders already operating in France and by those who wished to enter the market, through quarterly auctions conducted on the internet. Purchasers of these options received a drawing right on EDF generation capacity at a pre‐defined variable cost, without assuming any of the engineering and operational risk of plant ownership. EDF sold generation capacity in the form of contracts specifying both an energy price and a capacity price. The energy price was fixed in advance and remained fixed for the duration of the contract. The energy price varied by product class (i.e. base load and peak), reflecting differences in short‐run marginal costs of production. The capacity price was determined by the auction mechanism. This capacity price was paid every month for each MW purchased, for the duration of the contract. EDF auctioned up to 4 400 MW of base load contracts (80% of total) and up to 1 200 MW of peak‐ load contracts (20% of total). Both base load and peak load VPPs were offered in a variety of durations from 3 to 36 months. In addition the base load VPP product was also offered with a 48 month period. Sales were conducted using a multi‐round ascending price clock auction mechanism that offered all products simultaneously (3, 6, 12, 24, 36 and 48 months for base load contracts and 3, 6, 12, 24 and 36 months for peak load contracts), to enable buyers to acquire the appropriate portfolio of contracts for their needs. Auctions typically attracted around 30 bidders with around 20 successful purchasers at each auction. Source: EDF 2012 and Ausubel L. M. & P. Cramton 2010. A virtual power plant auction program could help to improve diversity within the Russian wholesale electricity market. For instance, a virtual power plant auction of 6 GW of Rosatom capacity would have the potential to reduce overall concentration by between 7.5% and 8.5% in Price Zone One, and by nearly 18% if applied entirely in the Central region which would be similar to the potential benefit of doubling intra‐regional trade. Virtual power plants might also facilitate extending merit order bidding and dispatch to some or all nuclear and hydro plant that is used to underwrite auction volumes. This may help to substantially increase liquidity and depth in the competitive segment of the wholesale spot market, which would help to improve the competitiveness of wholesale spot price formation. This in turn could help to strengthen incentives for efficient and innovative electricity market operation and development. Russian policymakers and regulators may wish to consider the potential for introducing virtual power plant auctions or similar mechanisms as a practical alternative to divesting assets that may prove difficult to privatise for wider public policy reasons, like nuclear and possibly some hydro facilities. Substantial ongoing public ownership of the country’s generating capacity is bound to raise competitive neutrality concerns among other market participants. It could also raise concerns among market participants about the potential for conflict of interest to unduly influence policy decisions given the Government’s role as rule‐maker, regulator and market participant. The perception may arise that the Government continues to own these assets in order to unduly influence and manage market outcomes. Such pressures may become difficult to resist, especially as wholesale and retail prices rise, as demonstrated in the decision to cap retail price rises in 2011. The Government will need to resist undue pressure to intervene in this way to the greatest

Russian Electricity Reform 2013 Update: © OECD/IEA 2013 Laying an Efficient and Competitive Foundation for Innovation and Modernisation

extent possible. Even the expectation that the government might be willing to intervene could damage the market’s credibility and the confidence of market participants. Uncertainty would grow, increasing regulatory risk and discouraging efficient and timely investment and market development, with the potential to jeopardise efficient and timely modernisation of the power sector. Such perceptions need to be carefully managed and minimised through consistent, Page | 24 coherent and objective policy and regulatory responses that, among other things, promote the development of a diverse and competitive market structure. Transparent and effective application of sound corporate governance principles and commercial practices to all facets of the management and day‐to‐day operation of government‐owned electricity businesses will help to address such concerns. Considerable progress has been made to introduce corporate governance arrangements, financial and risk management, auditing and public disclosure and reporting regimes that are consistent with international practices and the legislative requirements applying to similar privately owned entities. Government‐owned electricity businesses should be encouraged to build on this foundation by taking every opportunity to strengthen the application of arm’s‐length commercial decision‐making and by further improving transparency and disclosure. Independent, transparent and objective competition supervision will also be critical for maintaining a competitive wholesale market structure that builds confidence among market participants and potential investors. This is especially so in the period immediately following liberalisation which is often accompanied by considerable merger and acquisition activity. The Federal Antimonopoly Service (FAS) is responsible for competition supervision of wholesale and retail electricity markets in Russia and has already developed considerable experience with major merger and acquisition cases. Decisions to date have employed a mixture of behavioural and structural remedies with a view to maintaining a competitive balance, consistent with the range of regulatory remedies used by competition authorities among IEA jurisdictions. Transparency has been supported through targeted consultation and publication of decisions on the FAS website, which has included explanations of the reasons underpinning decisions. Several of these cases have involved government‐owned entities; cases which by their nature can place the objectivity of regulatory decision‐making under considerable pressure. To date FAS has been able to manage such pressure and deliver balanced determinations that seek to address competition and competitive neutrality concerns. However, FAS has employed some relatively prescriptive behavioural remedies on occasion, which may have the potential to unduly restrict commercial practice as markets develop. 2012 amendments to the Federal Law on the Protection of Competition that permit FAS to modify previous decisions to reflect changing market circumstances add welcome flexibility to the supervisory framework (see Russian Federation, 2012c for details). FAS has shown the capability to appropriately adapt its supervision to reflect changing market circumstances in the context of its recent determination to revise its March 2011 decision regarding InterRAO’s acquisition of OGK 3. However, this flexibility will need to be managed carefully to avoid creating regulatory risk or making changes that could unduly weaken previous decisions at the expense of efficient and competitive market operation and development. Box 2 provides further information on FAS’s approach to the InterRAO‐OGK‐3 acquisition case. FAS will need to continue to develop its supervisory methodology and approach to ensure that it is able to continue to provide balanced and objective competition supervision to support the efficient development of competitive wholesale and retail electricity markets in Russia. Regulatory independence and effective regulatory resourcing are critical preconditions for success in this context. Access to sufficient resources, especially capable and experienced staff, has proven to be a challenge in most IEA jurisdictions. FAS has given priority to addressing these

© OECD/IEA 2013 Russian Electricity Reform 2013 Update: Laying an Efficient and Competitive Foundation for Innovation and Modernisation issues, including through training programs and international engagement with competition supervisors, and is encouraged to continue to build the knowledge and expertise of its staff and to support the development of wider understanding of competition supervision issues among key stakeholders. Russian policy makers are encouraged to continue to support and strengthen FAS’s regulatory independence as appropriate. Page | 25 Box 2 • Competition supervision case study – InterRAO acquisition of OGK‐3

On 14th March 2011, FAS granted an application from InterRAO UES to acquire over 75% of the voting shares of the wholesale generating company OGK‐3. However, FAS concluded that the merger could strengthen the dominant position of InterRAO UES in the Ural Free Power Transfer Zone, and as part of its determination required the company to sell at least 883 MW of its other generating assets located in the Ural Free Power Transfer Zone within three years of acquiring OGK‐3. In the interim prior to completing the mandated divestment, the determination required InterRAO to file price‐taking bids on the day‐ahead spot market equal to at least 70% of its maximum available generating capacity located in the first price zone between the hours of 7 a.m. to 10 p.m. inclusive. For other spot market bids, InterRAO was also required to take into account the average‐weighted price of the fuel used to generate electric energy on its generating equipment. In addition, InterRAO was required to offer its plant in a manner that did not facilitate strategic behaviour that could result in a considerable increase in prices on the wholesale electricity spot or capacity markets. At the beginning of 2012, the “third antimonopoly package” was adopted which included a new mechanism for reconsidering determinations where relevant circumstances have changed. Under Part 11 Article 33 of No.135‐FZ Federal Law “On Protection of Competition” of 26th July 2005 (as amended), FAS or a market participant may apply to have the content or procedures for executing a determination reconsidered to reflect significant changes in underlying market circumstances. Shortly after implementation of the new provisions, InterRAO UES filed an application to reconsider that part of the determination requiring it to submit price‐taking bids. The application was supported by a collective petition from foreign investors including Enel OGK‐5, E.ON Rossia and Fortum, which argued that the price‐taking bid requirement could distort market signals for both generating companies and consumers of electric power. The Council of Electric Power Generators Non‐ Commercial Partnership filed a similar petition. FAS reviewed the case and drawing from analysis undertaken in cooperation with the Market Council decided to issue a revised determination. FAS’s revised determination No. AG/35061/12 of 29 October 2012 rescinded its previous behavioural requirements in relation to price‐taking bids while maintaining the other elements of the original determination. Source: FAS 2011 and FAS 2013c.

IEA experience also suggests that the objectivity and credibility of competition supervision can be greatly enhanced through transparent review processes incorporating effective public consultation. Such processes provide a way for key stakeholders to contribute information and insights that can serve to improve the quality of regulatory decision‐making, while also helping to build support and wider acceptance of regulatory decisions. Russian policy makers and FAS might consider ways to strengthen public consultation, including the potential to broaden stakeholder consultation and extend statutory review periods to provide sufficient time for more effective stakeholder consultation and consideration of contributions received.

Russian Electricity Reform 2013 Update: © OECD/IEA 2013 Laying an Efficient and Competitive Foundation for Innovation and Modernisation

Wholesale market arrangements

Currently wholesale electricity market arrangements are based separate markets for energy and capacity. Page | 26 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 market. The spot market is divided into two pricing zones. 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 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 (Kuleshov et al., 2012). 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. These nodes reflect the impact of network losses and congestion on power flows and trade. Spot prices are not subject to pre‐determined price caps or floors, but are closely monitored by FAS which has the authority to intervene to regulate wholesale prices where competition is considered insufficient to deliver an efficient pricing outcome. Wholesale prices, volumes and counterparties supplying regulated residential customers are regulated by the Federal Tariff Service (FTS). Market participants trading in the competitive wholesale market can enter into bilateral supply contracts, which must be registered with ATS and are treated as price taker volumes for the purposes of spot market settlement. The wholesale market also includes a balancing market and a recently established ancillary services market which are managed by the System Operator of the United Power System (SO UPS). The capacity mechanism includes two elements:  a series of bilateral contractual obligations (the Dogovor o Predostavleny Moshnosty or DPM mechanism) between incumbent generators and the Russian Federation to secure new incremental generation investments needed to meet projected adequacy requirements during the transitional period; and  a capacity obligation on retail entities and large volume users to enter into supply contracts for existing capacity offered through competitive capacity auctions. The DPM mechanism created a legally binding investment obligation on all parties that purchased or controlled generating assets following the 2007‐08 privatisation process. Under the DPM mechanism, contracting parties were originally required to undertake specific investments in new generating capacity within specified timeframes as prescribed by the Russian Federation between 2008 and 2012. In return, DPM arrangements provide a generous guaranteed rate of return through a capacity premium that initially delivered a return on investment of between 13% and 14% per annum (Russian Federation, 2010a). These contracts aim to 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. 138 thermal generating projects and six nuclear and hydro projects have been underwritten with DPM contracts, which are expected to deliver a net increase in installed capacity of 25.2 GW and 11.2 GW respectively by 2018 (Russian Ministry of Energy, 2012a). According to the Ministry of Economy, the projected net increase in generating capacity is considered sufficient to meet incremental demand growth

© OECD/IEA 2013 Russian Electricity Reform 2013 Update: Laying an Efficient and Competitive Foundation for Innovation and Modernisation until at least 20188. A market‐wide capacity mechanism has been introduced to deliver a return on capital for existing generating facilities. The model reflects elements of the capacity obligation mechanisms operating in the Northeast of the United States. It establishes an obligation on retail entities and large users sourcing power directly from wholesale markets to enter into capacity contracts with existing generators. An annual capacity auction market is operated by the SO UPS to facilitate Page | 27 contracting. Annual contracting is scheduled to be replaced with a four‐year forward capacity auction cycle from 2016 (Eurelectric & CIS EPC, 2012). In 2012 the market for existing capacity was divided into 27 separate trading zones reflecting network congestion and other technical constraints as shown in Figure 3 below.

Figure 3 • 2012 trading zones for existing generating capacity

Notes: The Federal Antimonopoly Service notes that this document was adopted upon the Order of the Ministry of Energy of the Russian Federation and published on the website of the System Operator of the United Power System. This map is without prejudice to the status of or sovereignty over any territory, to the delimitation of international frontiers and boundaries, and to the name of any territory, city or area. Source: Federal Antimonopoly Service 2012b In principle, the strike price for capacity contracts should reflect the system marginal capacity price determined competitively on the basis of the marginal offer that clears the market within each capacity zone. However, in 2012 prices were determined on a competitive basis in only three of the 27 capacity zones. Ine those thre zones, the system marginal price was set in effect by the penultimate bid, not the actual system marginal bid that cleared the market, resulting in a systemic reduction in capacity payments for all generators within these zones9. FAS set regulated price caps for the other 24 capacity zones where competition was considered too weak to deliver

8 raised during consultations with Ministry of Economy officials, April 2011. 9 Under the capacity auction rules, competitively determined system marginal prices are calculated after excluding the most expensive 15% of the plant selected through the auction process, effectively delivering a result consistent with the penultimate bid setting the system marginal price rather than the actual bid required to clear the market. See Barkin 2012 for details.

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an efficient and competitive outcome. As a result, just over half the generation capacity within the competitive wholesale market was subject to regulated capacity pricing (FAS, 2012b).

Wholesale energy markets Evidence suggests that the competitive wholesale spot market is one of the most successful Page | 28 components of the electricity reforms implemented to date. Energy prices have generally reflected movements in underlying supply‐demand fundamentals and short‐run marginal production costs, driven largely by changes in upstream fuel costs. Several stakeholders consulted during the course of this project supported this conclusion, suggesting that effective competition was driving efficient price formation in the wholesale spot market. A similar conclusion can be drawn from the correlation between changes in wholesale spot prices and underlying supply‐demand balances during the global financial crisis and subsequent economic slowdown of 2009, as reflected in Figure 4 below. Russian gross domestic product fell by around 8% in 2009 in the wake of the global financial crisis (IEA, 2011a). Falling domestic economic activity was reflected in a reduction in electricity consumption of around 4.6% in 2009. Annual average wholesale spot prices fell by 42 roubles per MWh, or around 5.9% over the same period, comparable with the reduction in demand. Spot prices remained at more moderate levels throughout the downturn and only began to rise as the economy and electricity demand began to grow again in 2010. By contrast, regulated electricity prices continued to rise over the period with annual average regulated prices increasing by 72 roubles per MWh, or around 17% in 2009.

Figure 4 • Wholesale electricity spot prices and traded volumes 2008 and 2009 Rub/MWh

708 666

January February March April May June July August September October November December 2008 demand 2008 average spot price

2009 demand 2009 average spot price

Source: ATS 2010 Notwithstanding positive outcomes to date, opportunities may exist to improve the efficiency and robustness of spot price formation by increasing the underlying competitiveness of the spot market. Several options could be considered to help improve spot market performance including:

 improving intra‐regional and inter‐regional market integration;  strengthening transparency and competition in upstream fuel supply markets;  reviewing price‐taker bidding restrictions, especially for reservoir hydro plant;  strengthening incentives for more efficient CHP participation in wholesale electricity markets; and Page | 29  improving system operation.

Regional market integration More effective regional market integration has the potential to deliver lower average electricity prices where it results in more efficient use of least cost generation. At present the wholesale spot market is divided into two pricing zones with limited transfer capacity and trade. Network and power flow restrictions are reflected in systemic price separation, with the Siberian price zone recording substantially lower annual average spot prices than the European Russia‐Urals price zone. Efforts to strengthen market integration through targeted investment in transmission capacity and technical capability required to support larger inter‐regional power flows, has the potential to significantly increase the liquidity, depth and competitiveness of spot price formation in both pricing zones. It may also result in a significant overall reduction in average annual wholesale spot prices on a national basis, depending on volume of inter‐regional flows and the relative impact of trade on marginal price formation in both pricing regions. However, it should be noted that greater regional integration can also result in wealth transfers from ‘lower priced’ regions to ‘higher priced’ regions, which may have wider macroeconomic and socioeconomic implications that would need to be carefully considered in the context of determining the appropriate degree of regional market integration. For instance, spot prices in the Siberian region may rise significantly with greater integration. The Russian Ministry of Energy estimates that fully integrating the European Russia‐Urals pricing zone with the Siberian pricing zone would result in a 15% increase in average wholesale electricity prices for Siberian consumers while delivering only a 1% decrease in average prices for European Russia‐Urals customers. In this case a broadly‐based benefit‐cost analysis may not support the development of a fully integrated, national wholesale spot market at this time, especially given the negative impact it may have for the competitiveness of energy‐intensive, export orientated industries which are substantial contributors to economic activity in the Siberian region. These and other related implications would need to be carefully weighed against the economic benefits of greater regional integration. Greater regional integration also has the potential to improve market flexibility, reliability and resilience at least cost by facilitating more efficient reserve sharing and more effective deployment of complementary generation technologies during periods when power systems are under stress or during emergencies. For instance, greater integration of the Siberian integrated power system which is dominated by hydro generators, with the power systems of European Russia, which are dominated by thermal generators, could help to strengthen security of supply in Siberia during periods of drought, while more effective integration of Siberian hydro power with European Russia could greatly improve the operational flexibility and resilience, enabling more effective management of power system security at least cost (IEA, 2005b). IEA experience suggests that greater power system integration has the potential to reduce the volume of reserves needed to maintain resource adequacy, effectively helping to ‘free‐up’ network and generation resources to strengthen competition and trade. More efficient use of existing resources can also serve to defer the need for expensive investment, which can further

Russian Electricity Reform 2013 Update: © OECD/IEA 2013 Laying an Efficient and Competitive Foundation for Innovation and Modernisation

reduce costs for consumers.

Upstream fuel supply transparency, flexibility and competitiveness Fuel costs are a key determinant of short‐run marginal costs for thermal generators, which generally set system marginal prices on the wholesale spot market. Access to competitively‐ Page | 30 priced gas supplies are of particular importance given that gas‐fired generators represent over 47% of total installed generation capacity and around 70% of total thermal generation capacity. Gas–fired generation dominates In Price Zone One, representing around 62% of generating capacity and over 85% of thermal capacity (Sberbank, 2012b). The Government has recognised the need for a more innovative and competitive upstream fuel supply sector and has introduced several initiatives to help improve downstream access to competitively‐priced fuel supplies including:  third‐party access to domestic gas transportation infrastructure;  encouraging new independent gas suppliers;  stronger competition supervision of domestic coal and gas markets; and  the introduction of a pilot gas trading exchange. Progress has been mixed. Efforts to encourage the development of independent gas suppliers have been among the most successful of these policies to date. Gazprom dominates the domestic gas market with just over 70% market share at present. However, independent gas suppliers are emerging rapidly. The total domestic market share of independent gas suppliers is forecast to reach nearly 30% in 2013, representing a near doubling since 2005. Strong growth is expected to continue for the reminder of the decade, with one investment bank forecasting that the domestic market share of independents could exceed 50% by 2020 (Sberbank, 2013a). Independent suppliers are dominated by Novatek and Rosneft, both of which control substantial gas reserves and a growing thermal generation customer base. By contrast, the pilot gas trading exchange which opened in 2006 was closed at the end of 2008. Despite several positive statements in recent years about reopening and expanding the scope of the exchange, a new gas trading exchange is yet to materialise10. Notwithstanding the recent inroads by independents, domestic gas markets remain regionalised and dominated by incumbents with considerable potential to influence market outcomes. Several stakeholders raised concerns about the competitiveness of upstream fuel supply markets for thermal generators, suggesting that a lack of effective competition was reflected in higher prices and less flexibility than might otherwise be expected in a more transparent and contestable marketplace. Particular concerns were raised about natural gas supply markets, especially the limited influence of competition on gas price formation and limited opportunity for some potential new entrants to access the domestic pipeline system on fair and reasonable terms. Some claimed this latter restriction represented an insurmountable barrier to the development of greater diversity of supply and competition in key domestic gas markets. Rising prices are also greatly affected by the program of tariff rebalancing which aims to increase domestic gas prices to export price parity on a knet‐bac basis by 2016. Gas tariffs were increased by 15% in July 2012 and immediately fed into electricity prices, with a 21% increase in spot electricity prices recorded in Price Zone One on a month‐on‐month basis (Sberbank, 2012b).

10 For instance, on 21 January 2013, Interfax reported that the Russian Ministry of Energy had asked Gazprom to help launch organised gas trading by September 2013 in cooperation with the Moscow International Commodities & Energy Exchange (MICEX) and St Petersburg International Mercantile Exchange (SPIMEX). It is envisaged that spot contracts would be the first product to be traded at a future Russian gas exchange but there are also plans to set‐up exchange trading of financial derivatives on gas. Volumes are likely to be limited at first to around 5% of domestic consumption.

Regulated domestic gas prices are expected to continue to grow at around 15% per annum over the next few years. Access to competitively priced fuel on fair and reasonable terms is a key pre‐requisite for minimising wholesale electricity prices over the longer‐term. Several possibilities exist to help improve transparency, flexibility and competitiveness of upstream fuel markets including: strengthening third party access arrangements, possibly including the introduction of regulated Page | 31 reference tariff services to support more informed and effective negotiations; improving transparency and access to spare pipeline capacity for third parties; and reopening the wholesale gas trading exchange, with sufficient liquidity and depth to support greater flexibility, transparency and more efficient price formation and risk management. Greater flexibility, especially in the terms and conditions for fuel supply, has the potential to significantly reduce fuel‐related operating costs for peaking generators and generators facing substantial seasonal variations in fuel requirements, such as combined heat and power plants, improving their commercial viability. Policy makers are encouraged to review existing arrangements with a view to strengthening and augmenting them where required to support the development of more transparent, flexible and competitive domestic fuel supply markets for thermal generators over the longer‐term.

Reviewing price‐taker bidding restrictions A relatively large volume of plant is currently dispatched on a price‐taker basis. Price‐taking plant represents up to 127 GW, or nearly two‐thirds of the total generation stock in the competitive wholesale market during the peak winter season. Over 65 GW of this capacity is nuclear and hydro plant, which is subject to permanent price‐taker status. Such plants are typically required to bid for dispatch in liberalised IEA electricity markets. Requiring these plants to bid for dispatch has the potential to nearly halve the volume of capacity currently receiving price taker status. This would have the potential to substantially increase the liquidity and depth of the merit order segment of the market, which could help to improve the efficiency of price formation and the effectiveness of price signals to help drive more efficient commercial behaviour. It could also help to strengthen liquid and depth in financial markets by increasing the number of trading counterparties and volume of trade, especially if the wholesale market develops towards an energy‐only model. Creating strong commercial incentives for timely and efficient deployment of hydro resources is particularly important in this context. Power systems are inherently volatile reflecting the unique characteristics of electricity11. Liberalised power markets generally reflect this inherent volatility in the wholesale price formation process, creating a strong price signal and financial incentive to develop and deploy the operational flexibility of power systems. Hydro facilities, particularly reservoir based hydro plants, currently represent the most flexible and cost‐effective technology available to manage this volatility. Leading practice liberalised power markets among IEA member countries have increasingly seen hydro facilities providing higher value adding services including balancing, peak power and related financial hedging and insurance products, that reflect the commercial value of flexibility and ensure that this flexibility is effectively deployed to deliver power system reliability and to clear markets at least cost. Regulatory and market arrangements should aim to facilitate the efficient and responsive development and deployment

11 Electricity possesses a unique combination of properties including: electricity generally can’t be cost effectively stored meaning there are few if any inventories with which to balance supply and demand; supply and demand must be balanced in every moment and in every location simultaneously to avoid catastrophic blackouts; demand is generally inelastic in the balancing (instantaneous) timeframe; and additional production capability is limited by technical restrictions including hard capacity constraints and ramp up/down rates.

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of hydro facilities to the greatest extent possible. However, there are likely to be a range of technical and operational limitations affecting hydro electric generation that may limit responsiveness to price signals in practice, including the volume of water storage, the degree to which units are embedded in a larger run‐of‐river hydro system, and a range of operational restrictions reflecting agricultural, environmental and Page | 32 recreational entitlements. In addition, there are likely to be a range of system security and management requirements that would need to be addressed. The potential benefits of dispatch based on more independent, decentralised decision‐making would need to be carefully considered in this wider context. Russian policy makers may wish to consider the potential for extending bidding for dispatch to some or all of this capacity, especially reservoir hydro plant which can have a critical role in promoting efficient marginal price formation due to the technical flexibility of this technology. Relaxation of price‐taker restrictions should be considered as part of an integrated strategy to increase private diversity of ownership and participation in the competitive wholesale market, as discussed under wholesale market structure above.

Encouraging more efficient CHP participation in wholesale electricity markets Combined heat and power (CHP) plants are a key resource in the Russian electricity system, representing around one‐third of total generating capacity. They also provide an essential district heating service, which affects their participation in the wholesale electricity market, especially during the winter months12. Much of the CHP fleet is old and operating at relatively low levels of technical efficiency. Considerable potential exists to modernise the CHP fleet which could deliver a range of benefits including: more efficient and cost‐effective production of electricity and heat; lower electricity network losses and transportation costs given the generally close proximity of CHP to load; potentially lower overall generation investment requirements, reflecting the relatively high technical efficiency of modern CHP facilities; and lower electricity prices. These benefits are reflected in the Government’s ambitious modernisation objectives for large‐scale CHP contained in the General Scheme for the location of electricity installations (Russian Federation, 2008). Market participants are exploring ways to realise this potential. For instance, the Fortum Corporation is undertaking a pilot program to modernise its CHP facilities serving Chelyabinsk. The project involves converting one of the existing steam turbines into a modern combined cycle gas turbine (CCGT) of around two‐thirds the capacity of the original unit. The conversion is expected to deliver a three‐fold increase in effective output, which will enable Fortum to decommission the other obsolete units while meeting current heating and electricity demand. If successful, Fortum intends to extend the program to modernise all its CHP facilities. Cost‐ reflective prices that yield competitive rates of return and sufficient flexibility for CHP owners to commission and decommission capacity will be needed to facilitate further efficient and innovative responses of this kind to help realise the Government’s modernisation goals in a timely and cost‐effective manner. However, regional regulation of the heating sector has distorted incentives for efficient operation and development of CHP facilities. To date, more expensive heating boilers owned by local authorities have usually been given priority for heat production with CHP used to balance local heating systems. Higher costs are equalised across heat producers through cross‐subsidies from more efficient and lower cost CHP to less efficient and higher cost boilers. As a result, boilers have delivered an inefficiently high

12 CHP plants are added to the priority dispatch list during the winter period. Any electricity they produce receives the system marginal price from the wholesale spot market.

© OECD/IEA 2013 Russian Electricity Reform 2013 Update: Laying an Efficient and Competitive Foundation for Innovation and Modernisation proportion of heat production while CHP heating capacity in some cases is underutilised. This cost shifting distorts CHP heat production, affecting operational efficiency, heating revenues and electricity production. Some stakeholders noted that regulated returns from heat production are insufficient to cover related costs for most CHP plants and that this affects decisions around generating electricity, which in turn affects the efficient operation of wholesale electricity markets. In addition, revisions to the methodology for calculating electricity‐related capacity Page | 33 payments from payments based on installed capacity to payments based on available capacity has the potential to further erode CHP cash flows, magnifying any revenue shortfalls13. Russian authorities are aware of the need to reform the regulation and operation of the heating sector and to address anomalies that may distort operational or investment responses affecting efficient CHP participation in the electricity and heating sectors. A comprehensive law to transform the operation and regulation of the heating sector was passed in 2010 (Russian Federation, 2010b). However, the related rules and regulations required to operationalise the law are still being developed. At the time of writing, 16 of the expected 30 regulatory instruments had been finalised. The October 2012 announcement of rules for determining regulated heating tariffs represents an important and very positive step. Among other things, the new rules apply Regulatory Asset Base (RAB) regulation to heating network infrastructure and introduce incentive regulation for heat producers with tariffs capped against a benchmark reflecting the cost of supply from a ‘best‐in‐ class’ heat‐only boiler. This approach can serve to strengthen incentives to deploy CHP units over expensive boilers and is expected to ultimately encourage the retirement of the most expensive and inefficient boilers from the heating sector and investment in more efficient CHP technologies. It could also allow CHP plants to receive a more cost‐reflective return on heat while reducing, and possibly eliminating, cross‐subsidisation over time. The Resolution will come into full force from 2014. The target model for the heating sector is consistent with the approaches currently adopted in several Northern European countries and could open the way for a limited form of heat supply liberalisation focusing on larger‐volume customers in the longer‐term, based on bilateral supply contracts with prices moderated by the threat of substitution. Introduction of more cost‐ reflective pricing for residential heat consumers will need to be carefully handled with price rises linked to capacity to pay and possibly supported by government‐funded community service obligations similar to the ‘social norm’ proposed for the electricity sector. More effective metering would support the introduction of more cost‐reflective pricing by allowing residential consumers to verify that they are only paying for heat they consume. Overall, the reform package has the potential to deliver more cost‐reflective, long‐term heating tariffs, which several stakeholders consider a precondition for promoting efficient CHP participation in the wholesale electricity market. Russian policy makers and regulators are encouraged to move quickly to develop and implement the remaining rules and regulations required to operationalize the heating sector reforms, and to do so in a way that encourages more efficient CHP participation in the electricity and heating sectors, and timely and efficient modernisation of CHP facilities.

Improving system operation Transparent and objective system operation is needed to deliver efficient dispatch and network operation that supports competitive and efficient wholesale market outcomes. A range of

13 Sberbank estimates that around 16% of CHP capacity is no longer eligible for capacity payments based on using an available capacity methodology. See Sberbank 2012b for details.

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concerns were raised by stakeholders about certain aspects of system operation. Some stakeholders noted a lack of transparency around system security interventions affecting power flows and dispatch and the rationale for such interventions. Similar concerns were raised around the management of capacity reserves, particularly in relation to the ‘forced’ capacity reserve. It was suggested that an unduly conservative approach to reserve management may be resulting in Page | 34 tighter supply‐demand balances, higher ancillary services costs and higher wholesale prices in some regions than is warranted. Other stakeholders suggested that the system operator’s focus on reliability combined with system modelling and dispatch engine limitations were resulting in unduly conservative dispatch and power flow regulation that could be contributing to effective network congestion, reducing the potential for intra‐regional and inter‐regional trade and competition. It was suggested that system operators had little incentive to manage the power system in a manner that maximises capacity available for trade and that more transparency and accountability is needed to improve the efficiency and effectiveness of system operation. Market participants have raised similar concerns about system operation in IEA jurisdictions. System management practices are receiving greater scrutiny from market participants in liberalised electricity markets, given that commercial interests are directly affected by system operator interventions. Market participants in IEA jurisdictions have raised questions about the transparency, objectivity, costs and legal liability associated with system operation. In response, policy makers and regulators have sought to bring greater transparency and accountability to system operation. In general, well‐functioning wholesale electricity markets have a key role to play in this context by encouraging more flexible and responsive use of the power system, which has the potential to complement system operator management by reducing pressures on system resources at times when systems are congested and operating at or near their security limits. In addition, leading practice IEA jurisdictions have also sought to address these issues through the introduction of markets for the procurement of certain ancillary services. At present, market‐based methods typically involve open tendering and bilateral contracting processes. Some employ more dynamic market mechanisms that incorporate regular auction processes, particularly for the procurement of frequency control ancillary services and capacity reserves. Prices are set on the basis of competitive bids, with the marginal bid setting the system price for a particular trading period. In other cases, auction processes use cost‐based regulated prices where competitive pressures are considered too weak to produce efficient bilateral or system marginal prices. Cost recovery is typically averaged across users through some form of general charge or as part of the fixed component of transmission charges. To date, market‐based mechanisms have resulted in more efficient, innovative and better targeted provision of power system security at least cost, and helped improve the flexibility and efficiency of system security management. Commercial arrangements have led to a substantial reduction in the overall cost of ancillary services for maintaining transmission system security in United Kingdom, United States, Scandinavia, Germany and Australia (IEA, 2005b). In Russia, SO UPS launched a bilateral ancillary service market in 2010 which it uses to procure frequency control ancillary services including automatic generation control and spinning reserve services. The market currently targets thermal generators. Hydro generators are obliged to provide these services. Services are secured through bilateral contracts where the system operator undertakes to pay maintenance costs in exchange for the right to call on the counterparty generator to operate whenever required, even if at a loss. Market volumes are growing. SO UPS plans to purchase around 1 000 MW of frequency control regulating services in 2013, while in 2014 it plans to increase market‐based purchases to covers all it anticipated primary frequency control

© OECD/IEA 2013 Russian Electricity Reform 2013 Update: Laying an Efficient and Competitive Foundation for Innovation and Modernisation requirements; representing between 1 200 and 1 500 MW or around 3% of total load. Opportunities to extend market‐based approaches for purchasing ancillary services should be examined. For example, market‐based procurement could be expanded to include a wider range of ancillary services, such as more effective coverage of network control ancillary services. Potential may also exist to use more dynamic market‐based models, like wholesale spot market auctions, which have the potential to substantially improve flexibility and efficiency by more Page | 35 closely aligning resource procurement with real‐time requirements. Another possibility may involve moving toward cost allocation based on the causer‐pays principle. Substantial benefits may also be achieved from more effective harnessing of demand response. Demand reductions in response to high prices are likely to occur when power systems are operating close to their security limits. Such responsiveness would help reduce pressure on spot prices, while potentially strengthening system security and reliability by improving power system flexibility to balance generation and load. Demand response issues are discussed further in the retail market development chapter. Russian policy makers, regulators and system operators could consider ways to extend market‐ based procurement of ancillary services to help reduce costs and improve market efficiency. Consideration could also be given to reviewing the power system management, modelling and situational awareness capabilities of system operators, with a view to upgrading system operation capabilities, as required, to help improve power system operation and performance at least cost.

Wholesale capacity markets By contrast with wholesale energy markets, experience to date with the wholesale transitional capacity mechanism has revealed some significant shortcomings. In particular, the lack of flexibility and additional costs associated with the highly prescriptive DPM investment mechanism became evident during the economic downturn following the global financial crisis. Demand forecasts underpinning the DPM investment program were no longer valid in the wake of the global financial crisis, resulting in a substantial overstatement of incremental investment requirements. However, the DPM mechanism didn’t incorporate sufficient flexibility to quickly and easily adjust the timing and volume of mandated investment. As a result, investment proceeded well ahead of when it was needed. Investors had little incentive to respond to changing market conditions as most of the risks and costs associated with these investments were effectively transferred to the Government through the guaranteed payment mechanism, and ultimately to taxpayers or rate payers through higher charges. The Government responded to these developments by entering into agreements with some contracting parties to delay particular projects by up to three years, but in several cases projects were underway and little could be done. It is impossible to say how investors might have responded to an unexpected shock of this magnitude in Russia if they had been subject to more flexible and dynamic market‐based incentives and investment arrangements. All markets have experienced some losses and extra costs from what proved to be poorly timed incremental investments as a result of these events. However, in leading liberalised IEA electricity markets changes in incremental electricity demand were quickly reflected in falling spot and forward contract prices, encouraging investors to move quickly to delay or deferred investment plans, where possible. This contrasting experience suggests that a less prescriptive and more market‐based approach may have delivered a more efficient and timely investment response and outcome. In addition to concerns about the efficiency and flexibility of these arrangements, several other concerns have emerged with DPM and with the capacity market for existing generation.

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According to various stakeholders, the DPM and capacity mechanism:  over‐rewards new investment and inefficient, expensive ‘must have’ plants retained for system security and reliability requirements;  under‐rewards existing plant, especially peaking plant, delivering revenues that are below commercial rates of return and which according to one analysis have not grown in real terms Page | 36 since liberalisation;  unduly restricts plant retirements and efficient exit from the market;  reduces the scope of competitive sourcing of new plant and new entry by prescribing the volume and timing of new investment and allocating its provision to incumbents through guaranteed DPM contracts, possibly at the expense of more efficient, innovative and least cost alternatives;  discourages efficient investment in renovation, upgrading and refurbishment of existing plant which has the potential to meet incremental investment requirements and modernisation objectives at least cost;  locks large consumers into supply agreements that unduly restrain operational flexibility and freedom of customer choice;  ‘crowds out’ the development of potentially more efficient market‐based options based on bilateral capacity contracts;  delivers higher overall system marginal prices than is warranted, and excessive infra‐marginal rents for some generators, as a result of incorporating separate system marginal pricing for energyd an capacity; and  employs inefficiently sized capacity pricing zones that have the potential to entrench capacity price regulation over the longer term. In summary, current arrangements could be described as essentially delivering a form of central planning that is ultimately incompatible with the policy goal of developing efficient, innovative and dynamic electricity markets reflecting the commercial choices of many individual buyers and sellers. Russian policy makers are aware of the shortcomings of the existing capacity mechanism and are developing options that could help to increase its transparent and competitiveness. Although work is progressing to address many of these issues, it is likely that some may not be fully resolved before the next major increment of generating capacity is required. If this is the case then transitional arrangements may need to be extended beyond 2018, with the objective of introducing fully competitive arrangements once the key transitional issues have been resolved. In the interim, there appear to be several opportunities to refine existing arrangements including:  further integrating trading zones for existing capacity to strengthen the underlying level of competition to supply capacity;  strengthening market‐based arrangements for securing capacity using bilateral contractual mechanisms, possibly supported by longer‐term forward capacity auctions and the development of secondary capacity trading arrangements; and  removing undue legal and regulatory barriers to more innovative investment responses, including renovation, refurbishment and retirements, driven by independent decentralised decision‐making.

Integrating capacity zones The case for rationalising the number of capacity market zones of free flow appears compelling.

As noted previously, in 2012 there were 27 separate capacity zones, effectively resulting in 27 separate regional capacity markets. The highly fragmented nature of the capacity market is reflected in a highly concentrated market structure, with around 20 of the current zones recording HHI scores of around 5 000 or above, which is indicative of very high levels of concentration consistent with the presence of substantial market power (Porohova, 2010). As a result, market clearing on the basis of competitively determined capacity prices occurred in just Page | 37 three of these zones in 2012. Policy makers and regulators have recognised this issue and are in the process of reducing the number of capacity zones. In 2013 it is proposed to reduce the number of free flow capacity zones from 27 to 23, with market clearing expected to be determined on the basis of competitive bidding in five of these zones, representing nearly 60% of total generating capacity available for auction. FAS has advised that the ultimate goal is to substantially reduce the number of capacity zones, possibly down to four by around 2020. One possible configuration is shown in Figure 5.

Figure 5 • Potential wholesale electricity capacity trading zones by 2020

Notes: The Federal Antimonopoly Service notes that this map presents one of several different possible configurations developed on the basis of calculations made by the System Operator of the United Power System. This map is without prejudice to the status of or sovereignty over any territory, to the delimitation of international frontiers and boundaries, and to the name of any territory, city or area. Source: Federal Antimonopoly Service 2012b. Further aggregation of the trading zones for capacity has the potential to greatly improve the depth of competition in capacity markets. Consolidation could serve to increase the volume and liquidity of capacity markets, which could also support the development of more decentralised forms of capacity trading based on bilateral contracting, and eth development of more sophisticated derivative markets for capacity that could facilitate more efficient risk management and least cost capacity provision over time. As noted previously, investments to address critical points of persistent congestion or technical limitations in the transmission network which prevent greater aggregation are proceeding and need to be pursued as a matter of priority.

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Developing more competitive capacity markets IEA experience with capacity mechanisms and markets has been mixed to date. They have proven to be effective in addressing the ‘missing money’ problem created by unduly low wholesale price caps or where regular re‐dispatch by system operators is not properly reflected in wholesale price formation. They have also proven effective in securing investment during the transitional Page | 38 period while market‐based reforms are being implemented and related policy and regulatory uncertainty that could delay timely and efficient investment responses remains high (Ishii & Yan, 2004). Capacity mechanisms have also proven useful to strengthen investment incentives where concerns over the capacity of wholesale price signals to attract sufficient, timely investment persist, such as in small, isolated power systems or in energy constrained power systems, such as those dominated by hydro power where droughts periodically limit production creating shortages and high prices that may not be translated into an investment response14. Capacity mechanisms are currently being considered by several European countries as a means of ensuring timely and sufficient investment in ‘back up’ generation to support the large‐scale introduction of variable renewable generation to meet decarbonisation policy goals. This is essentially a variant of the ‘energy constrained’ situation that can apply in heavily hydro‐ dominated power systems. Box 3 provides a summary of capacity mechanisms currently deployed among IEA member countries. However, IEA experience with capacity mechanisms has also raised a range of concerns. Capacity mechanisms have been criticised for providing poor incentives for investors and for being susceptible to manipulation. They have led to inefficient and inappropriate investment, including over‐investment. They have the potential to ‘crowd out’ more innovative and efficient responses to peak prices, like demand response. In some cases, poorly defined triggers have inappropriately released capacity into the market, creating uncertainty that further distorts efficient market operation and investment decisions. The European Commission recently highlighted similar concerns. It encouraged Member States to fully analyse the reasons for a lack of generation investment, to consider alternative remedies including demand response and increasing inter‐ regional trade, and to consider the impact on neighbouring states and the efficient development of the internal electricity market before introducing a capacity mechanism (European Commission, 2012a). Russian policy makers could consider IEA experience in the context of refining the existing capacity mechanism, perhaps drawing on the more successful approaches emerging among IEA members such as the forward capacity models adopted in the North‐Eastern United States. In particular, priority could be given to strengthening the bilateral contractual framework for securing capacity, with a view to encouraging greater reliance on market‐based capacity procurement driven by independent and decentralised decision‐making in response to competitively determined prices. Such a framework can encourage more efficient, innovative and timely capacity management and investment responses that deliver efficient modernisation of the sector while maintaining reliable electricity services at least cost. Recent reports suggesting that the revised energy market model currently being developed will seek to expand the use of competitive bilateral contracts to support more cost‐effective and innovative capacity procurement are encouraging (Sberbank, 2013b).

14 In such situations, price signals may not necessarily elicit appropriate new investment, since the underlying capacity to meet peak demand under “normal” rainfall conditions already exists. The argument in favour of using a capacity mechanism, at least for operating reserves, is strongest for isolated and hydro‐dominated power systems, like New Zealand.

A bilateral contractual framework could be supported by the development of secondary trading platforms and related physical and financial derivative products, to help reduce trading transaction costs, inform efficient and timely price formation and decision‐making, support more efficient risk management, and improve market flexibility. The combination of an effective bilateral contractual framework and trading arrangements could help accelerate the development of more effective capacity markets and enhance market‐based responses. The Page | 39 proposed introduction of four‐year forward contracting from 2016 could be a positive step in the development of market‐based bilateral contracting and related trading arrangements, especially where it delivers greater transparency, certainty, liquidity and depth to help reduce transaction risks and costs.

Box 3 • An overview of capacity mechanisms deployed among IEA countries

Capacity mechanisms exist in a range of different formulations, but at their base they involve the system operator determining capacity requirements based on supply‐demand balance forecasts, then creating a revenue stream for required additional capacity. The objective of these mechanisms is to deliver a timely and sufficient quantity of incremental capacity at prices that reflect fair value. Further benefits often claimed include that end‐user prices should be less volatile, and that a steadier stream of revenue should reduce the risk of boom‐bust investment cycles. Payments made to support marginal capacity resemble derivatives that are commonly traded bilaterally in parallel to energy spot markets. When a systems operator or Load Serving Entity (LSE) purchases a capacity contract they are generally purchasing the right (but not the obligation) to purchase output at a given price in the future – akin to an energy ‘call option’ contract. Such contracts can be physical or financial, meaning that they can relate to the delivery of the underlying energy, or merely to the cost of the underlying energy on the wholesale market. The purchaser of the derivative is paying a premium to limit its exposure to a lack of capacity or very highly priced capacity. The seller of the derivative is generally earning a return on an investment even when there is a risk that the investment in question will remain unused. A number of models exist for capacity mechanisms. In Spain, the regulator intervenes to set an administered price for capacity and generators have the option as to whether they will offer capacity to benefit from these payments in lieu of payments they receive on the main wholesale market. Similar to the premium associated with a call option, the generator receives the capacity payment regardless of whether the capacity is run. The price is determined based on estimates of the cost of new plant and is not strictly linked to a mandated reliability target. Administered capacity prices do not rely on market mechanisms to determine price, rather it is determined by the central regulator, which means that pricing can deviate substantially from efficient pricing, particularly when the market is illiquid. The administered price for capacity allows the regulator to limit payments to a certain type of capacity (for example, plant that would otherwise be retired or new plant). In Spain, payments are limited to new plant or significant upgrades to existing plant. The cost of payments is recovered through a general volume‐based uplift on all consumption. In addition to strategic reserves maintained by some Nordic countries, each TSO in Nord Pool also operates a market for options over operational reserve. The system was developed partly in response to the unique energy mix of the Nordic region which incorporates a large volume of hydro‐ power, meaning that in certain years of low rainfall the supply demand balance can be very tight. Under these operational reserve arrangements, the system operator can purchase a right (but not an obligation) to operate capacity at a given point in the future that is binding on the seller. Generators can opt to bid their capacity into the operational reserve market when the price in that market is higher than the price in the main wholesale market, thereby maintaining returns on investment in marginal capacity in periods of lower demand. Industrial users of energy can also bid in loads that they agree to curtail at times of peak demand in return for a premium payment. The cost of the capacity payments are spread across all users.

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Box 3 continued In markets that do not rely on strategic reserve capacity or short term operational reserves, regulators sometimes set a target level of reliability and then create an obligation on load‐serving entities to fund the incremental investment. Key defining features of these arrangements include: Page | 40 whether capacity is to be made available following a short or long time delay (from weeks up to several years), and whether LSEs are required to acquit their obligations solely through their own resources and bilateral contracting, or can also rely on a centralised market operated by the system operator. In United States power markets that remain regulated, utilities are typically required to meet medium term reliability obligations through their own resources and bilateral contracting. In many liberalised markets centrally organised capacity auctions allow LSEs to purchase capacity as well as relying on their own resources and bilateral contracts. In the latter instance, the existence of a central market for capacity can facilitate more efficient price discovery in bilateral contracting. For example, regulators and system operators managing markets covering New England and the PJM Interconnection (PJM) target a level of reliability and operate centralised markets for forward capacity. The capacity market is a forward market in that the regulator sets a desired level of reliability, then projects extra capacity required three years in advance to meet this standard (the standard is expressed as a probability of lost load of 0.1 days a year). LSEs are required to pay ISO’s for the capacity purchases in proportion to each LSE’s share of the peak load reached in the preceding year. LSEs that have enough of their own resource or bilaterally contracted capacity to meet the reliability requirements can net this off against their payment obligations. LSEs that fail to meet their obligations for acquiring load are penalised, at a rate per megawatt of capacity consistent with the cost of new entry. The penalty is designed to make contracting for new investment or demand response more attractive than paying the penalty. The auctions for forward capacity managed by the New England Independent System Operator (NE ISO) and PJM use descending price auctions that find the lowest price for the pre‐determined level of capacity, that is, they set the quantity required and allow the market to find a price. Price caps and floors are administered relative to a number of inputs, including the estimated price of new entry and the need to limit the exercise of market power. In an instance where existing capacity is projected to be inadequate to meet demand in three years’ time then the cost of generating units that are yet to be constructed will set the marginal price in the auction, ensuring that prices reflect the fixed and variable costs of new generation, while providing infra‐marginal returns to existing generators that are surplus to current needs. Prices in NE ISO and PJM are also determined on the basis of locational marginal prices at specific locations within the network, reflecting the existence of import‐ constrained nodes and sub‐regions, and to encourage fresh investment where it is most needed. In contrast to NE ISO and PJM, several centralised capacity markets operate for delivery in the same period (for example the market operated by the New York Independent System Operator and the South West Interconnected System market in Western Australia). However, a number of benefits accrue to a forward market for capacity, including: giving investors time to deliver additional generating capacity, allowing the system operator an opportunity to acquire extra resources when LSEs are non‐compliant, and also allowing new entrants an opportunity to participate in the capacity market in advance. In forward capacity markets subsidiary options are frequently held in the year of delivery to allow LSEs to adjust capacity commitments in response to changes in circumstances. Pricing forward capacity annually provides incentives for LSEs to enter into long term forward bilateral commitments that hedge capacity costs relative to spot market prices. Source: Regulator and system operator websites from related control areas and jurisdictions.

Consideration could also be given to several complementary reforms which have the potential to support more efficient, innovative and least cost capacity market outcomes. In particular, returns on investment need to be sufficient to retain efficient generators and attract efficient capital. Any restrictions that unduly limit potentially efficient, innovative and least cost investment responses could also be reviewed. Several stakeholders noted that current arrangements discourage efficient and timely refurbishment projects and retirements. Refurbishment has proven to be a

© OECD/IEA 2013 Russian Electricity Reform 2013 Update: Laying an Efficient and Competitive Foundation for Innovation and Modernisation least cost and efficient means of modernising generation stock and has been a commonly observed primary investment choice in liberalised electricity markets. Russian policy makers should identify any rigidities that might unduly discourage efficient, timely and innovative investment responses and consider how best to address them. Over the longer term, options may exist to gradually replace the transitional capacity mechanism with an energy‐only model for mainstream generation investment and a capacity mechanism for Page | 41 procuring operational reserves. Key pre‐requisites for an effective energy‐only model are discussed in the next section. Operational reserves have public good characteristics and therefore may require additional financial inducements to elicit an appropriate investment response. The strategic capacity reserve models operating in the Nordic region could be considered in this context. For example, in Sweden the transmission system operator (TSO) purchases strategic reserve capacity. Under this model, the regulator sets a margin of reserve capacity required and then the TSO contracts for this capacity in the competitive market. Capacity release is triggered when commercially available supply is insufficient to clear the market. Under these circumstances the TSO can release its reserve capacity to meet unserved demand. The price level at which the extra capacity is dispatched is set Euro 0.01 above the bid of the last market generator dispatched, while the cost of procuring the capacity is allocated across the market. Further information is provided Box 4 below.

Box 4 • An overview of the Swedish strategic capacity reserve model

Under the Act on the peak load reserve Svenska Kraftnät has a responsibility to ensure that a peak load reserve of up to 2 000 MW is available during the winter period. The Ordinance (2010:2004) states the amount to be procured every winter. The type and number of facilities to be included in the peak load reserve depend on the contracts and varies from year to year. For the time horizon to 2020, the peak load power reserve should not exceed the following capacities:  2011‐13: 1 750 MW with a 25% demand reduction;  2013‐15: 1 500 MW with a 50% demand reduction;  2015‐17: 1 000 MW with a 75% demand reduction; and  2017‐19: 750 MW with a 100% demand reduction. Every year, Swedish TSO Svenska Kraftnät can procure reserves for the winter periods between 16 November to 15 March through auctions and commercial bids on the Nordic day‐ahead market, Nord Pool Elspot. The owners of the reduction bids may choose to offer their resources to Elspot. If they are not traded on Elspot, owners are required to enter bids on the balancing power market. Activation of the production bids can occur when the supply and demand curves on Elspot do not meet. The bids are activated only after all the commercial bids are activated and then to the price of the highest commercial bidder plus 0.1 euro per MWh (the minimum price step for bids on Nord Pool Spot). As a lower price limit for the activation of the peak load reserve, there is a minimum price specified. Svenska Kraftnät can activate resources after the closing of Elspot. This is the most common way of activating the peak load reserve. The price is the minimum price specified in the contract between the resource owner and Svenska Kraftnät. Svenska Kraftnät recently changed the management of the demand reduction of the power reserve as a result of new legislation. The procurement of consumption reductions will only cover bidding on the balancing market and the management of the consumption reduction resources shall also permit plant owners to make their own bids for the resource to the Elspot market. If the resource is not activated on the spot market, it will remain at the disposal of the balancing power market. As resources are made available as bids on the spot market, they participate in the price formation. Source: IEA 2013, Box 8, p126

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Toward a long‐term wholesale market model

The Government is examining options for securing investment beyond 2018, with the intention of moving to a more market‐based approach that will deliver more efficiently timed, sized and well located investment, operational and end‐use outcomes at least cost. Achieving these Page | 42 outcomes will involve moving from the current centrally planned and closely regulated approach towards more liberalised arrangements where generation investments are undertaken by independent decentralised decision‐makers in response to incentives created by cost‐reflective and competitively determined prices. Options under consideration include replacing the current energy and capacity model with an energy‐only wholesale market model. Concerns have been raised about the ability of energy‐only wholesale market models to attract sufficient, timely investment and about the volatility of related wholesale spot prices. These concerns were among those that led policy makers and regulators in United States north‐eastern markets to adopt wholesale models with separate energy and capacity .markets However, IEA experience suggests that a well‐functioning energy‐only market can provide an effective means of delivering the efficiently timed, sized and well located generation investment needed to develop a competitive, dynamic and innovative electricity sector at least cost, and that it can do so with moderate price volatility that reflects underlying supply‐demand fundamentals. For instance, the Australian National Electricity Market (NEM), which employs a gross pool spot market mechanism similar to the one used in Russia’s wholesale energy market, has delivered efficiently timed, sized and well‐located generation investment for the last decade using an energy‐only wholesale market model. Figure 6 shows growth in incremental peak demand and dispatchable generation capacity in the Australian NEM over the period since market start, while Box 5 summarises the key features of the NEM.

Figure 6 • Peak demand and generation growth in the Australian national electricity market: 1998‐2011

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Note: Forecast peak demand is based on projections published by AEMO for a period two years in advance. Source: AER 2011. Figure 6 shows a close load‐following correlation between growth in incremental peak demand and growth in new dispatchable generating capacity. An additional 12.4 GW of new dispatchable generating capacity was added to the market, representing a 37% increase in total generating capacity over the period. Incremental growth in capacity closely matched growth in peak

© OECD/IEA 2013 Russian Electricity Reform 2013 Update: Laying an Efficient and Competitive Foundation for Innovation and Modernisation electricity demand, which grew by 35.8% over the same period. New investment in dispatchable generating capacity is driven by independent decentralised decision‐making in response to price signals from the wholesale spot and forward financial contract markets. The market demonstrated the capacity to respond quickly and effectively to changes in demand to maintain adequate and reliable electricity services at least cost. Furthermore, responses to cost‐reflective wholesale prices have delivered increasingly timely, innovative and effective operational and Page | 43 end‐use outcomes that have supported efficient market operation and development.

Box 5 • Key features of the Australian national electricity market

The Australian National Electricity Market (NEM) is a wholesale market through which generators sell electricity in eastern and southern Australia. All generators that are registered to provide supply in the market must sell through the central pool. Wholesale trading is conducted through a spot market where supply and demand is instantaneously matched in real‐time through a centrally‐coordinated dispatch process. Only energy is sold in the market, with no payments made for providing capacity. The main customers are energy retailers, which bundle electricity with network services for sale to residential, commercial and industrial energy users. Generators offer to supply the market with specific amounts of electricity at particular prices. Offers are submitted day‐ahead and can be modified through rebidding procedures up to five minutes before dispatch, eliminating the need for a separate intra‐day market. From all offers submitted, the market operator determines which generators will run based on the principle of meeting prevailing demand at lowest cost, building a ‘bid stack’ from the cheapest energy source towards the more expensive, which is used to determine the system marginal price paid to all generators that are dispatched. A further feature of the NEM is that the energy market is ‘co‐optimised’ with the market for ancillary services (services required to ensure the stability of the power system, and facilitate its recovery). This means that the dispatch algorithm for calculating market outcomes ensures that energy demand and stability requirements are jointly met at the lowest cost. Prices and demands are averaged over a half hour trading period and settlements are made against metered volumes. Demand forecasting, bids, settlements, and supply and demand balancing are all carried out by the independent market and systems operator, the Australian Energy Market Operator (AEMO). There is a cap on wholesale spot prices of AUD 12 500 per MWh. In the NEM, the price cap is set at a level designed to meet an exogenously determined reliability standard of 0.002% of un‐served energy in a year. Prices over AUD 500 per MWh are only rarely reached but at these times marginal generators are able to recoup contributions towards their fixed costs. There is also a price floor of AUD 1 000 per MWh, which can be reached in periods of very low demand and/or high renewable generation, when generators of base load power bid in at negative prices in order to remain on line. While the NEM is a gross pool, where all electricity bought and sold must be cleared through the spot market, an active market in financial derivatives also exists, allowing buyers and sellers of wholesale electricity in the NEM to manage their exposure to volatile spot prices. Financial products, such as contracts for difference, provide predictable cash flows based on an agreed ‘strike’ price. The party that wishes to set the strike price typically pays a premium to the counter party, reflecting the risk that the market will turn against the counterparty, as well as a degree of credit risk. Financial entities such as hedge funds and banks also take positions in these markets, providing further liquidity and depth. Source: AEMO 2010 and AER 2011.

At the same time, wholesale spot prices have exhibited moderate volatility, with annual volume‐ weighted average spot prices typically ranging between AUD 30 per MWh and AUD 60 per MWh since 2007‐08 in the major zonal markets of New South Wales, Victoria and Queensland. The frequency, duration and impact of price volatility is more clearly seen in Figure 7 which shows volume‐weighted average wholesale spot prices on a weekly basis for these regions over the same period. This figure shows that weekly average wholesale spot prices tended to range within a relatively narrow band of between AUD 20 per MWhD to AU 70 per MWh.

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Figure 7 • Weekly volume‐weighted average wholesale spot prices for key regions in the Australian national electricity market: 2007‐2012

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Source: IEA analysis based on AER 2009, AER 2011 & AER 2012. On only 14 occasions did average weekly spot prices exceed AUD 100 per MWh in New South Wales and Queensland, representing less than 5% of the weekly intervals over the period. While in Victoria, average weekly spot prices exceeded AUD 100 per MWh on just 13 occasions, representing around 4.5% of the weekly intervals over the period. According to the Australian Energy Regulator, these pricing peaks generally reflected tightening supply‐demand fundamentals caused by a combination of extreme peak demand and network or generation outages. In some instances they also reflected opportunistic generator bidding behaviour. However, on no occasion were peaks in weekly spot prices driven solely by strategic bidding behaviour, reflecting the inability of any generator or group of generators to effectively exercise market power on a systemic basis (AER, 2011). However, IEA experience indicates that there are some key pre‐conditions that need to be met for energy‐only markets to deliver the desired outcome including:  A competitive wholesale market structure needs to be in place to ensure market‐based incentives and disciplines are sufficient to elicit timely, efficient and innovative responses, as discussed previously;  Prices need to be cost‐reflective through the value chain to create strong incentives for efficient investment, operation and end‐use, with price regulation allowing sufficient room for efficient price formation, especially during periods of relative scarcity when supply‐demand balances are tight;  A liquid, deep, transparent and efficient financial market is needed to facilitate efficient risk management, price formation and to help increase access to capital at least cost; and  Efficient market responses need to be informed by accurate and timely information, including credible medium‐term demand projections that facilitate greater market transparency and more effective independent decentralised decision‐making.

Cost‐reflective pricing Cost‐reflective prices are needed to create clear incentives for efficient, timely and innovative investment, operational and end‐use responses in energy‐only markets that rely on independent and decentralised decision‐making. But cost‐reflective electricity prices tend to be volatile, particularly short‐term wholesale spot prices, reflecting the unique characteristics of electricity15. Page | 45 Energy‐only wholesale markets tend to reflect this volatility in a more transparent and direct manner than energy and capacity markets. This is an important distinction. Inherent price volatility needs to be revealed in the spot price formation process under an energy‐only model so that price signals accurately reflect underlying supply‐demand conditions and create strong incentives for efficient, timely and innovative investment, operational and end‐use responses. Energy‐only pricing could deliver several benefits in a Russian context that could help to improve spot price formation and possibly lead to lower average wholesale prices over the longer term. For example, energy‐only pricing with a single system marginal price is likely to be more efficient, avoiding the problem of compounding infra‐marginal rents from separate system marginal prices for energy and capacity. It would also largely remove the need for related interventions, such as the current capacity premium toe ensur return of highly capital intensive base load plant like nuclear and hydro, while also helping to address concerns around ‘windfall profits’ accruing to base load plant with low short‐run marginal costs by incorporating the return on capital into the energy‐only price. However, it is essential for efficient price formation that fluctuations in wholesale spot prices not be unduly masked or capped where they reflect movements in the underlying supply‐demand balance. If they are unduly distorted, they will send the wrong signals, communicate the wrong incentives and likely deliver the wrong outcomes. That said, the relative inflexibility of demand in real time means that all wholesale electricity markets are exposed to the risk that they may not be able to clear under conditions of extreme scarcity. In such circumstances, spot prices could reach extremely high levels without finding a market clearing solution. Most wholesale electricity market designs address this risk through a price cap or some regulatory provision that is triggered when prices clearly exceed a reasonable value of lost load16. Russian electricity law empowers the Federal Antimonopoly Service to suspend competitive price formation and impose a regulated price regime whenever capacity shortages or abuse of market power may lead to unacceptably high wholesale prices. Beyond this power, the Russian wholesale market does not include any explicit price caps (Russian Federation, 2003). The wholesale price capping powers have been used on occasion. For example, wholesale prices in the Siberian pricing zone increased significantly after the accident that shut down the 6 400 MW Sayano‐Shushenskaya hydro plant in August 2009. System marginal prices rose as more expensive coal‐fired generation was dispatched to compensate for the lost hydro capacity. Regulators responded by immediately capping day ahead prices to the regulated rates applying at the time. Caps remained in place for over two months after the accident, until 1 October 2009. Concerns have been expressed over the use of price caps in the Russian context, especially the risk that inappropriate intervention could unduly prevent prices from reflect scarcity conditions, undermining market‐based signals for efficient investment, operational and end‐use responses (Boute, 2012).

15 See Footnote 11 for a summary of the unique characteristics of electricity. 16 The value of lost load (VoLL) can be defined as the monetary value placed on a marginal unit of electricity consumed. System VoLL refers to the highest monetary valuation among all potential consumers for the marginal unit of electricity consumed. Hence, VoLL defines the maximum price consumers would be willing to pay in exchange for not having to reduce electricity consumption at the margin.

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Regulated price regimes can suffer from several weaknesses. Often, the trigger mechanism is based on a price ceiling that does not take into account the underlying supply‐ demand situation. As a result, regulated price caps can mask legitimate price volatility and undermine incentives for efficient market responses through the electricity supply chain. Regulatory discretion can reduce this problem. However, it may also create uncertainty, magnify regulatory risk and place pressure Page | 46 on governments to intervene inappropriately to manage prices in the future. Poorly thought‐out price caps can have the unintended consequence of driving market participants to the edge of bankruptcy. In California in 2001, a retail price cap prevented utilities from recovering their spiralling wholesale costs (IEA, 2002). Similarly in Victoria, Australia in 2000, the imposition of price caps during a temporary power shortage increased the impact and duration of the shortage and resulted in the deferral of planned private investment in peak capacity, which threatened reliability and increased the risk of further intervention (IEA, 2003; Victorian Department of Natural Resources & Environment, 2000). Price caps that are set too low distort efficient responses to price volatility. They discourage demand flexibility and inter‐regional investment. They also discourage the efficient development and use of financial risk management products that could shield consumers from wholesale‐ market volatility, providing the price stability that price caps are designed to deliver but without the drawbacks of capping. This has been an on‐going problem in several markets in the United States where policy makers and regulators sought to address concerns about the risk of high and volatile prices through the imposition of relatively low wholesale spot price caps. As a result, the ‘headroom’ provided for efficient wholesale price formation was unduly constrained and markets were unable to deliver sufficient revenue to fund incremental investment in peaking capacity. This ‘missing money’ problem became a key rationale for adopting capacity mechanisms; to provide the supplementary cash flow needed to close this gap. However, capacity mechanisms introduce a more invasive form of market management that increases exposure to regulatory risk and a range of additional costs. Russia has already experienced some of these issues (There is a wealth of literature exploring capacity mechanisms and related issues, including for example, Cramton and Stoft, 2008; Joskow, 2008; and Roques 2008). Wider IEA experience suggests that a more effective and less distortionary option would be to increase the price cap to a level closer to the value of lost load. There is some movement in this direction in the United States. Federal Energy Regulatory Commission Order 719 of October 2008 noted that market rules that do not allow prices to rise sufficiently during a reserve shortage to allow supply to meet demand are unjust and unreasonable, and required regional transmission organisations to modify their rules, as necessary, to allow more transparent pricing during periods of reserve shortage (FERC, 2008). PJM Interconenction LLC; the independent system operator for the PJM regional market, has responded to the Order by recently introducing a shortage pricing scheme. Under the scheme, among other things, a ‘scarcity’ price cap has been introduced allowing the wholesale price cap to be increased during capacity shortages from USD 1 000 per MWh to USD 2 700 per MWh. The scheme will be fully implemented from 2015. The scarcity price cap will be triggered when available operating reserves fall below the reserve target for a prescribed period or when the system operator activates emergency procedures to avoid a blackout (PJM, 2012; NERA, 2012). An alternative to the exception‐based regulatory approach currently used in Russia would be to implement a wholesale price cap that reflects the economic value of consumption at the margin. The United Kingdom and Australia, among others, use wholesale price caps based on an estimation of the system value of lost load (VoLL). Price caps of this kind are superior to arbitrary price caps in that they maximize the opportunity for economic price formation and efficient

© OECD/IEA 2013 Russian Electricity Reform 2013 Update: Laying an Efficient and Competitive Foundation for Innovation and Modernisation responses to price signals, while also protecting the consumer from excessive price‐gouging. VoLL‐based wholesale price caps can be set in advance in a fully transparent manner, thus avoiding the vagaries of regulatory discretion and reducing pressure for government intervention. Russian policy makers should consider the merit of introducing price scaps of thi kind, especially if a decision is made to introduce an energy‐only wholesale market model in the future. Page | 47 Financial markets Volatility in energy‐only spot markets exposes market participants to a range of financial risks. Efficient, cost‐effective management of these risks is crucial to the efficient operation and development of energy‐only wholesale electricity markets. Financial markets that are liquid, deep and innovative offer efficient ways for market participants tol dea with the commercial risks of volatile wholesale electricity markets, by transferring the risks to those who can manage them at least cost. Financial markets can underpin the development and operation of efficient electricity markets in several other ways including:  increasing transparency and competition in ways that will facilitate efficient price formation and more transparent signals for efficiently timed and sized investment, operation and end‐ use responses;  reducing transaction costs and risk‐management costs, especially for potential new entrants;  reducing scope and incentives for generators to use of bidding strategies to drive up spot prices as revenues are largely derived from fixed‐price financial contracts;  reducing the need to employ more expensive and less efficient means of mitigating these risks, such as physical hedging through vertical integration;  providing an effective platform for developing efficient financial products to manage trading and counterparty risks associated with locational marginal pricing, such as financial transmission rights,17 and  helping to create greater cash flow certainty, and thereby reducing the risk premium investors and financiers attach to electricity market investments while potentially improving access to capital markets. In particular, efficient, liquid and deep financial markets can smooth wholesale‐price volatility without undermining efficient price signals and investment responses (Newbury et al., 2003). Accordingly, they can remove a principle rationale for distortionary price caps and other regulatory instruments designed to manage price volatility. Recent inquiries by the European Union and Nordic Energy Regulators have concluded that encouraging the development of financial markets remains an important policy priority (NordREG, 2010; European Commission, 2007). Financial power markets in the Nordic region are among the most mature and developed across the IEA. An overview of the Nord Pool exchange and its main derivative products follows.

17 See Hogan 1999 for a discussion of the ideal nature and scope of financial transmission rights and their potential to facilitate efficient risk management where congestion is priced on the basis of locational marginal prices. For practical experience with financial transmission rights see market and system operator reports and related regulatory assessments in relation to the PJM Interconnection, NY ISO and New England ISO markets.

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Box 6 • An overview of the Nord Pool power exchange

The Nordic electricity exchange, commonly known as Nord Pool, serves participants in the wholesale electricity markets of Denmark, Estonia, Finland, Lithuania, Norway and Sweden. First established in Norway the exchange was extended to Sweden in 1996, creating the world's first multinational Page | 48 exchange for trading electric power. Nord Pool operates a number of marketplaces and associated services, including day‐ahead, hour‐ahead and real time spot markets for physical delivery of power, a financial derivatives market and a clearing house for financial contracts. Participants in Nord Pool include producers, retailers and market intermediaries (or traders). Futures, forwards, option contracts and contracts for difference are sold through Nasdaq OMX Commodities, the Nord Pool financial trading platform. Some trading in instruments related to the European emissions trading scheme also takes place. Nord Pool’s financial market runs in competition with bilateral over‐the‐counter (OTC) contracts, with a portion of bilateral contracts registered for clearing on the central exchange. Contracts traded in the Nord Pool financial market do not involve transfer of the underlying commodity. Rather, the contracts allow parties to agree to fix the financial cost of a given future purchase of wholesale electricity. Financial intermediaries with no production capacity or end customers enter this financial market with a view to earning returns from successful trading strategies, thereby creating a deeper market with greater liquidity. Nord pool’s standard trading instruments are futures and forward contracts. These products create the obligation to trade electricity at a set point in the future, at a set price. Futures are settled daily and forward contracts at the end of the contract period. The system price calculated by Nord Pool Spot is used as the reference price for futures and forwards. If the system price deviates from the price agreed in a futures or forward contract then one party must compensate the other, such that the financial effect on both is as per the pre‐determined price. The contracts have a time horizon of up to six years, covering daily, weekly, monthly, quarterly and annual contracts. Nord Pool also offers option contracts, which are a variation on futures contracts, whereby the party purchasing the option purchases the right, but not the obligation, to buy electricity at a set price at some point in the future. Unlike futures or forward contracts, where both parties are committed to the eventual exchange, the party purchasing an option may let the option lapse. The party selling the option receives a premium in return for agreeing to settle the contracted trade only if the purchaser elects to do so. Factors such as grid congestion and access to capacity are not taken into consideration when entering into futures and forward contracts. Nord Pool offers contracts for difference products so that parties can manage their exposure to differences between the system price and area prices across Nord Pool markets. Under a contract for difference one party is able to fix the price for a future purchase of electricity equal to the system price, even where area prices diverge. Futures and forward contracts are linked to the system price and contracts for difference to area prices. This distinction was maintained in preference to a system of futures and forward contracts linked to various area prices, to help maintain market liquidity and depth. Hence, a party seeking to hedge its risk against movements in the system price and in specific area prices needs to purchase: a future or forward contract that limits its exposure to the system price; a contract for difference addressing exposure to variations in the relevant area price; and the underlying energy on the wholesale energy market. Nord Pool’s active market in financial derivatives provides a number of benefits. The contracts allow multiple parties to operate as retailers without the need for vertically‐integrated upstream generation assets, encouraging greater competition in the provision of retail energy. On‐going trading in financial derivatives provides transparency over price expectations – since the futures contracts give a strong indication of market players’ estimates of future price outcomes – and this more nuanced view of long term supply and demand allows generating parties to make better informed investment decisions. Finally, the calculation of area prices and associated trade in contracts for difference indicates where the need for fresh investment in generation and transmission is greatest. Source: Nasdaq OMX and Nord Pool websites.

Figure 8 charts the development of the Nordic financial market. IEA experience suggests that

© OECD/IEA 2013 Russian Electricity Reform 2013 Update: Laying an Efficient and Competitive Foundation for Innovation and Modernisation financial markets can be slow to develop with bilateral over‐the‐counter (OTC) trading generally developing initially and more fungible exchange traded volumes growing as markets mature.

Figure 8 • Volume of trade in Nordic electricity markets: 1998‐2011

3500 Page | 49 3000

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Source: Source: NordREG 2012 Dips in 2003 and in 2009 are largely explained by the physical and financial market corrections following the collapse of Enron in 2002 and the global financial crisis in 2009 (NordREG, 2012). A trend toward exchange traded products is also evident. However, total traded volumes in 2011 were only around 4.5 times underlying physical consumption, well below the ratio considered indicative of robust liquidity and depth in other financial and commodity markets. Russian experience to date appears to be following a similar path. Day‐ahead physical spot market transactions dominate wholesale markets with little information available on the nature and volume of financial trading. Trading volumes on the Moscow Energy Exchange represent only a small fraction of overall physical volumes. One stakeholder noted that legislation governing the nature and trading of financial products does not adequately define hedging instruments and that this creates risk that discourages participation in the financial market. Indeed, under current highly regulated arrangements there is probably little need to hedge and hence little reason to develop more sophisticated financial risk management strategies. IEA experience to date suggests that several factors can affect the development of liquid, deep and effective financial markets for electricity including:  access to a credible price reference, such as a robust wholesale spot price that appropriately reflects underlying supply‐demand fundamentals;  lack of awareness, sophistication and involvement among market participants and financial intermediaries;  an unduly limited range of financial trading mechanisms and products;  high transaction costs;  high levels of vertical integration;  the nature and scope of regulation; and

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 cyclical factors affecting market participants’ willingness to trade (eg. tightening supply‐ demand balances may encourage generators to limit certain offerings, such as peak power contracts). Other power exchanges across Europe, North America and Australia are developing, with a range of products now offered over a variety of timeframes. Some are approaching or exceeding the Page | 50 traded volumes currently achieved in the Nordic market. Volumes are continuing to grow as market participants understanding of financial risk exposures grows and as their exposures increase. In particular, further consideration could be given to North American experience with financial transmission rights given that the Russian wholesale market currently employs locational marginal pricing. Introduction of more competitive wholesale market arrangements with greater reliance on independent decentralised decision‐making is likely to increase market participant exposure to congestion and related trading risks associated with a locational marginal pricing environment. IEA experience suggests that some form of financial transmission rights are a fundamental requirement for developing effective wholesale market arrangements employing locational marginal pricing. An effective system of risk management products incorporating financial transmission rights will be needed to support the introduction of more competitive and decentralised market‐based arrangements in this context. ATS undertook some work in this regard in 2004‐5. Consideration could be given to reactivating this work in the context of developing more market‐based arrangements, particularly if policy makers decide to pursue an energy‐only model incorporating locational marginal pricing. Current global financial difficulties highlight the need for efficient financial markets that cost‐ effectively manage risk and promote certainty for investors. Such markets can increase cost‐ effective access to capital, which is critical for securing efficiently timed and sized investment in the longer term, especially if a move toward a more efficient, market‐based investment paradigm built on an energy‐only wholesale market and independent decentralised decision‐making is contemplated in the longer‐term. If this is the case then Russian policy makers may want to give greater priority to the development of electricity‐related financial markets, drawing from the lessons of successful North American and European exchanges, including further developing products and trading platforms to support the effective use of financial transmission rights, and identifying and removing any undue legal or regulatory barriers to their development and use.

Transparency IEA experience indicates that efficient investment, operational and end‐use responses need to be informed by accurate and timely information and credible medium‐term supply and demand projections that facilitate greater market transparency and support more effective independent and decentralised decision‐making by market participants. The European Union competition inquiry into the energy sector identified three key reasons for greater transparency (European Commission, 2007):  access to more comprehensive information would allow all market participants to take informed actions which minimise commercial risks and reduce barriers to entry;  levelling the playing field by avoiding situations where parties can profit from access to commercially sensitive information at the expense of other market participants and efficient market operation; and  higher levels of transparency build confidence and trust in wholesale markets, especially in the reliability of price formation, which has the potential to strengthen price‐based incentives for timely and efficient market‐based responses.

The European Commission’s Competition Inquiry noted a lack of transparency across most European Union Member States and widespread dissatisfaction with the nature, scope and coverage of data made available to market participants18. In particular, it highlighted several practices where incumbents withheld key data to advantage affiliates at the expense of more competitive and efficient market outcomes19. According to the Inquiry, those markets that made more information available were generally considered more competitive than those where less Page | 51 information was provided. Nordic markets and the United Kingdom were commended in this regard. The Inquiry concluded that more information should be published on the technical availability of networks and interconnectors, on generation, load, balancing and reserve power requirements. Concerns about confidentiality associated with ‘excessive’ transparency were noted, especially the risk that increasing transparency may facilitate undue collusion among market participants operating in oligopolistic markets. However, these concerns were not considered an insurmountable barrier to improving transparency. On the contrary, the Inquiry concluded that the benefits associated with a better informed marketplace outweighed any risks associated with a potential increase in anti‐competitive behaviour. It noted that improved transparency could help to strengthen commercial discipline on market behaviour and hence reduce scope for market power abuse. Concerns about collusion and confidentially could largely be addressed through appropriate aggregation of data and the timing of publication of information. The Inquiry also suggested that transparency requirements could be included among remedies in future competition cases (European Commission, 2007). There have been significant developments to improve transparency in European wholesale electricity markets since the publication of this report. In particular, work undertaken by the European Regulators' Group for Electricity and Gas, building on its 2006 Good Practice Guide for Information Management and Transparency in Electricity Markets, has resulted in a proposal to create a European‐wide standard for electricity market data transparency addressing information requirements for generation, load, transmission and interconnectors and balancing. It also proposed the creation of a central information platform for publishing electricity data, to improve management of information and stakeholder access to reliable and comparable data (ERGEG, 2010). Key features of the proposal are summarised in Box 7. Several elements were incorporated into the European Union’s Wholesale Energy Market Integrity and Transparency Regulation (REMIT), which among other things, introduced a new mandatory reporting framework for monitoring of wholesale energy markets focusing on detecting and deterring market manipulation and insider trading (European Parliament, 2011). Similar kinds of information are made available by market and system operators in other leading practice IEA markets in North America, Australia and New Zealand.

18 A survey of national regulators undertaken in the context of the Inquiry revealed 80% dissatisfaction with the nature, scope and coverage of data made available to wholesale markets. Survey results are discussed further in European Commission 2007, Section II 4.3 (pp190‐91). 19 For example, the Inquiry notes a general perception that vertically integrated incumbents did not share generation data with all market participants, undermining confidence in wholesale markets. Another example cites the practice of operators withholding information on generation outages until after markets had closed, allowing their affiliates to trade on an unfair basis (p188).

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Box 7 • European regulators' group for electricity and gas guidelines to improve electricity market transparency

The guidelines aim to establish a minimum level of data transparency to support the efficient functioning of wholesale electricity markets across the European Union. They define a minimum set Page | 52 of data to be made available to all market participants through a centralised information platform to help establish a coherent and consistent frame of reference for understanding and analysing European wholesale electricity markets. Data would be retained for a minimum of five years in an easily accessible form on a website to be managed by the European Network of Transmission System Operators for Electricity (ENTSO‐E). Minimum data requirements in relation to load include:  hourly actual load published no later than one hour after dispatch;  day‐ahead estimates of total load by dispatch interval for each bidding area no later than one hour before day‐ahead gate closure;  forward estimates of maximum, minimum and average load in each bidding area, on a weekly, monthly and yearly basis consistent with power exchange product offerings;  a year ahead forecast of the supply‐demand margin by bidding region, including separate forecasts for generation of capacity, availability and contracted reserves for system services;  ex‐ante information on the planned unavailability of consumption units, with changes reported and published within one hour of receipt for volumes over 100 MW;  ex‐post information on the unplanned unavailability of consumption units, with changes reported and published within one hour of receipt for volumes over 100 MW; Minimum data requirements in relation to transmission and interconnectors include:  annual information on the expansion and retirement of capacity per bidding area including the estimated impact on transmission capacity and capability over the next three years;  all relevant data on available transmission capacity between bidding areas on the basis of best available forecasts including: information on planned outages affecting interconnection capacity between bidding areas; ex‐post information on actual planned or unplanned transmission outages; day‐ahead capacity offers (where relevant); and net transfer capacities between bidding areas;  information on the use of transmission and interconnector capacity including: the volume of capacity made available to the market; the price of each bidding area (for interconnectors); and congestion revenues;  publication of an annual report (updated during the year) identifying points of persistent congestion, the nature and impact of the congestion, and corrective measures that could be implemented to alleviate the congestion; and  impact of system operator intervention to resolve network and system security issues on net transfer capacity, where the impact was greater than 100 MW in an affected trading interval, with any modification published no later than two hours after an intervention. Minimum data requirements in relation to generation include:  sum of all generation capacity greater than or equal to 1 MW in service or expected to enter service over the following three years;  information on each unit (installed or planned to enter service) with capacity of 100 MW or greater including: capacity, location, bidding area and production type;  annual ex‐ante forecast of available capacity for the following three years for each unit with capacity of 100 MW or greater;

Box 7 continued  ex‐ante information on planned outages of 100 MW or greater including: volume of capacity affected, location, bidding area, production type, period of outage, and reason for outage;  ex‐post information on unplanned outages of 100 MW or greater including: volume of capacity affected, location, bidding area, production type, period of outage, and reason for outage; Page | 53  day‐ahead estimated aggregate generation to be scheduled for dispatch for each trading interval for each bidding area;  aggregate ex‐post information for the previous week on the filling rate of hydro reservoirs for each bidding area, including a comparison value for the previous year;  actual output of each generator of 100 MW or greater updated hourly in arrears;  aggregate production for each trading interval by generation type in each bidding area published hourly in arrears; and  day‐ahead forecasts of wind and solar power in each bidding area for each dispatch interval where these technologies contribute more than 5% of generation per annum. Minimum data requirements in relation to balancing include:  publication of balancing rules including: processes for ex‐ante and real‐time procurement of differing types of balancing reserves; pricing methodology for activated reserves; and the methodology for calculating imbalance charges;  the nature and amount of any balancing reserves and period procured;  ex‐ante price paid for each kind of balancing reserve procured, including the pricing methodology;  ex‐post aggregated activation offers made to the system operator by type of balancing reserve;  ex‐post information on activated balancing reserves including: whether procured ex‐ante or ex‐post; type of reserve; and when the reserves were used;  ex‐post information on average and marginal prices paid by system operators for balancing energy;  imbalance prices per balancing period;  aggregated volumes of imbalances and related volumes of balancing reserves used within each control area;  financial balances for each control area including expenses for balancing energy and capacity payments resulting from imbalances; and  market information on the type of balancing bids and offers used each day. Source: ERGEG 2010

In addition, many IEA jurisdictions undertake and publish independent longer‐term projections of supply‐demand balances annually, typically covering a period of 10 years to facilitate timely and efficient market‐based operational and investment responses to ensure on‐going reliability and adequacy of electricity services. Examples include; the North American Electricity Reliability Corporation’s annual Long‐Term Reliability Assessment which assesses the adequacy of the bulk electric system in the United States and Canada; the European Network of Transmission System Operators for Electricity biannual Ten‐Year Network Development Plan and Regional Investment Plans (the latter from 2014); the Australian Energy Market Operator’s (AEMO) annual Electricity Statement of Opportunity which includes forecasts of supply‐demand balances for each region in the Australian National Electricity Market; and the joint Department of Energy and Climate Change and Ofgem annual Statutory Security of Supply Report which includes 15‐year supply‐ demand projections for the United Kingdom. In some leading practice jurisdictions, regulators and system operators are developing innovative, interactive web‐based packages to enable

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market participants to more effectively undertake their own analysis and strategic planning drawing on the modelling methodology underpinning official forecasts. The following box describes one example.

Box 8 • An overview of the AEMO supply‐demand calculator

Page | 54 Each year the Australian Energy Market Operator (AEMO) publishes the Electricity Statement of Opportunity, (ESOO) which includes updated forecasts of the supply‐demand balance in the National Electricity Market (NEM) for the following 10 years. Forecasts are developed using a linear programming model that co‐optimises generation dispatch and interconnector power flows subject to minimising reserve deficits. AEMO uses this supply‐demand methodology to generate 10‐year reliability outlooks for each region. These outlooks highlight potential generation, network and demand‐side investment opportunities, by providing an independent and robust analysis of when each region may require additional supply. AEMO released an interactive version of the model with the 2011 ESOO. This Supply‐Demand Calculator provides a readily usable tool that enables interested parties to vary the key underlying assumptions and to run sensitivity analyses and to assess the impacts of alternative future scenarios. Assumptions that can be varied include: regional maximum demand projections for the high, medium, and low economic growth scenarios; levels of committed demand‐side participation; capacities of existing and committed new scheduled and semi‐scheduled generation including committed retirements; reserve sharing relationships; and existing transmission capabilities and committed transmission projects. The Calculator along with a step‐by‐step instruction manual can be downloaded from the AEMO website. The Calculator has been provided to help improve market participants’ understanding of the modelling that underpins AEMO’s official forecasts and to help inform timely and efficient decision‐ making by permitting individual market participants to undertake targeted analysis of investment, operational and end‐use opportunities using a tested and credible methodology. Source: AEMO 2012.

In Russia, ATS provides daily aggregated data on wholesale spot market prices and traded volumes. Limited information is accessible on network congestion, with nodal level information not generally made available to market participants. Varying degrees of data transparency are provided on generation and network availability, load, balancing and reliability requirements. Information on wholesale market performance is published by regulators, the system operator and the market operator with timescales ranging from daily through to annual reporting. The Government publishes a social‐economic outlook each year and longer‐term projections every three to five years in the context of updating its General Scheme for the development of the energy sector. Some stakeholders raised concerns about the reliability of official projections and forecasts currently made available to the market. In particular, substantial revisions of medium‐term supply‐demand balance forecasts were noted, which some market participants considered well beyond what might have been required to account for the impact of the global financial crisis. Some private generators and large users suggested that official forecasts reflected policy aspirations more than an objective and independent assessment of potential supply‐demand requirements, and hence did not provide a particularly credible basis for informing private investment, operational or end‐use decision‐making. IEA experience suggests that market forecasts are a key input for effective and timely decentralised decision‐making in liberalised electricity markets, and especially crucial for bringing forward timely and sufficient generation investment. They need to be credible, and perceived to be credible, by market participants if they are to support effective and timely decision‐making. Such forecasting is usually undertaken by system operators, market institutions or regulatory

© OECD/IEA 2013 Russian Electricity Reform 2013 Update: Laying an Efficient and Competitive Foundation for Innovation and Modernisation bodies in liberalised jurisdictions at arm’s‐length from policy bodies to help increase its independence and objectivity. In leading practice IEA jurisdictions forecasting is also undertaken in a transparent manner involving consultation with key stakeholders, which can help to improve the quality of forecasting while increasing its credibility among market participants. Effective decision‐making under a more decentralised, market‐based wholesale model needs to be supported by credible, accurate and comprehensive data and high‐quality, credible forecasts. Page | 55 Russian policy makers, regulators and market institutions may consider reviewing current data provision, with a view to improving the nature, scope and coverage of information and access to that information, especially if a more competitive wholesale market model based on decentralised decision‐making is to be introduced. Similarly, policy makers should consider options to improve forecasting methodologies and processes, possibly including establishing a more independent and consultative process for domestic electricity forecasting, with a view to improving the credibility and effectiveness of official forecasts as a key tool to help inform more efficient and timely investment, operational and end‐use responses.

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3. Retail Market Development

Dynamic and competitive retail markets are needed to drive efficiency dividends through the value chain to end users in the form of more efficient prices and more innovative services. They are an important pre‐condition for developing effective customer choice and demand‐side Page | 56 flexibility, which can enhance efficient price formation, introduce greater competitive discipline and help moderate the potential for market power abuse through the value chain. In particular, experience from leading practice IEA jurisdictions suggests that greater market‐based demand‐ side flexibility and responsiveness resulting from liberalisation of retail electricity markets can deliver a range of economic, reliability and sustainability benefits. From an economic perspective, more flexible demand‐side responses have the potential to greatly enhance the efficiency of the price formation process, creating clearer signals for more efficient investment, operation and end use. Greater demand‐side flexibility can substantially moderate the potential for market power abuse, with a proportional increase in demand elasticity delivering the same competitive discipline as a similar proportional decrease in effective market concentration. Greater demand‐side flexibility can also help to reduce investment requirements to the extent that it can moderate peak demand, resulting in improved dynamic efficiency and lower system costs over time. More flexibility is crucial for empowering customer choice, which can create a range of competitive disciplines that help improve overall efficiency by strengthening incentives to pass through competitive benefits to end‐users, stimulate innovation and deliver cost‐effective services to customers. From an electricity security perspective, demand‐side participation has the potential to support more flexible, innovative and efficient delivery of power system security at least cost. Demand reductions in response to high prices tend to occur when transmission systems are operating close to their security limits. Effective harnessing of demand response in these situations has the potential to significantly reduce pressure on system security and improve reliability by improving the balance between generation and load. In the longer‐term, it has the potential to provide a more flexible and efficient alternative to mandatory load‐shedding during emergency situations. Greater demand flexibility may also reduce the volume of operating reserves system operators need to acquire to meet security requirements. Demand response could be fully activated over a very short timeframe making it an ideal alternative source of operating reserve, which can help to deepen and diversify the pool of reserves and increase competition to provide reserve services. This could have the effect of lowering ancillary service costs while improving overall system security. It also has the potential to defer the need for incremental reliability‐based investments (IEA, 2005b). From a sustainability perspective, demand response has the potential to greatly increase the volume of real‐time flexible resources available to support large‐scale integration of variable renewable generation. It also offers the potential to smooth volatility in electricity demand, which may reduce overall carbon emissions by replacing carbon‐intense forms of peak generation with lower‐emitting generation options. In the longer term, greater demand‐side flexibility could be reflected in more efficient forms of electricity use. ,Over time improvements in end‐use energy efficiency could result in a permanent reduction in demand compared to previous levels in the absence of demand‐side flexibility. This may result in a permanent reduction in carbon emissions where the power saved would have been produced by fossil fuel generation. Russian policy makers have recognised these potential benefits and are aiming to establish efficient and innovative retail markets that will deliver effective customer choice, facilitate demand response and ultimately deliver tangible benefits for end‐users in the form of more

© OECD/IEA 2013 Russian Electricity Reform 2013 Update: Laying an Efficient and Competitive Foundation for Innovation and Modernisation innovative products and services, improved service quality and more efficient prices. Successful delivery of such benefits would help to strengthen the credibility and acceptance of the reform program among key stakeholders and across the wider community. A range of stakeholders consulted during this study including from government, the electricity supply industry, large users, regulators and market institutions all supported the development of more competitive, innovative and transparent retail markets for electricity. One large industrial user estimated that Page | 57 the introduction of more competitive retail market arrangements incorporating more cost‐ reflecting pricing could save around RUB 60 billion per annum. However, fully realising these potential benefits has proven elusive, especially for smaller volume consumer classes. While leading practice IEA jurisdictions in Europe and North America have made considerable progress in recent years to develop demand response, largely in the context of supporting more reliable system operation and reducing peak system demand, much of its potential remains undeveloped. Key pre‐conditions for the successful development of competitive retail markets that deliver effective customer choice and greater demand response include:  the presence of a transparent and competitive retail market structure;  effective retail market arrangements that promote the development of competition among retailers resulting in the provision of innovative products and services; and  cost‐reflective end‐user prices that send clear signals for timely and innovative retail market responses.

Retail market structure

Russian policy makers recognize the importance of creating a robust, competitive retail market structure and have included it among the strategic objectives of the reform. Competition was first introduced to electricity retail markets in September 2006 (Russian Federation, 2006). These rules allowed contestable customers to enter into supply contracts with independent retailers for those proportions of their load that could be sourced from competitive wholesale markets. The proportion of load eligible for competitive supply was gradually increased over the subsequent five‐year implementation period. At present all customers with the exception of regulated residential customers are eligible to exercise choice at the retail level. There are over 120 licensed independent retailers registered to operate on the wholesale market. Reform also involved the vertical unbundling and physical separation of distribution and retail functions, with overlapping distribution and retail franchise areas initially established to help strengthen separation and promote more competitive outcomes. At the same time, the rules established a regime of suppliers of last resort commonly referred to as Guaranteeing Suppliers (GS) to supply regulated customers and to fulfil universal service obligations, including supplying customers served by a competitive retailer within their franchise which had become insolvent. 69 GS’s were created originally in 2006 and their numbers have grown rapidly since, with the Ministry of Energy reporting that there were over 1 000 registered GS’s in 2012. Each GS is subject to regulation, with standard contracts and cost‐plus pricing supervised by national and regional regulatory authorities. In return, each GS is permitted to operate an exclusive local franchise, in which they are the only entity that can supply regulated residential customers. GS’s are permitted to compete with independent retailers for contestable customers. Currently, GS’s supply around 68% of the contestable customer load in European Russia and the Urals, and around 45% of the contestable customer load in Siberia (Russian Ministry of Energy, 2012b). In practice, all smaller contestable consumers without direct access to the wholesale market have until recently had little choice but to purchase from their local

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GS’s. GS’s possess a dominate market position in most retail markets in Russia, accounting for between 75% and 85% of all retail sales across the integrated regional power systems where competitive market reforms are being introduced, as shown in Table 4 below. Several stakeholders noted that competition, efficient retail market development and effective customer choice is suffering as a Page | 58 consequence of this dominance.

Table 4 • Average market shares of retail suppliers in 2010

Average Market Share of Suppliers Average Market Share of Federal District of Last Resort (%) Independent Retailers (%) Central 80 20 Volga 75 25 Urals1 81 19 Northwest 85 15 South 85 15 Siberia 83 17 Note: Data for the Urals Federal District is for 2009. Source: Kuleshov et al. 2012 and APBE 2011. The dominance of GS’s and the localised nature of retailing activities are generally reflected in a highly fragmented and concentrated retail market structure. Table 5 presents results from a more detailed study of changes in retail market shares and market concentration in the Volga Federal District between 2007 and 2010. According to this study, the nature of the retail market structure and trends experienced in the Volga Federal District over this period are broadly representative of wider experience across Russian retail electricity markets and hence provides a sound basis for drawing more general observations20. In most sub‐regions between one and three GS’s provided nearly two‐thirds of electricity sales across the region in 2010. The remaining one‐third of sales was sourced from a growing number of independent retailers, each with a relatively small market share. The top three retailers have increased their market shares over the period. LLC “Rusenergosbyt” accounted for around 9% of regional electricity supply and operateed as a GS and independent retailer in eight sub‐regions. LLC “Rusenergoresurs” increased its average market share to 4% over the period. JSC “Megregioneneergosbyt” was established by Gazprom when the reform was introduced and supplies mainly Gazprom affiliate generators in six sub‐regions within the Volga Federal District. The other independent retailers typically supply one or several industrial end‐users in their sub‐ region (Kuleshov et al., 2012). Analysis of the structural trends in the Volga Federal District shows some potentially positive signs of independent retailers making inroads into the dominant position of incumbent GS’s. The market share of independents grew in ten of the 14 sub‐regions of the Volga Federal District between 2007 and 2010, and more than doubled in seven of those sub‐regions over the period, albeit from a very low base. Similarly, the number of independent suppliers rose over the period in all bar two of the sub‐regional markets, while the number of GS’s generally remained constant or contracted slightly.

20 The Volga Federal District ranks second among the Federal Districts based on gross regional product and industrial production. It incorporates 14 sub‐regions with a population of around 30 million; 70% of whom reside in urban areas. See Kuleshov, et al., 2012 for further details.

Table 5 • Retail market structure of the Volga federal district ‐ 2007 & 2010

2007 2010 Guaranteeing Independent HHI Guaranteeing Independent HHI Sub-Region Suppliers Retailers Index Suppliers Retailers Index

Number Market Number Market Number Market Number Market Share Share Share Share Page | 59 (%) (%) (%) (%) Nigegorodsky 3 64 5 36 3374 3 60 9 40 3234 Saratovsky 5 80 6 20 2361 3 91 8 9 4107 Samarsky 3 97 7 3 9468 4 83 8 17 4633 Ulyanovsky 2 96 3 4 8703 2 86 13 14 6996 Permsky 2 83 4 17 6049 1 75 6 25 5829 Penzensky 1 80 5 20 6582 1 84 5 16 7101 Orenburgsky 3 66 5 34 4404 3 70 8 30 4647 Kirovsky 2 95 1 5 7260 2 77 3 23 4830 Republic of 1 98 1 2 9532 1 83 3 17 7218 Chuvachiy Republic of 2 82 6 18 4155 1 60 8 40 3996 Udmurtiya Republic of Tatar 1 100 ‐ ‐ 10000 1 >50 n.a. <50 >5000 Stan Republic of Mordovia 2 75 5 25 3551 1 57 7 43 3544 Republic of Mari El 2 87 2 13 4527 1 90 1 10 8168 Republic of 1 99 n.a. 1 9920 1 79 n.a. 21 6682 Bashkortostan Note: HHI index figures are rounded to nearest whole number based on figures published in annual reports of retailers and market regulators. n.a. = not available Source: Kuleshov et al. 2012. The increasing market shares of independent retailers are reflected in falling indicators of market concentration. The HHI index score improved in ten of the sub‐regions, with a significant improvement recorded in seven of those sub‐regions over the period. A substantial increase in concentration was recorded in only one sub‐region over the period. Stakeholder comments generally confirmed these findings, with some noting evidence of competition between independent retailers and GS’s emerging in some regions. These developments are generally positive but there is still a long way to go. Despite these improvements the retail market remains highly concentrated throughout the Volga Federal District, with HHI scores ranging from around 3 200 to over 8 000 in 2010, suggesting that incumbent GS’s retain considerable potential to exercise substantial market power and considerable incentive to protect their dominant market position. Most stakeholders noted that retail markets currently fell well short of the competitive goal. Several concerns were expressed about the inherently uncompetitive retail market structure and the resulting capacity of incumbent GS’s to exercise market power to extract excess profits at the expense of end‐users including:  limited competition reflected in passing through of all costs with few incentives for developing more cost ‐effective, efficient or innovative products or services;

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 various forms of price gouging leading to substantially higher profits for incumbent GS’s and higher retail charges for end‐users compared to retail businesses operating in more contestable markets,21  limited effective choice and weakening consumer engagement, reflecting a lack of competition, and market and regulatory barriers to switching suppliers; and Page | 60  substantial barriers to new entry including: high transaction costs associated with accessing the wholesale market; regulated monopoly status of GS’s; limited transparency; opaque price formation; limited access to information and customers; and continuing uncertainty over the roles, responsibilities and rules applying to retail market entities and retail market transactions. Together these factors have helped to strengthen the effective market power of GS’s while distorting competition and slowing efficient retail market development at the expense of end‐ users. Potentiale to exercis market power is reflected in the margins GS’s were able to extract from retail markets. According to the Ministry of Energy, GS retail margins were more than double prescribed levels in 2010‐11, providing additional total revenue of between 50 and 70 billion roubles over the period (Russian Ministry of Energy, 2012b). Recent policy announcements, notably the May 2012 resolution on retail market development issues, have sought to address many of these concerns (Russian Federation, 2012a). Among other things, the new retail rules:  Reduce barriers to accessing the wholesale market. From April 2013 consumers have access to the wholesale market without regional regulatory approval or paying compensation to GS’s. Individual consumers will not be directly accountable for meeting any wholesale balancing obligations. Related imbalance monitoring and information exchange will be managed by ATS. Access will be granted on a quarterly basis subject to meeting certain requirements.  Introduce a revenue cap methodology to replace cost‐plus regulation of GS retail margins. For regulated residential consumers the margin will reflect the cost incurred for serving differing residential customer classes as determined by regional regulators. For contestable consumers, the retail margin will be set as a proportion of the final unregulated price based on the revenue cap established by the Federal Tariff Service. Revenue caps for contestable consumers will be differentiated by customer class.  Establish customer service quality standards for GS’s including:  model services contracts including minimum timeframes for concluding agreements;  compliance procedures;  provisions to improve customer access to information by requiring GS’s to establish call centres with toll‐free numbers and shopfront services;  requiring effective metering of individual consumption with remote meter reading capability; and  introducing a range of payment methods including making payments directly to GS’s without having to go through an intermediary and pay related commissions. Most of these provisions are in force, with quality of supply requirements to take effect from May 2013. FAS is responsible for monitoring and enforcing GS compliance with the new rules.

21 For example, the practice among Guaranteeing Suppliers of creaming‐off the differential between individual imbalance fees charged to users and net system charges paid to cover actual imbalances in the wholesale market. According to one market commentator, price gouging in its various forms had resulted in annual profit margins of up% to 15 per annum in some cases.

IEA experience to date highlights the importance of establishing clear commercial incentives for retailers to cost‐effectively and innovatively serve the interests of end‐use customers. A competitive retail market structure has a key role to play in this context to help create and reinforce the competitive incentives needed to underpin efficient and innovative retail market responses that can empower consumer choice. IEA experience also suggests that rationalisation following market start usually results in a more Page | 61 concentrated retail market with a relatively small number of larger and more commercially viable retail entities emerging at the end of the process. For instance, the number of retailers has nearly halved in Sweden since market opening, with most of the remaining retailers developing a national presence to ensure their growth and commercial viability (NordREG, 2011). Other leading practice retail markets among the Nordic countries, the United Kingdom and in Australia have experienced similar trends. Iny man cases the main incumbent retail entities operating at the time of market start go on to solidify their market position (NordREG, 2012). Rationalisation reflects the low margin, high volume nature of electricity retailing and at least in part reflects a sound commercial response to the realities of these markets. However, rationalisation can also result in undue concentration and a lack of transparency that can serve as barriers for new entrants and encourage anti‐competitive behaviour among incumbents. From a structural perspective, this is likely to result in a retail market with fewer, larger suppliers that gradually develop a national marketing presence. This could be a positive development, especially where it reduces market fragmentation and strengthens competition across multiple regions among retail entities that can take advantage of economies of scale to reduce operating costs and deliver more competitive outcomes. As a result, end users could benefit from access to a wider range of more innovative and cost‐effective products and services. However, excessive consolidation could result in less competition and lower benefits for end users. An appropriate balance will need to be struck between the development of retail entities that are large enough to develop the ‘critical mass’ required to maintain commercial viability, possibly including developing a wider regional or national retail market presence, and maintaining a market structure that is contestable and supports competitive new entry. Contestability remains critical to the on‐going dynamism of retail markets as experience to date suggests that smaller and more innovative new entrants are a key source and driver of new products and services in electricity markets. Policy makers and regulators will need to actively monitor retail market developments and be prepared to act to identify and reduce potential barriers to efficient and competitive retail market development as appropriate, especially potential barriers to timely and efficient new entry. In particular, the dominant market position of incumbent GS’s will need to be carefully monitored and managed. Corporate entities that combine legislative monopoly GS activities and competitive retailing activities may have the capacity to employ various anticompetitive strategies, such as cross‐subsidising and cost‐shifting, which may distort efficient retail market development. Competitive retail market development is entering a new phase and policy makers have an opportunity to help strengthen incentives for efficient commercial behaviour among incumbent GS’s. Several recent policy and legislative developments in Russia have the potential to help strengthen the regulatory and commercial incentives on GS’s to deliver more cost‐effective services including measures to: improve transparency; improve retailer access to wholesale markets; establish key retail market rules; develop standardised bilateral supply contracts; and provisions to address GS pricing and other anti‐competitive practices. Structural reforms might also be considered to complement and reinforce these incentives. Some stakeholders suggested that fundamental reform and restructuring of incumbent GS’s may

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ultimately be necessary to deliver a more competitive retail market structure in the longer term. Under the original reform proposals all GS franchises were to be allocated on the basis of a competitive tender process and subsequently opened up to competitive tendering every three to five years. However, the requirement for regular competitive tendering of GS franchises was subsequently repealed in late 2010 (Russian Federation, 2010c). Page | 62 Reintroduction of a competitive tendering process for GS franchises may have some merit, especially if it could be used to help accelerate the development of a more integrated and commercially viable retail market structure that promotes more competitive outcomes on a regional or national basis. A regular tendering arrangement also has the potential to strengthen competitive disciplines which could help to improve the cost‐effectiveness of delivering these public service obligations, consistent with approaches emerging among IEA member countries and service provision principles endorsed in the European Union Third Directive (European Parliament, 2009). However, the potential advantages would need to be carefully weighed against the practical constraints. IEA understands that the potential to amalgamate GS service areas into larger cross‐regional franchises may be substantially limited by a range of local and technical factors at the distribution level, which could significantly reduce the scope to use GS auctions to promote the development of a more efficient retail market structure. Another common development among liberalised electricity markets has been the emergence of vertically integrated entities. These have included integrated retailing and distribution businesses, which are commonplace in North American and Australian markets, and integrated retailing and generation entities, which have emerged in all liberalised electricity retail markets across IEA member countries. Policy makers and regulators in several of the more advanced liberalised electricity markets are becoming increasingly concerned about the degree of vertical integration among generators and retailers. For instance, the ‘big six’ electricity retailers in the United Kingdom are vertically integrated and supplied over 99% of the retail market and around 32% of generation output in 2010. The United Kingdom’s energy regulator – the Office of Gas and Electricity Markets (Ofgem) – noted that increased vertical integration in the electricity market has had a detrimental impact on transparency and wholesale market liquidity, and may result in wholesale markets not delivering the products and signals needed to support contestability and efficient new entry. This can have a negative impact on retail consumers if these barriers mean that there is no viable threat to existing suppliers (Ofgem, 2011a). Recent retail price increases have raised concerns about the behaviour of the ‘Big Six’ among policy makers and across the community, resulting in several reviews and regulatory responses to help address concerns about vertical integration and weak competitive intensity. Ofgem proposals included: enhancing wholesale liquidity by requiring the ‘Big Six’ to make between 10% and 20% of their generation available annually to other market participants through mandatory auctions; and enhanced reporting requirements to strengthen transparency and accountability (Ofgem, 2011b). Russian policy makerss and regulators should keep a close watch on structural developments and take steps to avoid undue levels of vertical integration where appropriate. Concerns have also been raised about vertical integration of retailing and distribution functions. Several remedies have been deployed by regulators to improve transparency and accountability including various forms of legal and accounting separation and behavioural remedies including mandated use of supply contracts with standard terms and conditions for default and regulated services and requirements for separate account information on customer bills. Outcomes to date have been mixed.

The European Union Third Directive on the development of the internal electricity market recognised these concerns and called for fully effective separation of supply and generation activities from network activities throughout the Community, though stopped short of mandating separation of distribution and retailing activities (European Parliament 2009). There is a growing view among Continental European market participants that distribution businesses should perform a ‘neutral facilitator’ role for retail markets. Under this model, distribution businesses Page | 63 would be responsible for providing information, balancing and other services required to support competitive retail markets but would not directly participate in those markets, except possibly as a supplier of last resort, and then subject to clearly defined rules that limit the nature, scope and period of their activities (Eurelectric, 2011a; Eurelectric, 2011b). Russian electricity retail markets already benefit from physical separation of retailing and distribution activities. Policy makers and regulators could look to draw from European experience, as appropriate, to help develop and strengthen governance, reporting, contractual and regulatory arrangements between retailer and distribution businesses to promote efficient retail market development that benefits end‐users. IEA experience also suggests that relatively small legal, regulatory, market or administrative requirements that add undue transactions costs can serve to discourage new entrants, who are key drivers of the development of innovative products and services. Similarly, access to accurate and timely information has proven crucial to support new entry, innovative product development and to inform customer choice. One example of an innovative market‐based response has been the emergence of specialty aggregators and energy service companies among the more advanced IEA electricity retail markets. These specialty retail businesses have arisen in response to the growing commercial opportunities for demand‐side products and services in some markets. Typically they offer innovative products to elicit medium and small volume demand response. Contracted volumes are subsequently re‐packaged and on‐sold to a variety of purchasers including system operators and large users, or directly into wholesale and balancing markets. Aggregation has two broad components. Demand aggregation focuses on accumulating small loads from different types of flexible customers and offering them in an aggregated form in various wholesale and ancillary services markets and to different market participants as demand response services. Generation aggregation focuses on packaging small distributed forms of generation, such as combined heat‐and‐power plants, into ‘virtual’ power plants which can be offered into wholesale markets or to other market participants. Businesses adopting one or both of these aspects are beginning to emerge, especially in the United States where the Federal Energy Regulatory Commission has actively supported the development of demand‐side programs through mandating their potential to bid to provide ancillary services22. Controllable demand response is also currently being offered into capacity markets in the North‐eastern United States and Western Australia. In the United States, some states have authorised a form of municipal aggregation as a way of quickly delivering tangible reform benefits to residential consumers, while helping to develop their understanding of retail markets and products, with a view to developing consumer confidence and capability to effectively exercise choice independently (DEGF, 2011). Load aggregation helps to reduce transaction costs that might otherwise act as an undue barrier to mobilising demand‐side participation. In so doing, it is supporting the development of more

22 FERC requires independent system operators and regional transmission organisations to “accept bids from demand response resources, on a basis comparable to any other resources, for ancillary services that are required in a competitive bidding process” including to supply to supply imbalance, spinning reserves, supplemental reserves, reactive and voltage control, and regulation and frequency response. See FERC 2008 for details.

Russian Electricity Reform 2013 Update: © OECD/IEA 2013 Laying an Efficient and Competitive Foundation for Innovation and Modernisation

flexible electricity markets, resulting in a range of wider economic benefits including deferring expensive incremental investment in generation and networks to meet peak demand, improving power system reliability and strengthening customer choice by offering an innovative range of products and services that create value for consumers and encourage more active demand‐side participation in retail markets, especially among the lower volume customer classes. Russian Page | 64 policy makers and regulators may wish to consider these developments and opportunities to enhance market rules to ensure that they do not create undue barriers to the emergence of innovative forms of retail competition. Close monitoring and supervision of retail markets will be required to identify and eliminate barriers as they emerge especially during the early stages of the development and evolution of contestable retail markets. IEA understands that a package of measures is being developed to help address a range of potential barriers to entry and is dexpecte to be considered by the Government shortly. Effective competition supervision will be needed to support competitive retail market development. This is likely to be especially important at a regional level given the highly localised and relatively fragmented nature of the retail sector at present. FAS is taking a proactive approach to retail market monitoring and enforcement, including identifying potential barriers to entry at the retail level and opportunities to strengthen the supervisory framework to promote more effective retail competition. It is also developing frameworks to promote access to metering information to support competitive new entry, innovative product development and to help inform more effective customer choice. FAS also seeks to strengthen transparency through various public reports including its annual review of retail market developments. These are positive developments. FAS will need to build on this foundation to ensure that competition supervision remains effective and continues to support the development of competitive retail markets.

Retail market arrangements

Russian s have recognised the importance of developing a competitive retail sector that promotes innovation and effective customer choice to help maximise the benefits delivered to end‐users. Large‐scale industrial and commercial users are currently legally contestable. Residential users remain regulated. However, concerns have been raised about the capacity to exercise choice in practice. As previously noted, several stakeholders identified a range of barriers and high transaction costs that substantially limited their ability to exercise of choice in practice including: restrictions on access wholesale markets; limited retail level competition providing a narrow and largely unattractive range of products and services; legal and contractual restrictions and uncertainty, especially affecting switching; limited transparency and availability of information to support effective decision‐making, for consumers, potential new entrants and for innovative product development. Several of these weaknesses have been recognised by Russian authorities, with reform efforts focusing on clarifying the underpinning legal and regulatory framework and market rules governing retail market roles, responsibilities and transactions, for regulated and contestable customers. For instance, the provisions on market rules and regulatory arrangements released in May 2012 include provisions to improve access to the wholesale market, contracting standards; metering, billing, switching and disconnection standards; and clarity around pricing and price regulation (Russian Federation, 2012a).

Clarity on these matters is a necessary precondition for the effective functioning and development of competitive retail markets for electricity. In particular, a framework that clearly defines roles, responsibilities and obligations on parties is needed to establish an appropriate contractual basis for supply supported by effective dispute resolution and default mechanisms. Key issues associated with data exchange and ownership, settlement rules, metering responsibilities and consumer protection should be addressed in this context (European Page | 65 Commission, 2010; Eurelectric, 2011a). Legal and regulatory arrangements will need to evolve as markets develop. IEA experience also suggests that the effectiveness of the legal and regulatory framework can be greatly enhanced if it is supported by a well‐functioning marketplace that creates strong commercial incentives for efficient and innovative commercial behaviour to empower customer choice and strengthen incentives for more flexible demand response. The importance of establishing competitive wholesale and retail market structures in this context has been discussed. In Europe there is growing support for designing retail markets around the centrality of the retailer‐customer relationship. Under this approach, the retailer becomes the primary interface with the customer, providing the first point of contact for questions regarding switching, billing and moving in or moving out, while customer needs and requirements should drive the development of easily understood and comparable products and services. Under this model, distribution businesses act as ‘neutral facilitators’, providing the necessary information and infrastructure base on a non‐discriminatory basis to all market participants, new entrants and consumers, subject to appropriate confidentiality requirements, to support the development of dynamic retail‐level competition, while refraining from participation in the retail market. Similar principles appear to underpin the retail market model being implemented in Russia. The Council of European Energy Regulators (CEER) has identified four key principles to guide the development of effective retail markets (CEER, 2012).  The retail market model should be intuitively comprehensible for customers. The customer should understand without great effort which market actor to contact if they have questions related to electricity or gas. This requires that the roles and responsibilities of each market actor towards customers are well‐defined and customers are properly informed about them.  The retail market model should enable optimal customer service. This means that there should be several easy ways to reach the relevant market actor, and that the customer should have easy access to customer service and receive accurate answers as quickly as possible.  The retail market model should provide a level playing field to ensure competitive retail energy markets. It is important to ensure that the chosen interface model does not give any structural advantages to any market actor and thus hinder competition.  The retail market model should ensure cost efficiency. When designing a retail market model, the costs of each process within this model should be considered. CEER considers that a competitive retail market built on these principles most effectively aligns market roles and functions with commercial incentives, reinforcing retailer incentives to represent customer interests in a way that has the potential to deliver more effective customer choice with greater innovation and more cost‐effective products and services. European industry has espoused similar principles (Eurelectric, 2011a). Beyond this, IEA experience suggests that translating the legal and regulatory framework into practical rules and processes that minimise transaction costs, while supporting competitive entry, innovation and exercise of choice is a challenging task. An integrated and seamless approach is needed to address these practical challenges in an effective manner. Key issues that may need to be considered in this context include: establishing the commercial processes needed to facilitate

Russian Electricity Reform 2013 Update: © OECD/IEA 2013 Laying an Efficient and Competitive Foundation for Innovation and Modernisation

competitive entry and exercise of customer choice; access to accurate and timely information; building customer awareness and engagement; and effective use of enabling technologies.

Key retail market processes and practices Contractual arrangements provide the foundation for transactions in competitive retail markets Page | 66 for electricity. It is important that contractual arrangements provide clarity and certainty to counterparties around their role, responsibilities and accountabilities. Large volume industrial and commercial users typically have the resources, capability and financial incentive to negotiate effective supply contracts. However, this has not necessarily proven to be the case for smaller volume commercial and residential customers. Contracts for small volume consumers need to be simple and standardised to the greatest extent possible to help clarify and protect counterparty rights at least cost. Russian policy makers have taken positive steps in this direction with the initiative to develop model retail supply contracts as part of the response to improve customer service quality standards (Russian Federation, 2012a). Recognising these concerns and the importance of having a credible contractual framework to support the introduction of full retail contestability, the European Union requires the inclusion of minimum standard terms and conditions for contestable small volume retail contracts. Key elements to be addressed include:  identity and address of supplier;  description of the service to be provided, including types of maintenance services;  methods for obtaining current information on all applicable tariffs and maintenance charges;  the duration of the contract, conditions for renewal and withdrawal, including whether an early exit fee will be charged;  information on compensation or other refunds that may apply in the event of contracted service quality levels not being met, including in relation to inaccurate or delayed billing; and  information on consumer rights including complaint handling arrangements and methods for initiating procedures for settling disputes (European Parliament, 2009, Annex 1). Switching experience from liberalised electricity retail markets in IEA countries suggests that transaction costs and delays associated with switching processes have the potential to be a significant barrier to effective exercise of choice (AEMC, 2012a). Every effort should be made to minimise these costs to the greatest extent possible. In this context, CEER has identified switching and billing arrangements as key processes that need to be managed in an efficient and seamless manner. CEER’s latest recommendations in relation to switching and billing are summarised in Box 9. IEA experience suggests that simple and seamless rules and processes are needed to encourage competition, choice and demand response. ‘Back office’ processes need to be efficient, ensuring effective data exchange to support high quality functioning of switching processes. Meter operators need to provide information to market participants in a timely, efficient and non‐ discriminatory manner, while protecting consumer privacy and commercial confidentiality. Similarly, billing processes need to provide accountability and transparency and be implemented in a manner that does not discourage choice. Russian policy makers, regulators and market institutions will need to actively engage with market participants in the context of developing key retail market processes to ensure that they facilitate dynamic retail competition and promote effective customer choice.

Box 9 • Council of European energy regulators recommendations on good practice switching and billing processes

Switching:  A switch should be executed as quickly as possible. This could be as quickly as within 24 hours and in any case within three weeks, consistent with European Union Third Directive minimum Page | 67 standards.  A supplier switch should be possible any day of the week.  No market actor should be able to stop an initiated switch except for limited cases foreseen in the regulatory framework. Billing:  Retailers should be mandated to issue bills that include both supply and network charges separately itemised.  The final bill on switching or termination of service should be received by the customer as soon as possible. This could be as quickly as within two weeks and in any case within six weeks.  The customer should be offered at least two different payment methods, which are easily accessible and at least one of them should be free of charge.  The customer should have a choice of a minimum set of different billing and payment frequencies, including the possibility of a monthly frequency. Source: CEER 2012.

Access to information Access to accurate and timely information will be crucial for the emergence of dynamic and innovative electricity retail markets. Specific information about the location of individual customers, their volume of consumption and the nature and pattern of their usage are needed to support the development of more innovative products and services that support retailer competition and competitive new entry to help empower customer choice and ultimately maximise demand‐side flexibility. If such information is only available to incumbents, this may confer a substantial competitive advantage over potential new entrants, which may distort efficient market development and undermine incentives for developing innovative, timely and effective products to facilitate customer choice and mobilise demand response. Distribution system operators (DSO’s) also need access to real‐time technical data to support efficient monitoring and management of power systems to maintain system security, especially to maximise the benefits from ‘smart’ metering and ‘smart’ grid infrastructure where it is present. DSO’s may also need access to information about the nature of supply contracts so that they can facilitate the operation of well‐functioning retail markets by providing information to all retail market participants in an efficient, timely and non‐discriminatory manner. Consumers will need information that enables them to quickly and effectively assess their own consumption and compare various offers from different service providers, to help improve their awareness and facilitate more effective exercise of choice. While policy makers, regulators and market institutions also need information to allow them to monitor market developments and to respond in a timely manner with appropriate policy, regulatory and rule changes. Access to data and data exchange are emerging as key practical issues affecting the development of retail markets among IEA member countries. Data collection, management and dissemination needs to be undertaken in a manner that: ensures non‐discriminatory access; provides timely

Russian Electricity Reform 2013 Update: © OECD/IEA 2013 Laying an Efficient and Competitive Foundation for Innovation and Modernisation

access to sufficient information to support effective decision‐making by all stakeholders; protects privacy and confidentiality; and minimises data collection and management costs. Several models of information management and exchange are emerging in Europe including:  Bilateral Systems: Market participants manage data and exchange it on a bilateral basis as required. This is the most common form of information exchange across Europe at present. Page | 68  Data Hubs: Hubs facilitate exchange of bilateral information by providing a ‘post box’ and data quality checking service before information is forwarded to its final destination.  Centralised Databases: Under this model exchanged information is checked and stored, providing added value by supporting efficient record keeping, storage and non‐discriminatory access to information. The United Kingdom is currently developing a facility of this kind. A trend toward information exchange through data hubs can be observed in Europe, either covering all transactions or more limited forms that focus on facilitating customer switching. According to Eurelectric, centralised models are likely to be preferred as a means of helping to manage an increasingly complex real‐time operating environment reflecting the introduction of ‘smart’ energy systems, more sophisticated real‐time pricing products and growing deployment of variable renewable distributed generation. DSO’s might be effective in this role given their requirements under the European Union Third Directive. The relative merits of these options requires further consideration, particularly in terms of their implications for data quality, cost‐ effectiveness and market governance (Eurelectric, 2011a). Irrespective of the model chosen, policy makers and regulators will need to establish data standards addressing the nature, scope, coverage and frequency of data collected and the rules pertaining to accessing data. Data that is deemed essential to informing customer choice and facilitating competitive new entry should be made freely available to minimise transaction and information gathering costs, with access to other data restricted according to ownership and functional responsibility. Data security and privacy are key preconditions for effective market operation and development, while helping to build confidence among market participants and willingness on the part of consumers to actively exercise choice. All market participants should know who has access to their data and for what purpose. An effective privacy framework needs to ensure security of confidential data while permitting sufficient access to support the development and deployment of innovative products and technologies. Spanish legislation has sought to address these issues by defining which data can be shared. These requirements are summarised in Box 10. Policy makers and regulators in several IEA jurisdictions are reviewing data management standards and arrangements to ensure that an appropriate balance is maintained, particularly with the deployment of smart metering systems that are expected to substantially increase the volume and range of data available. Russian policy makers have entrusted retail market data collection and management to the Market Council. The Market Council may be well placed to offer a more centralised service and possibly act as a neutral facilitator promoting access to information and information exchange between retail market participants and distribution system operators, leveraging its information technology systems and experience to develop a least cost solution that can effectively interface with the wholesale market management system, as appropriate. Issues around the nature, scope and coverage of information to be collected will need to be considered in this context. For instance, data on switching provides a key indicator of the health of competition and exercise of choice and is of value to all market participants, as well as policy makers and regulators. However, little or no switching data is currently available in Russia. Such issues need to be addressed. Policy makers, regulators and market institutions should look to

© OECD/IEA 2013 Russian Electricity Reform 2013 Update: Laying an Efficient and Competitive Foundation for Innovation and Modernisation develop data standards and management processes in close consultation with market participants to deliver effective and least cost solutions that promote greater transparency, competition, innovative product development and effective choice.

Box 10 • Spanish standards for sharing retail‐level electricity information

Page | 69 Spanish legislation requires distribution companies to make a range of information on retail electricity transactions and consumption freely available via an online system including:  Consumer information including: location of the point of supply, physical or legal person, regular residential consumer or not;  Contract terms and conditions including: type of access tariff; date of last change of access tariff, date of last change of supplier, payment terms and conditions;  Consumption information including: usage over the previous two years, day, month and year of the last reading, type of consumption profile, type of usage;  Information related to defaults and arrears and on whether the customer has had payment problems in the past; and  Technical data including : voltage, maximum power, type of metering, and availability of power control management systems. Source: Eurelectric 2011a.

Consumer awareness and engagement IEA experience to date suggests that a knowledgeable and active consumer base that is able to effectively exercise choice is a key precondition for the successful introduction and development of competitive retail markets for electricity. However, developing this awareness and seeing it translated into active and sustained customer engagement has proven to be a key practical challenge, especially among the smaller‐volume customer classes in fully liberalised retail electricity markets. Transaction costs for small consumers to develop and maintain the understanding needed to effectively exercise choice can be very high relative to the potential benefits, especially in retail markets characterised by a lack of transparency, or a proliferation of products and service that are not easily comparable. For instance, in the United Kingdom concerns have been raised about the combination of complex tariff information, a multitude of incomparable product offerings and poor supplier conduct producing growing mistrust of retailers and anxiety among small volume consumers, with many smaller volume consumers exposed to the risk of poor switching decisions and disengaging from the market. Ofgem analysis of switching behaviour in the United Kingdom suggests that up to 60% of smaller volume customers are effectively disengaged from the retail market, with a further 20% to 30% either relatively passive or reactive participants. Ofgem concluded that only 5% to 10% of consumers in the United Kingdom were proactive market participants who research alternative offers and will switch tariff or supplier without prompting (Ofgem, 2011b). A large proportion of ‘sticky’ customers23 can have several adverse consequences for the development of competitive and innovative retail markets. High levels of disengaged consumers reduces the liquidity and depth of retail markets and can therefore decrease the potential for

23 A ‘sticky’ customer can be defined as a consumer that chooses not to switch or cannot switch due to their circumstances, or is discouraged from switching by complexity, insufficient information or mistrust. Ofgem has expressed concerns that many of these customers are also likely to be vulnerable consumer who may be missing out on competitive deals that may save them money. See Ofgem 2011b for details.

Russian Electricity Reform 2013 Update: © OECD/IEA 2013 Laying an Efficient and Competitive Foundation for Innovation and Modernisation

competition among retailers. This can act as a practical barrier for new entry and the development of more cost‐effective and innovative products and services. ‘Stickiness’ can also confer advantages on incumbents by allowing them to pass through unreasonably high cost increases in the knowledge that they are unlikely to loose many customers to competitors. On the other hand, potential new entrants are likely to have far fewer ‘sticky’ customers, reducing Page | 70 their ability to pass on cost increases compared to incumbents. This can result in reinforcing barriers to entry and business development for smaller new entrants which are generally at the forefront of driving innovation and competitive market development. It can also result in ineffective exercise of customer choice that weakens competitive incentives to offer more cost‐ effective and innovative products and services. Ultimately if left unchecked, these developments can deliver ineffective choice, limited new entry and reinforce incumbent market power; all of which can lead to higher prices and jeopardise the development of competitive retail markets that deliver tangible benefits to end‐users. Policy makers and regulators in leading practice IEA jurisdictions have recognised the risks and are developing a range of responses. For instance, Ofgem has proposed to improve tariff comparability for smaller consumers by requiring retailers to offer a limited number of standard products that facilitate comparison based on a standard unit price. Ofgem has also proposed that small volume users be provided with advice on switching processes and how to use available information to evaluate their options, including independent verification of switching sites to help build consumer trust (Ofgem, 2011b). Priority needs to be given to raising awareness and understanding, especially among small volume customers, so that they are able to effectively exercise choice and benefit from market‐ based reforms. Access to accurate and timely information is critical for building a more knowledgeable and well‐informed customer base in this context. This was recognised in the European Union Third Directive which established that customers are entitled to receive all consumption data in an easily understandable and harmonised form that will enable them to assess their consumption patterns and compare costs with offers from alternative suppliers (European Parliament, 2009). In 2011, the European Commission established a working group comprising regulators, industry participants, consumer groups and other experts to advise on ways to improve market transparency and consumer awareness, with a view to building consumer confidence and willingness to more actively and effectively participate in retail markets for electricity. Recommendations from the final report of the working group include (European Commission, 2012c):  Improving Understanding of Offers. Action is needed so that consumers are protected and can feel confident and equipped to participate in energy markets. In particular, consumers should be able to readily compare offers on the basis of unit price, with the competitive and regulated elements of the price clearly identified.  Improving Consumer Knowledge and Understanding. All market participants including regulators, industry participants and consumer bodies, should work together to improve awareness by focusing on developing and disseminating information on issues of greatest interest to consumers, such as energy market functioning, smart meters, price changes, green energy and how to improve management of energy consumption.  Presentation of Information. Information should be provided in plain language. Contracts should include a summary of consumer and supplier rights and obligations. The same price references should be used in the offer, contract and bill. Advertising should avoid exaggerated or misleading claims.

 Product Comparison Tools. The accuracy and objectivity of price and product comparison tools should be independently verified by a credible party, either a regulator or consumer body, with credible providers receiving official certification that will be instantly recognised by consumers. Alternatively, regulators should provide comparative information and assessment tools.  Informing Vulnerable Consumers. Information needs to be made available in a variety of forms Page | 71 to maximise access including print, telephone call centres, and online. Cultural, linguistic and literacy issues should be considered. Information needs to target key issues to help protect consumers from unscrupulous practices and products that are not in their interests.  Developing Effective Consumer Organisations. Consumer organisations have an important role for transparency, scrutiny and building consumer confidence in competitive retail markets for electricity. Governments and regulators need to actively nurture and develop them so that they can make an effective contribution to advancing competition, developing innovative solutions for consumers and fostering consumer empowerment. In particular, they could have a role in helping to disseminate information on innovative products that may improve small consumer engagement such as joint purchasing or collective switching programs.  Complementary Voluntary Enforcement. Regulatory provisions could be enhanced and complemented through the use of voluntary codes of practice, stronger retailer competition and dissemination of information on good practices. The combination of voluntary codes with the active threat of enforcing ‘safety net’ regulatory measures could provide a strong incentive for prudent behaviour that could improve the functioning of energy markets at least cost. Consumer awareness and engagement is expected to improve considerably with the increasing deployment of smart metering systems and in‐home displays, regular usage‐based bills, and web‐ based portals to help facilitate product comparison, which have the potential to reduce searching and transaction costs, while better informing more effective choice. Product comparison tools have great potential in this context with a variety of sites emerging across IEA member countries. A leading practice example that applies many of the principles proposed in the European Commission working group report is the Texas Electric Choice Program. The website and all material is provided and managed by the Public Utility Commission of Texas, giving it strong credibility as a reliable and trusted source of independent and objective advice. The website is supported by a toll‐free call centre; the Texas Electric Choice Answer Centre. A broad overview of how the Texas Electric Choice Program website is organised and the kind of information it provides is provides in Figure 9 below. The website provides a targeted yet relatively comprehensive range of information in a well‐ organised and readily accessible form, with most information available within three clicks from the home page. Information is presented in plain language and addresses the key issues customers need to consider when contemplating a switch. It includes information that:  educates customers about competitive electricity markets and choice;  explains the switching process;  guides customers step‐by‐step through the decision‐making processes underpinning an effective choice; and  provides comparable information on all retail products offered to Texan electricity customers including information comparing:  the average price in cents per kWh, based on 1,000 kWh consumption per annum;  cost per kWh;

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 rate type;  renewable energy content;  contract term; and  cancellation fees (where applicable).

Page | 72 Figure 9 • Organisation and content of the Texas electric choice program website

Home Page

Electricity Why Switch? Compare Offers Resources Basics

Process Overview Reasons Publications Overview

Links covering a Step 1: Questions to range of issues Understand Low Income Ask Yourself Choices

Step 2: Switching Questions to Your Rights Process Ask Providers

Step 3: Ways to Save FAQ’s Compare Offers

Source: IEA synthesis based on Texas PUC 2009 and review of the Texas electric choice website. The site also provides a range of practical resources including a comprehensive range of frequently asked questions, information on energy efficiency and how to reduce electricity consumption, and guidance on consumer rights for low income and vulnerable customers. This approach has proven very effective in educating small volume consumers, promoting consumer trust and engagement, and in supporting the development of the most dynamic retail market for electricity in North America (DEGF, 2012). Russian authorities have recognised the need to provide credible information to support retail market development and more effective exercise of customer choice. The Market Council launched a website in late 2011 that identifies all retailers operating in each Russian region and provides information on average wholesale electricity and capacity prices and average tariffs charged by GS’s. However, it does not include information for independent retailers. Consumers are obliged to contact independent retailers directly for product information (Kuleshov et al., 2012). This website is a positive development that can help to address concerns expressed by several stakeholders about a lack of transparency and high transaction costs associated with exercising choice in Russian retail markets. However, more could be done to improve transparency, scrutiny and consumer awareness, with a view to strengthening consumer engagement and customer choice. This will become increasingly important as opportunities for retail market development emerge with the unwinding of cross‐subsidies and the introduction of more cost‐reflective pricing, and especially if policy makers decide to pursue full retail contestability in the future. For now, policy makers,

© OECD/IEA 2013 Russian Electricity Reform 2013 Update: Laying an Efficient and Competitive Foundation for Innovation and Modernisation regulators and market institutions could consider options to improve consumer awareness and engagement, particularly among the smaller volume contestable customer classes. The Market Council website may provide a useful foundation on which to build. Given the nature and scope of the Market Council’s responsibilities it may also be well placed to develop information and comparison tools that are comprehensive and can deliver independent and credible advice to the market. However, web‐based information may not be sufficient to effectively reach all Page | 73 consumers, particularly smaller contestable customers, and may need to be complemented with plain language materials and possibly call centre options as proposed under the customer service quality standards initiative. Policy makers and regulators might also review regulatory and administrative processes to protect consumers including rights of appeal and recourse procedures.

Enabling technologies Leading IEA jurisdictions are also in the process of introducing a range of enabling technologies that provide cost‐effective, real‐time metering information, verification and control capability to support the development of innovative products that deliver greater demand‐side flexibility and more effective customer choice. In particular, ‘smart’ metering has the potential to become a key enabler for the more timely and effective exercise of customer choice and demand response. Advanced meters can improve competitive market functioning by improving transparency and quality of information, as well as facilitating retail switching and the development and delivery of more innovative products and services that value flexibility and quality. Advanced meter infrastructure is critical to the development of a more dynamic electricity services market that promotes more efficient end use. They also help consumers make better informed choices by improving the quality of information available to customers. They can improve the quality and accuracy of billing and help reduce the incidence of fraud. ‘Smart’ meters are a key component of an integrated ‘smart’ grid, which has the potential to improve power quality and energy efficiency while reducing environmental costs. Evidence is also emerging which suggests that a combination of enabling technologies has the potential to greatly enhance demand‐side responsiveness to innovative time of use and real‐time pricing products. Analysis of results from 39 empirical studies of small customer responses to real‐time electricity pricing with and without technologies indicates that the combination of smart meters and controllable devices can greatly increase potential demand‐side flexibility and response. The results are summarised in Figure 10 below. According to these studies, enabling technologies result in a substantial improvement in price responsiveness during peak periods once peak prices exceed three‐times the off peak price. The higher the price the greater the responsiveness with critical peak prices in the order of 16‐times off peak prices forecast to deliver up to a 35% reduction in peak demand, or around 40% more than the expected results in the absence of enabling technologies (see Faruqui & Palmer, 2011 and Faruqui & Palmer, 2012 for further discussion of these studies). Enabling technologies, particularly ‘smart’ meter and to a lesser extent ‘smart’ grid technologies, are being deployed across North America, Europe and Australia. Devices are also increasingly being deployed to automatically control the function of major appliances such as air conditioning and space heating equipment, and to manage plug‐loads in more mature markets. Deployment of ‘smart’ meters has been mandated in several IEA jurisdictions and most notably in the European Union, where the Third Directive requires Member States to achieve an 80% roll‐out of smart meters by 2020, subject to deployment achieving a positive net present value based on a long ‐term benefit‐cost analysis (European Parliament, 2009; European Commission, 2010).

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Figure 10• Peak usage reductions in response real time prices: impact of enabling technologies

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Source: Faruqui & Palmer 2011. The potential costs associated with the deployment of advanced metering systems are material and could delay or defer roll‐outs, especially where they exceed the potential benefits accruing to particular customer classes. For instance, concerns have been expressed in liberalised electricity markets about the net benefit of extending smart metering to the smallest residential customers, where the potential benefits of more innovative products and services, and possible savings, may be eclipsed by the capital and installation costs. Reported costs per meter of different planned or implemented projects vary considerably from between EUR 70 and EUR 450 per meter according to various studies. Cost differences reflect a range of factors including: nature and functionality of metering equipment; density of population; nature and size of meter rollout; and geographic conditions. The European Commission’s Joint Research Centre has prepared detailed guidelines for undertaking a benefit‐ cost analysis of smart metering deployment which provides a useful foundation for undertaking such analysis (JRC, 2012). Typically, meter hardware represents less than 50% of the total cost per meter, while installation and project management can represent up to one‐quarter of total installed costs. Related network investments are also considerable, representing around 20% of total installed costs. This might suggest that distribution businesses are well placed to undertake cost‐effective rollouts given the economies of coordination they may be able to draw upon to help minimise the overall cost of deployment. Experience to date also indicates that installation costs are very sensitive to the nature of the rollout. Higher‐volume rollouts that are able to take advantage of economies of scale in equipment manufacturing and installation tend to be cheaper per unit to implement. At the same time, evidence is emerging indicating that capital equipment costs are increasing with the addition of greater functionality. The Italian experience suggests that large economies of scale may exist in the manufacturing process, with considerable additional functionality added without a substantial increase in the capital cost per unit. Costs can rapidly escalate as the number of exceptions that need to be handled individually increases.

There are a range of policy, regulatory and implementation issues which need to be carefully considered and managed in this context. For instance, regulation and legislation needs to allow adequate time for implementation. Rollouts that are undertaken too quickly can increase costs and may involve undue compromise to critical functionality and other key requirements. Advanced metering roll‐outs and the introduction of real‐time pricing can also raise consumer awareness and protection issues that requiring proactive management. An effective transitional Page | 75 strategy needs to clearly communicate the rationale and long‐term goal of these changes to customers while also providing the tools needed for them to manage their exposure to real‐time pricing. Some degree of bill protection may be appropriate over an initial transitional period, possibly including two‐part rate designs and reimbursements to offer greater bill stability (Heffner et al., 2007). The drive to minimise costs may unintentionally limit functionality, which may result in the metering constraining the development and deployment of innovative products and services. Policy makers and regulators need to carefully balance these issues when setting functional and operational standards for advanced metering infrastructure. Regulatory uncertainty can also add to investment risk and cost, especially with large‐scale rollouts that take time to implement and risk being exposed to cost overruns beyond the control of the project proponent. To help reduce any latent investor uncertainty that may dissuade timely and efficient deployment, regulators need to take a pragmatic and balanced approach that can accommodate unavoidable delays and provides for prudent cost recovery. A lack of interoperability between different owners’ assets could threaten efficient operation and development of retail markets, customer choice and demand response24. Governments and regulators need to establish standards to ensure an appropriate degree of interoperability, especially in relation to metering functionality, information access and management, and communications. Insufficient interoperability has the potential to increase transaction costs, which could discourage switching and efficient new entry, potentially jeopardising the development of retail competition, effective customer choice, and demand response. Russian policy makers and regulators recognise the need for an effective metering system to support the development of dynamic retail markets that maximise the benefits associated with customer choice. Deployment of interval metering systems has been mandated under the Law on Energy Saving and Energy Efficiency and related roll‐out programs have been established (Russian Federation, 2009). Pilot programs to test the potential for ‘smart’ metering and ‘smart’ grids have also been established. These are positive steps and have the potential to greatly improve the quality and accuracy of metering information while supporting the development of more innovative retail products and services differentiated by time of use. Some stakeholders noted that interval metering was a necessary precondition for the development of competitive retail markets and affordable given declining interval metering costs over recent years. Real‐time ‘smart’ metering was generally considered too expensive and unnecessary at this stage of market development. This is probably a fair assessment at this time. However, IEA experience indicates that simple interval metering cannot deliver the full real‐time monitoring and verification capability of a ‘smart’ metering system, which is likely to affect the development of innovative products that can maximise demand‐side flexibility over the longer term. That said, a rollout of ‘smart’ meters to residential customers is unlikely to yield a positive

24 Eurelectric defines interoperability as the capacity of systems or components to exchange information and to use information that has been exchanged effectively. Interoperability can benefit market participants by facilitating communication; reducing entry barriers; reducing transaction costs; facilitating innovation; increasing cost‐effectiveness; and improving resilience of systems and processes.

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net benefit until pricing becomes more cost‐reflective and effective choice is introduced. Given the significant costs and potential benefits, Russian policy makers could undertake a benefit‐cost assessment of the potential for a ‘smart’ meter rollout to smaller volume contestable customers as retail markets mature, with the potential to extend the assessment and rollout to residential customers once they become fully contestable. In the interim, an appropriate rollout of interval Page | 76 meters could be pursued for small volume customers where a positive net benefit is likely, especially in those wealthier regions with higher average levels of consumption.

Extending customer choice Full retail competition has been introduced in the majority of IEA member countries with liberalised electricity markets over the last decade, with the European Union Third Directive mandating the implementation of full retail contestability from 2011. There has been an extensive academic debate around the merits of introducing full retail contestability and choice for all consumers. Some have argued that full retail contestability has not lived up to expectations, reflecting a cognitive bias that discourages small volume consumers from switching, and the underlying technological paradigm that reduces incentives for retail markets to deliver effective competitive outcomes and innovation (for example, Defeuilley, 2009). Others argue that the competitive process can be effective among small volume customers, noting a growing body of evidence showing that small volume customers do respond to price incentives, where they exist, in an economically rational manner and that retail markets do deliver cost‐effective and innovative products and services where they are sufficiently transparent and competitive (for example, Littlechild, 2009; AEMC, 2008; Faruqui & Sergici, 2009). In particular, emerging evidence suggests that full retail contestability does not necessarily disadvantage low‐income and other vulnerable consumer groups (for example, Kleit et al., 2012; Faruqui et al., 2012b). Benefits can be substantially increased where advanced interval metering and load control devices are also deployed. On balance, IEA experience suggests that the introduction of full retail contestability can deliver tangible competitive benefits for small volume customers in the form of greater choice, more innovative and cost‐effective products, and improved reliability and quality of service. However, its introduction can raise a range of complex and sensitive public policy issues, especially in the context of extending competition to residential consumers. Extending retail competition to smaller volume customers has proven to be a major and time‐ consuming undertaking in IEA countries. As noted previously, implementation needs to be done in a way that engages key stakeholders and consumers, with a view to building their confidence, capability and willingness to become active market participants. And it needs to be done in a marketplace characterised by transparency and effective competition. In practice, some IEA countries have found ethat th potential benefits of extending choice to the smallest customers may be outweighed by the associated costs in certain circumstances, such as in small, isolated markets or in some rural and remote regions. It is important for the wider credibility of the reform program that full retail competition is introduced where it is likely to deliver tangible benefits to consumers. Some IEA countries have undertaken benefit‐cost assessments to inform policy makers about the merits and timing for extending full retail contestability to particular customer classes and regions. Assessments of the net benefit of rolling‐out ‘smart’ metering systems, as discussed in the pervious section, have often proceeded as part of the same exercise. A rigorous and objective benefit‐cost analysis can support good policy decision‐making and help to assure the community about the nature and scope of potential benefits for smaller volume end users. A comprehensive analysis may also provide a framework for developing effective

© OECD/IEA 2013 Russian Electricity Reform 2013 Update: Laying an Efficient and Competitive Foundation for Innovation and Modernisation monitoring and supervision of market performance. Russian policy makers may wish to consider a similar approach, with a view to implementing full retail contestability as and when it is likely to deliver tangible benefits for end users. Introduction of full retail contestability is not a policy priority in Russia at this time. However, policy makers are encouraged to give it further careful consideration given the potential tangible benefits for consumers and opportunity this may provide to help strengthen acceptance of Page | 77 electricity sector reforms across the community. Key preconditions for the successful introduction of full retail contestability should be identified and addressed including: establishing effective retail‐level competition; greater transparency; introduction of cost‐reflective pricing; consumer education; and bedding‐down the market rules and regulatory arrangements to ensure appropriate supervision and ‘safety nets’ are in place. A clear statement from the Government affirming in‐principle commitment to the introduction of full retail contestability within a reasonable timeframe, subject to demonstrating net economic benefits for consumers, could also be considered. This would help to provide further impetus for completing related reform processes including the removal of remaining cross‐subsidies and the establishment of more effective competition and customer choice in retail markets for electricity.

Cost‐reflective end‐user pricing

Cost‐reflective and transparent price signals are essential for establishing robust and dynamic incentives for efficient, timely and innovative investment, operational and end‐user responses that maximise benefits for end users (IEA, 2005c). Cost‐reflective prices help to maximise technical, allocative and dynamic efficiency through the supply chain, and are therefore a key pre‐condition for delivering electricity sector modernisation and the Government’s wider economic policy objectives at least cost. They are also a key pre‐condition for introducing full retail contestability and for securing the financial viability of market participants. Introducing cost‐reflective pricing to the Russian electricity sector has proven to be a major challenge. Figure 11 gives an indication of the progress made to rebalance tariffs date. Considerable progress has been made to improve the cost‐reflectivity of end‐user prices in Russia. Average end‐user prices have increased significantly since 2001, especially for medium‐ sized commercial and industrial users, with prices rising three to five‐fold for most customer classes over the period, albeit from a relatively low base. Much of this adjustment was achieved during the decade to 2010. Since 2010, the rate of growth in end‐user prices has slowed considerably, with average prices for industrial and commercial users showing only marginal growth if any during 2011 and 2012. By contrast, residential prices continued to grow though at a much reduced rate, with an average increase of around 13% recorded during 2011 and 2012. A combination of factors contributed to the more recent slow down in the rate of growth of end‐ user prices including:  weakening economic activity and electricity supply‐demand fundamentals in the wake of the global financial crisis; and  regulatory intervention to moderate the rate of growth in end‐user prices reflecting concerns among policy makers about: limited end‐user capacity to pay, especially among residential users; the potential impact of continuing substantial price increases on economic growth; and the impact of rapidly increasing network charges resulting from the introduction of Regulatory Asset Base (RAB) regulation of network services.

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Figure 11 • Russian end‐user electricity price trends by customer class: 2001‐12

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Note: Prices inclusive of taxes and charges. Source: APBE 2013 Notwithstanding overall tariff rebalancing progress to date, Russian electricity prices are still relatively low by international standards. Figures 12 and 13 compare Russian residential and industrial prices to end‐user tariffs in selected OECD countries.

Figure 12 • International comparison of residential end‐user electricity prices in 2011

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Figure 13 • International comparison of industrial end‐user electricity prices in 2011

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Note: Prices excluding taxes and charges for the United States. Source: IEA 2012a and APBE 2013. Figure 12 indicates that Russian households enjoyed average residential electricity prices well below OECD levels. Average prices for Russian residential consumers were just over USD 66 per MWh, or around 38% of the OECD average of nearly USD 175 per MWh and around 27% of the OECD Europe average of nearly USD 245 per MWh in 2011. Russian residential prices also compared favourably with OECD countries on a purchasing power parity basis at around USD 115 per MWh according to the Russian Energy Forecasting Agency (APBE), which was around 30% below the OECD average of USD 163 per MWh and nearly halfCD the OE Europe average of around USD 229 per MWh in 2011. By contrast, Figure 13 indicates that Russian industrial electricity prices were comparable with the lower prices paid among OECD countries in 2011, with average prices ranging from around USD 75 per MWh for larger volume industrial users to nearly USD 108 per MWh for smaller volume industrial users over the period. Nonetheless, the average Russian industrial electricity price remained 10% to 40% below prices for OECD industrial customers at around per USD 123 per MWh, and 25% to 50% below the OECD European average industrial price at around USD 150 per MWh in 2011. However, these pricing relativities were reversed on a purchase power parity basis with average Russian industrial prices significantly above comparable OECD averages. According to APBE, Russian industrial prices ranged from around USD 129 per MWh for larger volume industrial users to around USD 186 per MWh for smaller volume industrials on a purchasing power parity basis, while comparable average electricity prices for OECD and OECD European industrial consumers were around USD 119 per MWh and USD 146 per MWh respectively in 2011. There is a clear relationship between industrial and residential prices in most OECD countries, with residential prices typically between 30% and double the annual average industrial price, largely reflecting the impact of taxes and charges, and the additional network and related costs associated with delivering power to residential users. Conversely, in Russia average residential prices were between 10% and 40% lower than industrial prices in 2011, which suggests that further substantial adjustments may be needed to achieve more cost‐reflective prices, especially for regulated residential customers. Key challenges in this context include unwinding the remaining cross‐subsidies and managing end‐user price controls.

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Unwinding cross‐subsidies The Government has undertaken to quarantine cross‐subsidies to the regulated network component of end‐user pricing from January 2013 and plans to remove remaining cross‐subsidies for regulated small volume customers from 2014, which could open the way for the introduction of full retail contestability. Page | 80 Cross‐subsidies have existed between customer classes, between regions and between generation technologies. The Ministry of Energy estimates the total transfer from contestable industrial and commercial customers to regulated residential customers at around RUB 207 billion per annum at present, or around EUR 5.2 billion, representing less than 10% of total electricity sector revenue (Russian Ministry of Energy, 2012b). According to Ministry of Energy estimates, the total cost of cross‐subsidies rose by over 50% between 2009 and 2011 but have stabilised at current levels since then, probably at least in part reflecting the slowing rate of grow in end‐user prices over the same period. The Ministry estimates that cross‐subsidies increase the average cost of electricity for industrial users by around 25 kopeks per kWh consumed, or EUR 0.006 per kWh, representing a five to seven percent average increase in industrial prices. Large industrial users fund around 40% of the total transfer. Regulated residential consumers currently receive a subsidy of around RUB 1.5 per kWh consumed, or EUR 0.037 per kWh. These subsidies are largely delivered through distribution charges, and increasingly through low‐ voltage distribution charges, with some subsidies also delivered through concessional wholesale pricing associated with regulated vesting contracts used to supply regulated residential consumers. Subsidies also have regional dimensions with regions subject to price regulation, such as the Cuscuses and the Far East, benefiting from transfers funded through regulated prices that are below market levels. In addition, the heating sector benefits from cross‐subsidies funded by combined heat and power plants. Although the absolute level of cross‐subsidy is moderate, the mechanism for delivering it has resulted in a highly concentrated wealth transfer with small and medium‐sized commercial customers bearing an increasing share of the burden through substantial hikes in their low‐ voltage distribution charges25. Some evidence is emerging of large and medium‐sized businesses choosing to invest in distributed generation rather than continuing to pay inflated distribution charges. And this trend is set to continue unless cross‐subsidies are quickly addressed. Ministry of Energy analysis indicates that from 2013 it would be profitable for 40% to 50% of industrial users to exit the grid‐connected power system and build their own generating facilities under the current cross‐subsidy arrangements (Russian Ministry of Energy, 2012b). Such an outcome would have the potential to place efficient, timely and least cost sector development at risk, possibly jeopardising the Government’s sector modernisation and wider economic policy objectives. At the same time, the concentration of the subsidy among regulated residential consumers, who represent a relatively small portion of total electricity consumption, serves to increase the effective level of subsidy per unit, substantially increasing the magnitude of the tariff rebalancing challenging. Given an average subsidy of around RUB 1.5 per kWh, it is likely that most regulated residential prices would need to increase by between 50% and 70% to reach cost‐reflective levels. Despite the subsidy, some evidence is emerging of growing payment defaults, which may suggest limited scope for further rapid and substantial tariff rebalancing at this time, especially among regulated residential consumers. However, electricity costs as a proportion of household income

25 APBE notes that network charges for commercial consumers below 750 kVa represented 60.1% of their total end‐user charge in 2009, rising to 64.6% of their end‐user charge in 2010. See APBE 2011, Table 5.4.1, p316.

© OECD/IEA 2013 Russian Electricity Reform 2013 Update: Laying an Efficient and Competitive Foundation for Innovation and Modernisation remain relatively low, at around 1.2% of average household income, suggesting that considerable scope may exist for further tariff rebalancing (Porohova, 2010). A comparison of recent trends in income and electricity price growth among regulated residential electricity consumers supports this conclusion.

Figure 14 • Growth in Russian household income and electricity costs: 2001‐2011 Page | 81 800

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Note: 2001 base year = 100. Source: IEA analysis based on Rosstat 2013 and APBE 2013. Figure 14 indicates that residential incomes have grown close to seven‐fold over the decade to 2011, while a representative index of regulated residential electricity tariffs has grown around six‐and‐a‐half‐fold over the same period. This suggests that electricity costs have broadly kept pace with growing capacity to pay, with electricity expenditures as a proportion of income falling slightly by around 8% on average over the period. The data suggests that despite the substantial price increases that occurred over the last decade, the electricity pricing burden remains much the same or has even fallen marginally as a proportion income, on average, which implies that considerable capacity exists to continue a measured process of tariff rebalancing for many regulated residential consumers. Unwinding the remaining cross‐subsidies and moving to cost‐reflective pricing will be a challenging but necessary task if the full benefits of electricity reform are to be realised, including the potential to introduce full retail contestability in the longer term. Public sensitivity and likely limited capacity among lower income regulated residential users to absorb further substantial tariff increases is likely to effectively limit the pace of tariff rebalancing to a rate comparable with real growth of incomes for residential consumers, or real economic growth for industrial and commercial customers whose income is driven by growth in economic activity. A coherent and well managed implementation strategy will be required to successfully complete the rebalancing. IEA experience suggests that the most timely and effective approaches to unwinding subsidies involve increasing end ‐user payments while at the same time pursuing sector efficiencies to reduce the cost‐reflective level of prices. This dynamic is illustrated in Figure 15.

Russian Electricity Reform 2013 Update: © OECD/IEA 2013 Laying an Efficient and Competitive Foundation for Innovation and Modernisation

Figure 15 • Key features of an effective tariff rebalancing program

$/kWh Price Growth 5% pa.

Lower Cost‐reflective Price P Page | 82 1

50%

Cost Reduction 5% pa. P2 Reduced Adjustment Period

5 yrs 10 yrs Time In this illustration, the tariff rebalancing task is defined as the difference between the cost‐ reflective price and the price paid by end‐users per unit at the commencement of the rebalancing period (i.e. P1‐P2 at T0). The maximum rate of tariff increase per unit consistent with end user capacity to pay is given by the ‘Price Growth’ schedule, while the maximum rate at which sector efficiency improvements are translated into falling cost‐reflective prices per unit is given by the ‘Cost Reduction’ schedule. There are a myriad of factors that would affect the rate of change in these schedules in practice including the rate of economic growth, efficiency of end‐use, and the degree to which competition and customer choice can drive productivity improvements and innovation leading to lower unit costs. For the purposes of this illustration it is assumed that capacity to pay grows at 5% per annum over the rebalancing period, while sector productivity improvements result in a 5% per annum reduction in cost‐reflective end‐user prices over the rebalancing period. A rebalancing program relying simply on productivity improvement and cost reduction would prolong the period of rebalancing and result in higher overall transition costs per unit of consumption. In this illustration, it would take around 10 years to achieve end‐user prices that eliminate the need for subsidies. In practice, it may not be possible to achieve cost‐reflective end user pricing relying on productivity improvements alone, especially if the initial subsidised price (P2) is so low that it provides insufficient revenue to fund efficient infrastructure maintenance and investment. Such a program runs the risk of undermining efficient development of the sector, while encouraging inefficient consumption among subsidised users. Similarly, a rebalancing program that relies exclusively on increasing prices to end users may result in a long rebalancing period and higher overall transition costs per unit, including a substantial on‐going subsidy per unit. In this illustration, it would take around 10 years to reach a cost‐reflective price level that eliminates the need for subsidies. In practice, this outcome may not be financially sustainable either, especially if the initial cost‐reflective unit price (P1) is so high that it is beyond the realistic expectations of end‐user capacity to pay within a reasonable period. Furthermore, it may not be sustainable from a wider economic perspective, especially if it entrenches inefficiencies and high input costs that have substantial and on‐going negative effects on productivity and economic growth. Delivering this rebalancing program would require a long‐ term commitment that could prove difficult to sustain given the sensitivities involved, which could place successful completion of the rebalancing program at risk.

The most timely and least cost outcome is achieved with a program that employs measures to improve sector productivity while at the same time incrementally increasing end‐use payments consistent with growing capacity to pay. This two‐pronged approach results in a more timely transition to cost‐reflective prices that deliver financial sustainability for the sector, while minimising overall subsidy payments per unit (i.e. the shaded triangle in Figure 15). It also results in a more efficient sector, reflected in a lower long‐term cost‐reflective price per unit (P3) than Page | 83 under a program that relies on increasing prices to end users alone (P1), while delivering a more financially viable sector that is able to fund efficient and timely maintenance and new investment to maintain services that meet user quality and reliability requirements without the risks and likely on‐going subsidies required under a program relying largely on productivity growth to rebalance tariffs. In this illustration, a two‐pronged rebalancing program would halve the price rise needed to deliver cost‐reflective prices while also halving the time taken to complete the rebalancing from 10 to five years. IEA experience suggests that an effective program to increase regulated end‐user prices to cost‐ reflective levels may include:  Aligning Increases in End‐User Rates to Capacity to Pay. A measured approach to regulated end‐user tariff rebalancing should be adopted that aligns increases in end‐user prices to increases in incremental capacity to pay. For regulated residential users the rate of increase in tariffs could be limited to the rate of growth in household income, while for commercial users the rate of increase could be limited to an appropriate measure of the rate of economic growth, where required.  Deliver On‐Going Assistance Directly To Low Income or Vulnerable Users. Instruments to more effectively target and deliver subsidy assistance, ultimately as a community service obligation (CSO), should be developed. Direct payments will serve to reduce distortion of price signals and improve effectiveness by ensuring that support goes to those in greatest need, thereby reducing overall subsidy costs. In many IEA member countries, CSO’s are paid through existing taxation or social welfare payment delivery systems to ensure maximum transfer of assistance to target beneficiaries at least administrative cost. Indirect payment through service providers risks leakage of transfers through undue administrative charges and less effective targeting, which could reduce overall program effectiveness while increasing its cost. That said, to avoid unduly delaying implementation of more effective targeting of assistance it may be more practical to initially use established regulatory arrangements based on indirect payments delivered through concessional pricing. However, this approach should be seen as a transitional measure given the potentially harmful impact it can have on efficient price formation, market development and incentives for more efficient end‐use.  Move to Government Funded Assistance. Subsidy funding should be progressively moved from electricity consumers to the taxpayer, consistent with its treatment as a CSO. This will serve to remove pricing distortions that can undermine efficient, timely market responses, while potentially bringing greater transparency and accountability to the provision of assistance. The process could proceed as follows:  Firstly, quarantine cross‐subsidies to the regulated components of the value chain, so that existing distortions to competitive price formation can be removed and competitive benefits maximised and passed through to end‐users as quickly as possible.  Once quarantined, gradually increase budget funding of cross‐subsidies. Initially, funding may be paid to service providers where existing indirect delivery mechanisms are used to offset costs associated with providing targeted subsidies through concessional end‐user prices. Ultimately, funding should be paid directly to consumers through a more transparent and efficient OCS instrument.

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 At same time, reduce contestable commercial consumer tariffs in proportion with the decrease in their share of the subsidy funding requirement, with the change in price made explicit in their bills. Russian policy makers have recognised the need to address cross‐subsidies; to reduce the cost and improve the targeting of assistance and to strengthen price‐based incentives for more Page | 84 efficient and innovative behaviour throughout the electricity sector. A decree is currently being prepared that will set the procedures for allocating and applying cross‐subsidies for regulated residential consumers. A proposal to introduce a fixed tranche of subsidised consumption, referred to as the ‘social norm’, is being finalised in this context. Under this proposal, eligible consumers will receive a concessional tariff for all consumption up to a fixed threshold per annum. The threshold is expected to be set at a level sufficient to meet basic living requirements. Electricity consumption above the threshold in a given year will be charged the market price. Eligibility is likely to be restricted to regulated residential consumers. Subsidy costs are likely to be budget funded or financed through a levy on contestable consumers. The Ministry of Energy notes that the ‘social norm’ proposal is expected to reduce the level of cross‐subsidies, support the delivery of more cost‐reflective residential tariffs and strengthen incentives for more efficient end‐use (Russian Ministry of Energy, 2012b). Pilot programs are planned to commence from July 2013, with a national program to be implemented from January 2014. A mechanism of this kind would represent a positive step toward unwinding cross‐subsidies and introducing more cost‐reflective pricing, consistent with the good practice principles outlined above. It would help to quarantine subsidy assistance to those in greatest need, while ensuring that residential customers with greater capacity to pay and higher consumption pay more cost‐ reflective prices. Improved targeting has the potential to reduce overall subsidy costs, which will remain a significant issue given that up to 30% of residential customers may require on‐going financial assistance. Moving to budget‐based funding would help to improve transparency and accountability, while supporting more efficient price formation and market development. Introduction of more cost‐reflective prices for wealthier residential consumers may also encourage more efficient end‐use. Russian policy makers could review the current approach to tariff rebalancing, with a view to ensuring that all key elements are being addressed in an effectively integrated way that can help to minimise the transitional period and related costs. IEA experience to date suggests that the introduction of cost‐reflective pricing and related unwinding of subsidies is one of the more difficult and sensitive elements of reform. Governments often come under intense pressure to maintain transitional arrangements or other forms of price regulation. Russian policy makers could provide additional support to the rebalancing initiative by reaffirming the Government’s commitment to specific implementation milestones including an explicit and realistic timeframe for the removal of all subsidies and the introduction of cost‐reflective prices for all users. As previously noted, implementation of sector reforms should proceed concurrently to help drive productivity and cost efficiencies to deliver a gradual reduction in cost‐reflective prices over time and help to reduce subsidy costs. An integrated reform program of the kind currently being implemented in Russia that covers the whole value chain could be expected to deliver the most effective results. Issues relating to progressing reform of contestable wholesale and retail markets have been discussed. Reform of monopoly network services can also make a substantial contribution to improving sector productivity and to reducing the overall level of cost‐reflective end‐user prices. Network charges represented around 33% of total delivered charges in 2011 and up to 60% of delivered electricity costs for small and medium volume residential and commercial consumers in Russia, with between 60% and 80% of those charges relating to distribution network services

(APBE, 2012). Recent substantial increases in end‐user electricity prices have largely been driven by a rapid acceleration in network charges, particularly distribution charges. There are several legitimate drivers for increasing network charges including the need to fund efficient maintenance and new investment, and the need to lift rates of return to competitive levels that cover costs and attract efficient capital. However, several stakeholders raised concerns about weaknesses in the regulatory framework that had permitted inefficient Page | 85 investments and operating costs to be passed through to end users. Some suggested that more effective scrutiny and accountability needs to be introduced to ensure more efficient, least cost network charges in the future. Concerns were also raised about the pace of tariff adjustment, with some suggesting that network charges had been permitted to increase too quickly, raising inflationary pressures and pressure for government intervention. Growing network charges were magnified by several other factors including: strategic behaviour among local distribution companies seeking to inflate their asset base prior to the application of Regulatory Asset Base (RAB) regulation; limited cost‐reductions in response to incentive‐based regulation among distribution businesses; and conservative system operation. Together these factors have weakened performance and added to costs. Implementation of economic regulation is a complex and demanding exercise. IEA experience indicates that all regulators go through a steep learning curve initially. Inherent information asymmetry tends to magnify the challenge. On‐going adjustments are often required to calibrate regulatory arrangements in light of operational experience. IEA regulators have implemented a range of sophisticated incentives to help improve efficiency and cost‐effectiveness including specific performance requirements, typically focusing on reliability and quality of supply, to help offset the incentive to unduly minimise operating and capital expenditures to maximise returns under incentive regulatory arrangements. Leading practice regulators are expanding the range of specific incentives to include demand response given its potential to improve power system flexibility, reliability and the cost‐effectiveness of electricity services. Regulators have also developed more robust methodologies for assessing proposed operating and capital expenditures. Sophisticated ‘building block’ cost of service methodologies have been employed incorporating forensic cash flow analysis and benefit‐cost assessment of proposed investments, with results used to help determine the expenditure allowances for a subsequent regulatory period. At the same time, regulators have employed incentive‐based regulatory methodologies typically based on Retail Price Index‐X principles26. Some have incorporated sophisticated sub‐elements into the X‐factor to reflect specific incentives, while others have explored using sectorial estimates of total factor productivity to determine the X‐factor 27. Several regulators in IEA jurisdictions have adopted hybrid approaches that employ elements of cost of service and incentive based regulation.

26 Incentive regulation is a commonly used technique in the management of natural monopolies. It typically involves specifying a goal, such as maintaining network reliability, and an estimated budget. If the business can outperform the predicted budget, it can keep a proportion of the savings, with the remainder passed through as lower prices for end users. The larger the proportion of savings that network businesses are allowed to keep, the stronger the incentive. This approach contrasts with cost plus or rate of return regulation, which does not reward cost minimisation or innovation. See Productivity Commission 2012 Chapter 5 for an excellent overview of incentive regulation and benchmarking principles. 27 Total factor productivity (TFP) measures changes in the relative cost of inputs to production compared to the value of outputs generated to identify changes in the value added by a particular business, sector or region. An industry TFP growth index measures the rate at which the productivity of a group of businesses changes over time and can be used in determining the rate of change of allowed prices for regulated service providers. See AEMC 2011 for further discussion of TFP issues and uses in economic regulation of electricity networks.

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Benchmarking is increasingly being used among IEA regulators to support the application of incentive regulation28. Typically benchmarking has been applied to distribution networks and used to create incentives for more efficient operating expenditures. It is increasingly being used to inform capital expenditure analysis and to support regulation of transmission networks. Procuring sufficient, high quality data to effectively implement benchmarking has proven to be a Page | 86 substantial practical challenge. Regulators have sought to overcome data deficiencies by using a ‘panel data’ approach that supplements available information with comparable data from other markets or industries with similar capital intensive infrastructure and service characteristics. Some regulators employ end‐of‐period optimisation or review mechanisms to review expenditure over the previous regulatory period before adding it to the regulatory asset base. Such provisions can provide a useful ‘safety net’ feature, especially while regulatory frameworks and expertise are being developed, and may act as a deterrent to ‘excessive’ expenditure. However, they also introduce regulatory risk for network businesses that could encourage unduly conservative investment behaviour at the expense of reliable and efficient market operation and development. These risks may be mitigated to some degree through clearly defined trigger criteria for expenditure review or optimisation. Some stakeholders raised concerns about the capability of regional regulators to effectively implement RAB regulation. More transparent regulatory processes that incorporate public consultation have been used by IEA regulators to help address information asymmetry and to improve the quality of regulatory outcomes. Perhaps there may be scope to employ some form of ‘peer review’ or targeted consultation to help address these concerns, or to develop an association to facilitate learning and information exchange within the domestic regulatory community. It should be noted that FTS is already drawing extensively from international experience through active engagement with the international regulatory community. Consideration could be given to more formalised training and development programs to help build and maintain competence over time, supported by effective staff retention policies. Russian policy makers have implemented several measures to strengthen the RAB incentive regulatory regime. Immediate policy responses included tariff smoothing and extension of regulatory periods. A more comprehensive range of initiatives were announced in 2012 to ‘reboot RAB’ and address the deficiencies revealed to date including (Novikov, 2012; Sberbank, 2012a):  Reducing the regulated asset base by up to 20% on average across all MRSK distribution networks;  Revising the methodology for determining the regulated rate of return on eligible distribution assets, resulting in an estimated reduction in return on investment of around 12% on average in 2012 and a new transitional path toward an estimated weighted average return of 11% per annum on existing and new assets from 2017;  Introducing more effective methods of regulating distribution network operating expenditures based on a benchmarking methodology that compares performance against best in class incorporating more stringent efficiency requirements;  Introducing several measures to encourage more cost‐effective network capital expenditure including: pre‐approval of investment programs of each regulatory period; applying a ‘building block’ methodology that prescribes maximum ‘standard rate’ expenditure limits for all new

28 Regulatory benchmarking focuses on comparing the performance of a regulated entity to some representative benchmark of performance. Benchmarks for performance could include: comparison of performance over time; the average performance of the regulated sector, or comparison to an ideal firm or best practice entity, in order to measure, and (potentially) encourage, greater efficiency in the regulated entity. A wide range of benchmarking methodologies and performance indicators has been employed by regulators across IEA jurisdictions.

major capital and equipment components from January 2013; permitting prudent cost recovery only after assets are in operation; and optimising assets to be included in the regulated asset base according to actual capacity utilisation from July 2014; and  Introducing service quality and reliability standards for all regulated network entities. As of 1 November 2012, the ‘RAB reboot’ had been completed for 44 of the 65 MRSK branches, representing over 80% of the total MRSK regulated asset base. The remaining assets are currently Page | 87 subject to cost plus regulation and are expected to migrate to the new RAB regime by 2014. Overall, these are welcome reforms that have the potential to strengthen the application of RAB regulation to deliver more efficient and cost‐effective outcomes that will lower the cost‐reflective level of end‐user prices over time. However, IEA experience with ex‐post investment approval regimes and regulatory optimisation more generally have been mixed, and raises concerns about their potential to increase regulatory uncertainty that may delay or defer efficiently timed and sized network investment. This issue has been identified as a substantial barrier to efficient network development in the United States, where ex‐post regulation of network investment is more prevalent, with regulators considering various options to help reduce associated regulatory uncertainty (NRRI, 2008). Notwithstanding these comments, circumstances in Russia demanded a strong response to allow regulatory authorities to quickly reign in excessive costs. However, given the potential risks for efficient network development, Russian policy makers and regulators are encouraged to carefully monitor the impact of the new capital expenditure provisions and to adapt them as required, possibly including the application of a more ex‐anti methodology as the regulatory environment matures. Other opportunities to build on these reforms to further strengthen the regulatory framework and help reduce the level of network prices could include:  Developing an economic assessment methodology to support analysis of investment proposals based on ‘building block’ and benefit‐cost analysis principles;  Developing a comprehensive data base to improve transparency and ultimately support the application of leading practice benchmarking techniques to support more effective analysis and decision‐making, especially at the distribution level;  Enhancing and expanding reliability and quality of service incentive programs by incorporating demand response elements over the medium‐term; and  Improving transparency of decision‐making processes, including through greater use of public consultation, to support more robust decision‐making and wider stakeholder acceptance of regulatory determinations. Beyond strengthening the regulatory methodology and process, there are a range of structural and corporate governance responses that could help to reinforce and complement economic regulation to strengthen incentives for more productive and cost‐effective outcomes. Structural approaches such as legal and accounting separation, and minimum outsourcing requirements, have also been employed among IEA member countries to reinforce behavioural incentives created by corporate governance requirements and greater transparency. Outcomes have been mixed. However, IEA experience suggests that privately operated network businesses respond more effectively to incentives created by economic regulation than their public sector counterparts. Russian policy initiatives to test the potential to improve performance through private sector management of distribution businesses are a welcome development, with the potential to help improve the effectiveness of incentive regulation while delivering more cost‐effective operational and investment performance, which can reduce costs for end‐users over time. The February 2012

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announcement that Électricité Réseau Distribution France Vostok had been contracted to manage the Tomsk Distribution Company until the end of 2019 was followed by Presidential Decree 1567 of 22 November 2012 to consolidate the Federal Grid Company and MRSK Holdings to create Russian Grids. This new entity is being created to promote more effective coordination of network investment, improve efficiency and to reduce overall network investment and Page | 88 operating cost. It is scheduled to commence operations from July 2013. The number of small regional distribution companies has grown rapidly from around 450 in 2008 to over 4 000 in 2012 (Russian Ministry of Energy, 2012b). Opportunities to consolidate these smaller entities could be considered to help improve investment and operational efficiency, to strengthen reliability and emergency response capability, and to promote more effective regulation. In addition, the Government is considering pilot privatisations of up to two distribution systems in 2013, with a view to testing the potential for private ownership and management of distribution networks to improve efficiency, innovation and responsiveness to incentive regulation. If successful, these privatised entities could provide a practical yardstick by which to measure and assess the performance of other government owned and operated distribution systems under the new benchmarking regime. The pilots may also open the way for greater private participation and possible ownership of distribution business in the future. Russian policy makers are encouraged to move quickly to expand private participation in the provision of distribution network services, subject to the successful implementation of the proposed pilot projects. An integrated strategy combining some or all of the good practice elements previously discussed could be employed to further reduce the cost‐reflective level of final end‐user prices while increasing end user payments in line with capacity to pay. This would help to accelerate completion of the rebalancing task. It would also speed the removal of distortions that currently undermine efficient price formation through the value chain, with the potential to deliver more effective price signals for timely, innovative and efficient investment, operation and end use. In addition, it would facilitate the introduction of a more transparent mechanism of direct payments that will enable assistance to be more effectively targeted to those in greatest need, both during the transition and in the longer‐term. Importantly, an integrated approach would help to minimise the overall cost to the Government of providing on‐going assistance while helping to create a more sustainable commercial foundation for the electricity sector into the future.

Reforming end‐user price controls Cost‐reflective pricing combined with effective customer choice, access to time of use consumption information and incentives created by competitive market reforms can open the way for innovative products and services. These in turn can help to empower customer choice to provide greater benefits for end‐users and more efficient outcomes from a sectoral and economy‐wide perspective, consistent with the Government’s innovation and modernisation policy objectives. A range of innovative products and services are emerging in advanced liberalised markets where these conditions exist. In North America, for example, commercial and industrial users can choose from a wide range of products and services with features tailored to their specific requirements. Examples of features offered include: fixed prices from one to several years; prices indexed to a commodity price that is critical to business operations; hourly variable prices; customised billing and credit terms; green power; bundling of supply and equipment maintenance services; energy efficiency advice and energy management services; and demand response products. Similarly, residential consumers are currently offered a range of products and

© OECD/IEA 2013 Russian Electricity Reform 2013 Update: Laying an Efficient and Competitive Foundation for Innovation and Modernisation services including: green power, month‐to‐month rates, fixed‐price contracts for terms of up to five years, prepaid energy services, and a variety of bundled service options that include maintenance of major appliances, in‐home energy management devices, distributed renewable generation options, and new technologies. Similar products and services are offered in other advanced retail markets for electricity including in the United Kingdom, the Nordic markets, Continental European markets and in the Australian National Electricity Market. Page | 89 A range of price‐based and contract‐based products are emerging to support innovative product development. Price‐based products reward consumers who can modify their consumption in response to changes in wholesale electricity prices. Examples include time‐of‐use pricing,29 real‐ time pricing30 and critical peak pricing31. Contract‐based products deliver an agreed premium in advance to customers who can guarantee to reduce consumption under certain contracted circumstances. Contract‐based products typically require controllable loads with suitable monitoring and verification equipment. These forms of demand response are increasingly purchased to provide ancillary services, to meet capacity obligations, to provide reliability reserves, and to provide emergency response reserves in some cases (IEA, 2011b). These products have the potential to unlock considerable demand‐side flexibility, which can greatly improve market efficiency; reduce peak prices and price volatility; reduce investment requirements, especially in generation and network infrastructure required to meet peak demand; and improve overall power system reliability. Empirical evidence supports these conclusions. Even small volume residential consumers have demonstrated considerable potential to modify their demand in response to price signals. Recent analysis summarising the results of 24 residential time‐varying pricing pilot studies conducted by utilities in North America, Europe and Australia over the last 14 years indicates that time‐varying prices can induce substantial reductions in residential peak load consumption. Figure 16 compares the relative reduction in peak load from residential consumers exposed to dynamic pricing as part of these pilot studies. It shows significant levels of price responsiveness among residential consumers. Small volume consumers exposed to dynamic pricing signals recorded median reductions in peak demand of around 12%, with many exhibiting larger responses of between 20% and 50%. According to this research, peak prices around three‐and‐a‐ half times off‐peak prices are likely to elicit a reduction in residential demand of around 10 per cent. The rate of growth in the response diminished as the ratio of peak to off‐peak prices rose, with residential demand response levelling out at a peak reduction of around 25%. As previously discussed, the magnitude of response was around 40% greater where enabling technologies like ‘smart’ meters and controllable devices were deployed.

29 Time‐of‐use pricing (TOU) products that provide a flexible pricing structure incorporating different unit prices for usage during different time periods within a day. TOU rates reflect the average cost of generating and delivering power during those time periods. Common TOU examples include peak and off‐peak products. 30 Real‐time pricing (RTP) products incorporate pricing based on real‐time movements in electricity prices based on trade in spot markets, balancing markets or other exchanges. It links hourly or half‐hourly prices to corresponding changes in real‐time or day‐ahead power costs. Customers are typically notified of expected RTP prices on a day‐ahead or hour‐ahead basis. RTP tariffs allow consumers to see (and react to) changes in marginal costs throughout the day. The standard approaches typically involve a one‐part pricing arrangement where prices fully reflect movements in hourly or half‐hourly wholesale spot prices. More sophisticated variants may involve two‐part pricing where real‐time prices are charged for marginal usage above or below a historic baseline for consumption. Two‐part methodologies have been adopted to provide a means of protecting customers from undue exposure to price volatility. 31 Critical peak pricing (CPP) products are a hybrid combining traditional time of use rates and real time pricing design. The basic rate structure is time of use. However, provision is made for replacing the normal peak price with a much higher pre‐ determined critical peak event price under specified trigger conditions, such as when system reliability is compromised, supply prices are very high or high and low temperatures are forecast. Peak time rebate products are a variation of CPP that provide incentives to reduce consumption in the form of an electricity bill rebate rather than exposure to high prices during a critical event.

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Figure 16 • Residential demand reductions in response to peak prices

Page | 90 24

Median = 12%

11 11 9 7 6 4 3 22

Peak Reduction Range

Source: Faruqui & Palmer 2011.

Russian reforms have taken the initial steps required to unlock this potential. For instance, Resolution N442 of May 2012 included provisions that have the potential to facilitate the development of time of use products incorporating peak and off‐peak pricing. The Resolution also incorporated provisions requiring the development of a more refined range of end‐user price controls for GS’s serving regulated residential consumers, with the aim of providing greater flexibility and incentives for developing more innovative and cost‐competitive products and services. Russian authorities have made extensive use of end‐user price controls in the past. For instance, a general cap on end‐user prices was introduced in 2011 which limited price increases to 15% per annum. This cap was largely introduced to address excessive increases in network charges associated with the introduction of RAB regulation. Without the intervention, increasing network charges could have led to a substantial increase in end‐suser price that could not be justified by underlying changes in actual costs. IEA experience suggests that extreme care needs to be exercised with price regulation in liberalised electricity markets. Irrespective of the merits, such interventions invariably magnify uncertainty and regulatory risk from the perspective of market participants which can distort responses and jeopardise efficient market development. This is particularly the case at the retail level where competitive margins are usually relatively thin. In the worst case undue price regulation can quickly result in insolvency, as happened in California in 2001 (IEA, 2002). More often it undermines competitive entry and innovation, benefiting incumbents at the expense of customer choice and products that could encourage greater demand‐side flexibility. However, price control and regulation of end‐user electricity prices remains relatively common in liberalised electricity markets, especially regulation of residential consumer prices. For example, 18 of the 27 European Union member states currently employ end‐user price controls for small

© OECD/IEA 2013 Russian Electricity Reform 2013 Update: Laying an Efficient and Competitive Foundation for Innovation and Modernisation volume consumers32. Maintenance of price controls is often justified on the basis of protecting low income and vulnerable consumers. End‐user price caps may be required in less competitive markets, or where more targeted forms of regulation are absent or ineffective. They can perform a transitional role as markets move from regulation into more effective liberalisation, to help assure the community that end‐users will not face undue price discrimination before competitive pressures and disciplines are more Page | 91 fully developed. A careful balance is required, especially where they are applied while tariff rebalancing is proceeding. Caps need to allow sufficient ‘headroom’ for competitive entry and price formation to help drive the development of innovative products and services that deliver benefits to end users. The interaction between regulated prices and competitive prices needs to be carefully considered in this context. Price caps have been identified as a key barrier to the development of competitive retail markets, especially where they result in regulated prices being kept artificially below the level of cost‐reflective prices. According to analysis published by the European Regulators' Group for Electricity and Gas, more than 80% of users will choose regulated products in these circumstances (ERGEG, 2009). However, the consumer protection argument for price controls becomes less compelling as competition develops. Empirical analysis to date suggests that low income households could benefit from a move to more cost‐reflective, time‐of‐use pricing where competition is effective. This reflects their lower level of consumption during peak periods compared to the residential consumer average and demonstrated ability to shift load to off‐peak pricing periods (Faruqui et al., 2010). Figure 17 presents the findings from a study comparing the impact of moving from flat rate to time‐varying pricing products on average and low income residential user charges. The analysis suggests that around 65% of low income residential consumers would be better off immediately with a critical peak pricing product compared to a flat rate product that averages the cost of consumption cross all residential consumers. This is because low income residential consumers tend to have a flatter load curve, which means that they tend to consume less than the average during peak periods. As a result, many low income residential consumers could gain from a shift to a time varying product where prices more closely reflect marginal costs with a larger proportion of revenue collected during peak periods. There are a range of more cost‐effective and less distortionary means of protecting low income and vulnerable residential customers. Concerns about the impact of high or volatile energy prices on the welfare and capacity to pay of low income or vulnerable residential consumers can best be addressed through targeted transfers that do not unduly distort investment and consumption decisions or efficient price formation. The potential to use a direct payment, in the form of a well‐targeted and least cost CSO, has previously been discussed. Vulnerability also reflects a lack of understanding and limited capacity to exercise choice. An integrated approach is needed to address these issues including:  improving access to information to strengthen consumer awareness of products and their ability to effectively exercise choice;  access to effective appeal and dispute resolution mechanisms complemented by well‐ resourced consumer advisory organisations which can help to facilitate consumer awareness and effective exercise of their rights under law;  competitive and transparent markets that deliver benefits to end users; and

32 Retail electricity prices are not regulated in Austria, Czech Republic, Germany, Finland, Luxembourg, the Netherlands, Sweden, Slovenia, and the United Kingdom. Plans are also in place to gradually remove price controls in Portugal and Ireland. See European Commission 2012a for details.

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 effective regulatory supervision to reinforce incentives for efficient commercial responses and to penalise abuse.

Figure 17 • Impact on residential charges of moving from flat rate to time‐varying products

Residential sample Page | 92 10% Bill change (%)

0% Increase >

Percentile -10% < Decrease 0% 25% 50% 75% 100%

Low-income sample 10% Bill change (%)

0% Increase >

Percentile -10% < Decrease 0% 25% 50% 75% 100%

Note: A critical peak pricing product was used as the time‐varying pricing product in this analysis. Source: Faruqui, Sergici & Palmer 2010. Considerable progress is being made within the European Union on these matters, where implementation of effective consumer protection without unduly distorting the development of efficient and competitive retail markets for electricity has been identified as a key policy priority under the European Union Third Directive (European Parliament, 2009; European Commission, 2012a). Regulated prices can delay the timely development of dynamic and innovative retail markets, with significant economic costs for consumers and the potential to substantially limit effective customer choice and demand response. As noted in a recent European Commission communication on the development of the internal electricity market, current price regulation (European Commission, 2012a):  prevents suppliers from offering attractive services including tailor‐made and dynamic pricing products;  can lead to energy tariff deficits born by energy companies or by public finance, which may burden future energy consumers or taxpayers with serious costs where regulated prices are set below market cost;  fail to provide the right incentives for efficient energy use; and  are not conducive to the development of a competitive and economically sustainable market that sends the right price signals to secure efficient investment. In particular, the Commission notes that price regulation can be “perceived by investors as an indicator of political interference which stifles investment.” Price controls are also inherently

© OECD/IEA 2013 Russian Electricity Reform 2013 Update: Laying an Efficient and Competitive Foundation for Innovation and Modernisation regressive, favouring households with above average consumption and greater capacity to pay33. The European Commission has again called for the removal of electricity price regulation for all customer classes, while ensuring that community service obligations and protection of vulnerable consumers is adequately addressed. The Commission has also indicated that it will continue to insist that timetables for the phasing out of regulatedd en ‐user prices be included as part of member states’ structural reforms. Furthermore, the Commission has undertaken to continue to Page | 93 promote competitive retail market price formation, including through infringement cases against member states that maintain price regulation that contravenes the provisions laid down in European Union law (European Commission, 2012a). Experience in most advanced markets suggests that maintaining price regulation is likely to cause more harm than good once competitive pressures have reached an effective level. In markets where these conditions have been met to date, removal of price regulation resulted in new entry and greater product differentiation and innovation resulting in more choices for consumers. Increased transparency, diversity and innovation in tariffs can also be expected to mitigate the risk of price coordination or tacit collusion in the market. However, retail pricing is a contentious public policy issue. Governments need to be confident that markets will deliver outcomes that benefit consumers once pricing controls have been removed. Some IEA jurisdictions have sought to inform the policy decision to remove price controls with objective and independent analysis undertaken at arm’s‐length by a market institution or regulatory authority. One leading practice example is the process of competition reviews currently being conducted in Australia. Under this process the Australia Energy Market Commission (AEMC), which is the independent body responsible for managing the Australian National Electricity Market rules, has been tasked to review and publicly report on the effectiveness of retail competition in jurisdictions participating in the Australian National Electricity Market. These reviews are being undertaken with a view to removing regulation of end user electricity prices where competition is deemed to be effective. AEMC is undertaking these assessments on the basis of criteria prescribed by participating jurisdictions. Key elements of the assessment criteria include: the degree of independent rivalry within the market; the ability of suppliers to enter the market; the nature and degree of choice exercised by contestable customers; the nature and degree of differentiated products and services; the level of price and profit margins; and customer switching behaviour (COAG, 2009, Clause 14.11(a)(i)). AEMC has published a statement of approach prior to undertaking each of these reviews. The statement of approach focuses on how the AEMC intends to interpret and apply the criteria, key issues to be analysed, and its procedures for undertaking assessments34. Three of the six mandated assessments have been completed to date. Each assessment was undertaken in an objective manner using a conceptually similar analytical framework modified at the margin to reflect local circumstances. Assessments were also undertaken in a transparent manner involving extensive public consultation with jurisdictions, key stakeholders ande th community, to help inform decision‐making and build broad stakeholder and community support for the findings. Russian policy makers and regulators might consider adopting a similar approach in the context of assessing the merits of removing electricity retail price controls at an appropriate point in the future.

33 According to several stakeholders the regressive nature of price controls is already evident in Russia with wealthier Muscovites consuming up to five times the Russian residential average, and anecdotes of very wealthy consumers using subsidised electricity to heat sand on private beaches. 34 AEMC has previously published a statement of approach for each of the retail competition reviews it has undertaken to date including for Victoria (2007), South Australia (2008), the Australian Capital Territory (2010) and most recently for the current review it is undertaking for New South Wales (2012).

Russian Electricity Reform 2013 Update: © OECD/IEA 2013 Laying an Efficient and Competitive Foundation for Innovation and Modernisation

Russian policymakers and regulators should carefully monitor retail price caps, including those recently established for GS’s serving regulated residential consumers, to ensure that they provide an effective incentive for more innovative and competitive behaviour while providing sufficient ’headroom’ to facilitate the timely unwinding of the remaining cross‐subsidies, and promote new entry to support the efficient development of more competitive retail markets. During the Page | 94 transition toward cost‐reflective end‐user prices, price caps can provide a ‘safety net’ to assure policymakers and the community that sufficient regulatory protection is in place to address potential excesses or abuse. However, danger remains. Policymakers could come under considerable pressure to maintain price caps that are too low, threatening the efficient development of competitive retail markets and ultimately jeopardising the delivery of cost‐ effective and reliable services to end‐users. A commitment to review price controls and to remove them where retail markets are sufficiently competitive to deliver and sustain efficient, cost‐reflective prices that benefit consumers could be given to help reassure market participants about the Government’s commitment to completing pricing reforms.

Acronyms, Abbreviations and Units of Measure

Acronyms and abbreviations

AER Australian Energy Regulator Page | 95 AEMC Australian Energy Market Commission AEMO Australian Energy Market Operator APBE Russian Energy Forecasting Agency ATS Russian Trade System Administrator CCGT Combined Cycle Gas Turbine CEER Council of European Energy Regulators CHP Combined Heat and Power CPP Critical Peak Pricing CSO Community Service Obligation DPM Dogovor o Predostavleny Moshnosty (the mandatory contractual obligation for new generation capacity to ensure adequacy during the transition period) DSO Distribution System Operator EDF Electricite de France ENTSO‐E European Network of Transmission System Operators for Electricity ERGEG European Regulators' Group for Electricity and Gas ESOO Australian Electricity Statement of Opportunity EU European Union FAS Russian Federal Antimonopoly Service FTS Russian Federal Tariff Service GS Guaranteeing Supplier HHI Herfindahl‐Hirschman Index IES Integrated Energy Systems LSE Load Serving Entity MRSK Interregional Distribution Grid Company (межрегиональных распределительных сетевых компаний) NE ISO New England Independent System Operator NERC North American Electric Reliability Corporation NEM Australian National Electricity Market NRRI United States National Regulatory Research Institute OGK Wholesale Generating Company Ofgem United Kingdom Office of Gas and Electricity Markets OTC Over the counter trade PJM Pennsylvania, New Jersey, Maryland Interconnection PPP Purchasing Power Parity RAB Regulatory Asset Base Regulation REA Russian Energy Agency REMIT EU Wholesale Energy Market Integrity and Transparency Regulation RTP Real‐time Pricing SLR Suppliers of Last Resort SO UPS System Operator of the United Power System of Russia SUEK Siberian Coal Energy Company TGK Territorial Generating Company TOU Time‐of‐use Pricing TSO Transmission System Operator

Russian Electricity Reform 2013 Update: © OECD/IEA 2013 Laying an Efficient and Competitive Foundation for Innovation and Modernisation

VoLL Value of Lost Load VPP Virtual Power Plant

Units of measure

Page | 96 kW Kilowatt (a measure of stock equivalent to 1 watt x 103) kWh Kilowatt‐hour (a measure of flow equivalent to 1 watt x 103 for 1 hour) MW Megawatt (i.e. 1 000 kilowatts or 1 watt x 106) MWh Megawatt‐hour (i.e. 1 000 kilowatt hours or 1 watt x 106 for 1 hour) GW Gigawatt (i.e. 1 000 megawatts or 1 watt x 109) GWh Gigawatt‐hour (i.e. 1 000 megawatt hours or 1 watt x 109 for 1 hour) TW Terawatt (i.e. 1 000 gigawatts or 1 watt x 1012) TWh Terawatt‐hour (i.e. 1 000 gigawatt hours or 1 watt x 1012 for 1 hour) AUD Australian Dollars EUR European Euros RUB Russian Roubles USD United States Dollars

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