Contract No 2011/ A project within the INOGATE Programme. Implemented by: Ramboll Denmark A/S (lead partner) EIR Development Partners Ltd.

Transcription

1 Develop the model and the regulations on elimination of cross-subsidies in energy tariffs (electricity) with the support of the beneficiary (Ministry of Energy) CWP.03.BY INOGATE Technical Secretariat and Integrated Programme in support of the Baku Initiative and the Eastern Partnership energy objectives Contract No 2011/ A project within the INOGATE Programme Implemented by: Ramboll Denmark A/S (lead partner) EIR Development Partners Ltd. The British Standards Institution LDK Consultants S.A. MVV decon GmbH ICF International Statistics Denmark Energy Institute Hrvoje Požar 1

2 Document title Document status Develop the model and the regulations on elimination of cross-subsidies in energy tariffs (electricity) with the support of the beneficiary (Ministry of Energy). CWP03BY Final Prepared by Checked by Name Vidmantas Jankauskas Michael Emmerton Nikos Tsakalidis Adrian Twomey Date 17/03/ /04/2016 Approved by Peter Larsen 06/06/2016 This publication has been produced with the assistance of the European Union. The contents of this publication are the sole responsibility of the authors and can in no way be taken to reflect the views of the European Union. 2

3 Table of Contents Abbreviations...5 List of tables and figures PART 1 EUROPEAN COMMISSION Background Essence of the Activity Key Findings Ownership and Benefits of the Activity Recommendations Challenges Faced Impact Matrix PART 2 - BENEFICIARIES Executive Summary Introduction Key Deliverables Scope of Work Framework of the Report Overview of the Belarussian Electricity System Basic Principles Legal and normative framework Government s policy plans in the electricity sector Legislative framework on electricity pricing Structure and levels of electricity tariffs Tariff Settting Tariff Design Principles Tariff setting in the EU Member countries Removal of cross-subsidies Tariff setting examples from countries with high share of nuclear generation Slovakian electricity tariff structure in the early nineties Lithuanian electricity tariff structure at the beginning of the century Electricity Demand Forecast in Belarus Demand Forecasts Historical Electricity Consumption Growth Planning Assumptions

4 6.1.2 Specific Consumption Growth Rates Growth in Customer Subscription (Customer Counts) Energy Consumption Projections GDP Projections Consumer Demand Profiles Supply Outlook for Belarus Input Assumptions for the Supply Sector Conclusions Tariff Strategies to Support the Nuclear Plant of Belarus EU Practice in Tariff Differentiation Tariff Setting Approach for Belarus Case 1 Tariffs with No Load Shift Case 2 - Tariffs with Moderate Load Shift Case 3 Tariffs with High Load Shift Recommendations Electric Boilers Excess Generation in Belarus Electric Boiler in a CHP System Recommendations The final workshop on electricity tariffs and possible tariff strategy for Belarus

5 Abbreviations BaU BYR CF CHP DSO EU GDP HV kw kwh LDC LF MoE Mtce MV MW MWh SME T&D ToU USD Business as Usual Belarussian Rouble Capacity Factor Combined heat and power plant Distribution System Operator European Union Gross Domestic Product High Voltage (> 35kV) Kilo-Watt Kilo-Watt hours Load Duration Curve Load Factor Ministry of Energy Million tonnes of coal equivalent Medium Voltage (6 (10)kV or 35kV) Mega-Watts Mega-Watt hours Small-to-Medium Enterprise Transmission and distribution Time-of-Use United States dollars 5

6 List of tables and figures Title of the table or figure Page 1 List of the main power plants in the Belarussian power system 22 2 Development of electricity consumption and GDP during the last decade (based on the data provided by the Ministry of Energy) 23 3 The main indicators of the Belarussian power system 23 4 Electricity transmission system and the main power plants of the Republic of Belarus 24 5 Structure of the final electricity consumption in Belarus in Calculation and approval of electricity tariffs in Belarus 28 7 Electricity tariffs to legal persons and individual enterprises from (with an assumption of the exchange rate BYR/USD = ) 30 8 Residential electricity tariffs valid since December 1, Development of electricity tariffs for different consumer groups Cross-subsidies in electricity sectors in some East European countries Removal of cross-subsidies between residential and commercial electricity consumers in Bulgaria and Romania Time zones for setting electricity tariffs VST tariffs to residential consumers in VST tariffs to commercial consumers connected to the medium voltage network Belenergo Electricity Demand Growth (kwh; ) Planning Assumptions Specific Consumption Growth Rate Assumption Industrial Customers to Commercial Customers to Residential Customers to Industrial Consumption (kwh) to Commercial Consumption (kwh) to

7 23 Domestic Consumption (kwh) to Total Electricity Consumption Growth Trajectory to 2030 (not including losses) Total Electricity Demand Growth to 2030 (not including losses) T&D Loss Trajectory to Total Electricity Consumption (kwh) by Class to 2035 (including losses = sent-out) GDP Regressed on Energy Consumption (kwh) BaU - GDP by Sector to 2035 (USD, const 2005) GDP Per Capita to 2035 (USD, const 2005) Growth Rate Outcomes to Comparison Belenergo and Consultant s Electricity Sent-Out Electricity Demand Forecast Consumer Demand Profiles Moderate Load Shift Profiles High Load Shift Profiles Belarus Existing Power Plants Belarus Existing Power Plant Groupings (Summary) Performance Statistics Belenergo Power Plant Fleet ( ) Power Plant Efficiency Assumptions (MWh fuel / MWhe) Power Plant Cost Assumptions (USD per MWhe) Load Duration Curve for 2014 (calibration case) Typical Daily Load Profile February Typical Daily Load Profile February Case 1 - Load Duration Curves Case 2 Load Duration Curves Case 3 - Load Duration Curves Case 1 Average Annual Energy Rate Rise from 2016 to 2020 (marginal cost-basis) Case 1 Average Monthly Bill Increase from 2016 to 2020 (marginal cost-basis) 60 7

8 49 Winter Off-peak Incentives Case 2 Incentives as Discount Summer Off-peak Incentives Case 2 Incentives as Discount on Marginal Cost Rates Case 2 Average Monthly Billing Increases by Time-of-Use 2014 to 2018 (marginal costbasis) Case 2 Winter Off-peak to non Off-Peak Time-Of-Use Rates Case 2 Summer Off-peak to non Off-Peak Time-Of-Use Rates Comparison Average Monthly Bill Increase in 2020 for Case 2 over Case Winter Off-peak Incentives Case 3 Incentives as Discount Summer Off-peak Incentives Case 3 Incentives as Discount on Marginal Cost Rates Case 3 Average Monthly Billing Increases by Time-of-Use 2014 to 2018 (marginal costbasis) 58 Case 3 Average Monthly Billing Increases by Time-of-Use 2014 to 2020 (marginal costbasis) Case 3 Winter Off-peak to non Off-Peak Time-Of-Use Rates in Case 3 Summer Off-peak to non Off-Peak Time-Of-Use Rates in Comparison Average Monthly Bill Increase in 2020 for Case 3 over Case Incidents of Excess Must-Run Supply Capacity in Incidents of Excess Must-Run Supply Capacity in Approximately 45 MW fuel input is needed for the generation of 15 MW of electricity and 25 MW of heat in a modern CHP plant 65 Familiarity of the audience with the topics discussed at the workshop at the start of the event The improvement in understanding of certain topics presented during the workshop at the beginning of the workshop and at the end of it Number of responses to which topics were the most interesting and useful 72 8

9 1 PART 1 EUROPEAN COMMISSION 1.1 Background Assignment Title: Develop the model and the regulations on elimination of crosssubsidies in energy tariffs (electricity) with the support of the beneficiary (Ministry of Energy) Country and Dates: Belarus, November 2015 March 2016 Beneficiary Organisation: Beneficiary Organisation - key contact persons name and address Ministry of Energy Andrey Zorich, zorich@min.energo.by Deliverables Produced March 2016 Expert Team Members Nikos Tsakalidis, Michael Emmerton, Vidmantas Jankauskas, Andrew Malochka 1.2 Essence of the Activity The focus of the activity was to examine the extent of a looming supply over-capacity problem by taking the following steps: 1. Review and model the demand forecasts by selected consumer class 2. Assess the impact of the nuclear power plant on the supply mix and to evaluate the impact of the plant on the cost of generation (the cost of electricity purchases taking into account capacity and energy charges) 3. Analyse the consumption patterns of different consumer categories and proposed cost reflective differentiated tariffs to apply after the commissioning of the new nuclear power plant 4. Identify existing cross-subsidies and a timeline proposed for tariff rationalization, taking into account the expected commencement operation date of the nuclear power plant 5. Determine revenue requirement and average tariffs of the transmission and distribution reflecting the costs of electricity purchase, transmission, distribution and supply costs before and after the introduction of the nuclear power plant Key Findings The key findings of the activity were: 1. The load forecast and associated electricity plant merit order of dispatch shows that there will be excess generation in 2018 and The challenge for Belarus is to find ways to absorb this excess power. The options are to introduce differentiated time-of-use tariffs with incentive power sufficient to encourage load shifting to the times when excess 1 The Ministry of Energy requested that the study focus on the development of supply and associated energy tariffs; following discussion with the Ministry this activity was dropped from scope 9

10 generation is to be expected, often in the early hours of winter mornings. Another possibility is to use the excess electricity generation to heat water in large distributed electric boilers, after which the hot water can be returned to the district heating networks supplied by the CHPs Ownership and Benefits of the Activity The main benefits of the activity for the Beneficiary are: 1. The beneficiary s concern of a supply over-capacity problem was confirmed by the Consultant. The beneficiary can confidently use the results of this study as part of consensus building amongst stakeholders. The Consultant quantified the over-capacity problem through modelling, providing forecasts of hourly production by plant for years 2018 and 2020, including a measure of the excess capacity. The beneficiary can use this information to assess the impact of three mitigation options for addressing the over-supply problem as follows 1) closure of aged condensing power plants, 2) use of large scale electric boilers to absorb residual excess power capacity, and 3) use of differentiated energy tariffs with offpeak incentive during winter peak periods to increase off-peak load and absorb excess power capacity 2. The computation of differentiated time-of-use tariffs has been provided based on a marginal costing technique. The beneficiary can adjust the incentive power of the off-peak industrial tariff and see the impact on re-allocation of costs. Average costs can be readily applied to compute tariffs. The model computations will benefit the beneficiary s efforts in developing energy policy. A basic strategy and timeline for energy supply tariff changes has been proposed, with due consideration of all of the abovementioned issues; the beneficiary can use the suggestion as a basis for further developing implementation plans. The Beneficiary took ownership in the following way: 1. Received this report and tariff spreadsheets 2. The beneficiary acknowledged the results and recommendations and proposed further investigations; the proposed investigations demonstrated that the study results were well received and understood 3. Received copies of presentations during the workshop for all stakeholders 1.5 Recommendations Actions and measures recommended to be taken after completion of the activity are: 2 CHP power plant co-generation production is a must-run production. The electricity is a by-product of heat production and cannot be rejected unless the condensing steam turbine is by-passed. The nuclear plant is also considered as a mustrun plant. The plant must-run at the highest possible capacity factor to justify the high front-end capital investment. This must-run capacity leads to over-supply at times of low load, particularly in the early mornings in winter when electricity demand is low. 10

11 1. Consider to introduce seasonal time-of-use rates immediately to pre-condition electricity consumers to the new approach. A two-prong marketing campaign would be desirable, to i) explain the adjustment to the rates due to the introduction of the nuclear plant and ii) the competitive advantage that time-of-use differentiated tariffs offers Belarus, in attracting new industry and offering the opportunity for existing industry to reduce net operating costs. 2. Consider the introduction of up to 1200 MW of large scale distributed electric boiler capacity. The proper dimensioning requires a detailed feasibility study; the study should include an economic evaluation to establish whether the economic benefits are sufficient to justify the long-term investment; however, given that the economic value of the excess power capacity is otherwise zero, the payback appears to be assured. 1.6 Challenges Faced The main challenges that will be faced: 1. Tariff reform will require a well-conceived marketing and communications plan to ensure that consumers understand why tariffs should change. The timing of tariff reform should proceed in concert with the timing of the nuclear plant commissioning. Seasonal time-of-use tariffs will need to be in force in Given a lead time of only 2 years, the introduction of tariff reform is indicated as a matter of urgency. At the same time the Government of Belarus should consider a social support scheme to assist the low income consumers. This will be challenging in terms of the identification of vulnerable consumers and the reaction of the public and community interest groups to such proposals. 1.7 Impact Matrix The following impacts could be observed in 2018 and 2020 should the recommendations given in this report be followed: Impact Area Developments 2016 (%) 2018 / 2020 (%) Policy Differentiated tariffs policy - - Regulation Regulatory support for differentiated time-of-use tariffs 10% (time-of-use tariffs apply) 50% (apply incentives phase 1) / 100% (strengthen incentives phase 2) Technology Introduction of electric boilers 0% 50% / 100% of final installed capacity Environment Nil n.a. n.a. Economics Nil change Social Policy for protection of vulnerable consumers 0% 100%/100% Other Nil n.a. n.a. 11

12 2 PART 2 - BENEFICIARIES 2.1 Executive Summary The stated objectives of this technical assistance were as follows: To review and model the demand forecasts by selected consumer class Assess the impact of the nuclear power plant on the supply mix and to evaluate the impact of the plant on the cost of generation (the cost of electricity purchases taking into account capacity and energy charges); Analyse the consumption patterns of different consumer categories and proposed cost reflective differentiated tariffs to apply after the commissioning of the new nuclear power plant; Identify existing cross-subsidies and a timeline proposed for tariff rationalization, taking into account the expected commencement operation date of the nuclear power plant; Determine revenue requirement and average tariffs of the transmission and distribution reflecting the costs of electricity purchase, transmission, distribution and supply costs before and after the introduction of the nuclear power plan. After discussion with the Ministry of Energy the last objective was removed from scope. The Ministry of Energy requested that effort be squarely focussed on energy supply tariffs. In particular, the Ministry of Energy requested the Consultants to consider how time-of-use differentiated tariffs might be applied to shift electricity demand; the objective being to deal with a situation where off-peak winter must-run production is anticipated to exceed consumer demand. The objectives have been met as follows: Seasonal, time-of-use differentiated energy tariffs have been developed using a marginal-cost approach. Marginal-costing results in the highest rate of rise of tariffs and represents a worst case scenario; The extent of the winter over-capacity problem was determined by way of modelling of demand and supply for the period 2014 to 2020; total electricity demand was forecasted and supply was determined using an hourly economic dispatch technique; To mitigate against over-capacity, three mitigation options were considered as 1) closure of aged condensing power plants, 2) use of large scale electric boilers to absorb residual excess power capacity, and 3) use of differentiated energy tariffs with off-peak incentive during winter peak periods to increase off-peak load and absorb excess power capacity; The incentive power of energy tariffs has been set with reference to industry benchmarks for industrial consumers and assumptions made with regard to the expected load shift to the off-peak period; two cases have been considered a moderate incentive power and a high incentive power has been applied by discounting the off-peak rates of the commercial and industry classes; A timeline for energy supply tariff changes has been proposed, with due consideration of all of the abovementioned issues. 12

13 Observations and Findings The Ministry of Energy has a justified concern that over-capacity will result at certain times of the day in winter after the nuclear plant begins operation, particularly when both units are in service. Economic dispatch runs have been used to quantify the excess. A typical February day in 2018 shows that excess must-run capacity is likely to exceed demand (this capacity cannot be reduced without reducing heat production) Figure E1: Typical Daily Despatch Curve in February 2018 (anticipated) Source: Consultant The extent of the over-capacity problem appears to require closure of the Berezovskavya plant (commissioned in ) just prior to commissioning of the first nuclear unit in In addition, unless additional load can be developed, the Lukoml power plant may need to operate at very low annual capacity factors (30% in 2018 reducing to as low as 12% by 2020). Whilst the operating regime can be ordered to reduce the over-capacity problem it will not completely eliminate the problem. The excess capacity must either be exported, used to produce hot water for space heating, or absorbed by shifting demand to the off-peak hours (and all of the above). Table E1 shows the residual occurrences of over-capacity in 2018 under a moderate load-shift scenario 13

14 Table E1: Incidents of Excess Must-Run Supply Capacity Hours of the Year by Typical Day of the Month Excess Capacity MWe Source: Consultant To absorb excess capacity, electric boilers could be employed on distributed basis at the CHP plants; it is estimated that the electric boiler capacity would need to be 600 MW peak in 2018 rising to 1200 MW peak in The advantages of electric boilers are several. They are certain to absorb excess capacity in winter. There would be a net saving in gas consumption of the CHPs if electric boilers were used to supply district heating networks. As electricity demand growth rates are low, less than 1%, the need for large scale electric boilers will be of sufficient time duration to warrant a payback on investment In most countries, notably in the European Union, energy prices follow as a consequence of the operation of wholesale energy markets. It is common to find differentiated network tariffs used as the means to reduce peak consumption. Since peak consumption is markedly higher in the winter, seasonal time-of-use tariffs are used. In countries where energy supply prices are set by regulatory determination, a typical summer incentive power, measured as the ratio of off-peak to peak tariff rates, is around 50% for Small-to-Medium Enterprise and industry. In winter the incentive power can be as high as 85% The use of differentiated tariffs to solve an over-capacity problem has rather few precedents and the impact of such tariff reform is less certain than the impact of electric boilers. In recent years, tariff differentiation has been used as the means to avoid curtailing night-time windfarm production. In Texas for example, off-peak electricity is free for industry. In Belarus a discounted off-peak rate, with strong incentive power, could be adopted as one of the means to encourage the economic use of power plants following the commissioning of the nuclear plant. The tariff setting should be arranged such that it is revenue neutral for each consumer class. The relationship between incentive power of off-peak electricity rates and load shifting is unknown in Belarus. Anecdotal evidence suggests that industry will incur added costs to operate at night, suggesting that the off-peak incentive would need to be strong to overcome such objections 14

15 In any case, it must be recognized that the introduction of the nuclear plant will result in an increase in tariff rates due to the significant capital investment. A nuclear plant has high fixed investment costs that occur at the beginning of the life cycle of the plant operation. It is estimated that average tariffs will need to increase as shown in Figure E2 Figure E2: Average Annual Energy Rate Rise from 2016 to 2020 (marginal cost-basis) Source: Consultant In the long term energy rate rises will be modest due to the dominance of the nuclear plant in the energy mix, wherein operating costs of the plant will be relatively low. This is a selling feature supporting the introduction of the nuclear. It is estimated that the average monthly bills for each class would have to increase as shown in Figure E3. There are no cross-subsidies embedded in the tariffs; as such the monthly bill rises reflect cost recovery based on the full user-pays principle. In practice the real tariff rises may need to entertain cross-subsidies to protect vulnerable residential customers. In any case, the Government of Belarus should consider the best social support scheme to assist low income residential consumers in coping with the potential tariff increase. 15

16 Figure E3: Example Moderate Load Shift Average Monthly Bill Increase 2014 to 2020 Source: Consultant It should be noted that the tariff projections in Table E1 are the result of assumptions and parameter settings. The figures are considered indicative but should not be considered as final due to the compressed nature of this tariff study The winter off-peak to peak ratios on the residential off-peak rate, applicable to the above monthly bill increases are shown in Table E2. These rates have been computed for all load shifting cases and by time of season. Table E2: Example Moderate Load Shift Winter Off-peak to non Off-Peak Time-Of-Use Rate Ratio Peak 1700 to 2359 Shoulder 0700 to 1659 Off-Peak 2400 to 0659 Peak 1700 to 2359 Shoulder 0700 to 1659 Off-Peak 2400 to 0659 Residential Commercial Industrial Source: Consultant Recommendations 1. Consider to introduce seasonal time-of-use rates immediately to pre-condition electricity consumers to the new approach. A two-prong marketing campaign will be desirable, to i) explain the adjustment to the rates due to the introduction of the nuclear plant and ii) the competitive advantage that time-of-use differentiated tariffs offers Belarus, in attracting new industry and offering the opportunity for existing industry to reduce net operating costs 16

17 2. Clearly tariff reform will require a marketing and communications plan to ensure that consumers understand why tariffs should rise. The timing of tariff reform should proceed in concert with the timing of the nuclear plant commissioning. Seasonal timeof-use tariffs will need to be in force in Given a lead time of only 2 years, the introduction of tariff reform is indicated as a matter of urgency. At the same time Government of Belarus should approve a social support scheme to assist the low income consumers 3. Differentiated tariffs will encourage load shifting to off-peak periods but given the lack of experience with such tariffs in Belarus it would be unwise to depend solely on this tariff reform. It is strongly recommended to introduce up to 1200 MW of large scale distributed electric boiler capacity. The proper dimensioning requires a detailed feasibility study; the study should include an economic evaluation to establish whether the economic benefits are sufficient to justify the long-term investment; however, given that the economic value of the excess power capacity is otherwise zero, the payback appears to be assured. 3 Introduction This Introduction contains a description of the key deliverables and the scope of work for this assignment. 3.1 Key Deliverables The key deliverables are as follows: A detailed report addressing the questions raised by the beneficiary; A workshop designed to explain differentiated tariffs in the EU and tariff setting principles and practice. 3.2 Scope of Work The scope of this report covers the following: To review and model the demand forecasts by consumer class; Assess the impact of the nuclear power plant on the supply mix and evaluate the impact of the plant on the cost of generation (the cost of electricity purchases taking into account capacity and energy charges); Propose strategies to mitigate against an over-capacity problem; Analyse the consumption patterns of different consumer categories and propose cost reflective differentiated tariffs to apply after the commissioning of the new nuclear power plant; Identify existing cross-subsidies and a timeline proposed for tariff rationalization, taking into account the expected commencement operation date of the nuclear power plant; and; Present and discuss the outcome of the consultation with the beneficiary. 3.3 Framework of the Report This report comprises an Executive Summary, Abbreviations, and seven sections. The Executive Summary and Abbreviations are provided at the beginning of this report. 17

18 Section 1 comprises this brief introduction Section 2 presents an overview of the Belarussian power system Section 3 presents a discussion of tariff setting Section 4 presents an electricity demand forecast for Belarus Section 5 presents the results of electricity supply economic dispatch runs, 2014 to 2020, and a marginal supply cost analysis Section 6 presents a discussion of the use of electric boilers to absorb excess supply capacity Section 7 summarizes the proceedings and outcomes of a workshop held in Minsk on

19 4 Overview of the Belarussian Electricity System 4.1 Basic Principles The electricity sector in Belarus is vertically integrated. All the functions of transmission, distribution and supply are carried out by the holding company Belenergo State Production Association (SPA) and almost all generation belongs to the same company. Belenergo SPA is 100% state owned. Belenergo SPA includes 6 subsidiaries - regional power companies (vertically integrated regional companies performing all the functions bundled together: generation, network services and supply; a construction company; infrastructure companies; maintenance and repair companies as also various research and design institutes. The total installed capacity of the Belarusian electricity system on was MW, including 41 thermal power stations (most of them are combined heat and power plants supplying with heat local district heating networks) with the capacity of MW and 12 gas turbines with the capacity of 692 MW, the main fuel there was natural gas. List of the main power plants is presented in the following table: Table 1: List of the main power plants in the Belarussian power system Power Plant Construction Installed capacity, MW Available capacity, MW Production 2014, GWh in Berezovsk TPP Lukoml TPP Novopolotsk CHP Gomel CHP Svetlogorsk CHP Mozyr CHP Grodno CHP Minsk CHP-3 with GT Minsk CHP-5 with GT Minsk CHP Mogilev CHP Bobruisk CHP Source: data provided by the Ministry of Energy There were also 23 hydro power plants with installed capacity 26.3 MW, one wind power plant of 1.5 MW and 206 units of industrial power plants with the 709 MW installed capacity in the system. During the last several years domestic electricity production was around 38 TWh. Besides the domestic electricity production significant amount of electricity was imported from abroad (mostly from Russia and Estonia), it peaked in 2012 to almost 7 TWh but slid down to about 3 TWh in 2104 and Electricity consumption in the country was growing steadily during the last decade, but not as fast the general economy, it may indicate that certain energy efficiency and saving measures were implemented (Figure 2). 19

20 Figure 2: Development of electricity consumption and GDP during the last decade (based on the data provided by the Ministry of Energy) Source: data provided by the Ministry of Energy The main indicators of the Belarussian power system are shown in the following table: Table 3: The main indicators of the Belarussian power system Indicator Value Installed capacity MW Electricity generated by the units of Belenergo SPA 31.6 TWh Heat generation 34.4 Pcal Electricity production by units not belonging to Belenergo SPA 3.1 TWh Import of electricity 3.8 TWh Export of electricity 0.5 TWh Total electricity consumption 38 TWh Losses in the grid 9.35% Length of electricity lines ( ) 276,187 km Source: data provided by the Ministry of Energy The Belarussian electricity system is well interconnected with the systems of all neighbouring countries (Russia, Ukraine, Poland, Lithuania and Latvia); it assures rather high security of supply and possibilities of international trade (Figure 4). 20

21 Figure 4: Electricity transmission system and the main power plants of the Republic of Belarus (source: Belenergo website) Source: data provided by the Ministry of Energy The main consumer of electricity in the country was industry; in 2014 it consumed about 55% of the final electricity. The share of residential consumption was 23%, commercial sector (defined here as a non-industrial ) consumed 14% of the final electricity use ( Figure 5). Figure 5: Structure of the final electricity consumption in Belarus in

22 Source: Belenergo Electricity consumption was growing during the last several years: from 33.5 TWh in 2003 to 38 TWh in At the same time period the maximum load of the system increased from 5660 MW to 6250 MW. The growing demand and increasing amount of electricity imports as also full dependence on the Russian natural gas as a fuel of almost all power plants in the country encouraged the Government of Belarus to take a strategic decision: to build a nuclear power plant with the capacity of 2400 MW, it is planned to be commissioned in 2018 (the first unit) and 2020 (the second unit). 4.2 Legal and normative framework Government s policy plans in the electricity sector Development of the electricity sector is determined by the state programmes. The programme currently under implementation is The State Programme for the development of the Belarussian energy system till 2016 approved by the Decision of the Cabinet of Ministers No. 194 on February 29, The main objectives of the Programme were: introduction of 1870 MW of new generation capacities with decommissioning of 700 MW of inefficient capacities. Among other goals were: improved efficiencies allowing fuel savings and increasing share of local fuels. Currently a new programme is drafted and undergoes an approval process. The draft is titled The State Programme for the development of the Belarussian energy system till The need for a new policy paper was based on several reasons: 1. More than 5000 MW of electricity generation capacity in the system (Lukoml and Berezovsk TPP, Minsk CHP-3, Mozyr, Novopolotsk and Svetlogorsk CHPs, Mogilev, Bobruisk and Grodno CHP-2, etc.) were introduced until 1975, their degree of depreciation will reach a critical value soon, this requires taking decisions on their substitution or upgrading. 2. The planned commissioning of the Belarusian nuclear power plant (first unit in 2018 and the second one in 2020) requires taking certain technical decisions in determining the structure of electricity generation capacity which would allow regulation of the load curve in the power system. 3. Creating a common electricity market of the states-members of the Eurasian Economic Union (Russia, Armenia, Belarus, Kazakhstan and Kyrgyzstan) will have an impact on changing the management structure of the energy system and the legislative framework will lead to the development of new mechanisms for import-export relations in the power industry. 22

23 The main goal of the Programme is to improve the reliability of the power system, economic and technological efficiency, while fully addressing the needs of the country in the electricity through the development and implementation of specific activities in line with the commissioning of the Belarussian nuclear power plant. Besides the construction of a new nuclear power plant the Programme envisages also a construction of several other power plants with a total capacity of 900 MW (some older units at thermal power plants will be decommissioned also). Construction of the nuclear power plant will allow reduction of natural gas imports from Russia by 2.5 Mtce (million tonnes of coal equivalent), and additional 0.4 Mtce reduction will be achieved by increasing the share of renewable energy as also improving energy efficiency. This would allow improving security of supply as all gas is imported from one country Russia. The Programme assumes that electricity consumption in the country will grow steadily despite its stabilisation or even decrease during the last 2-3 years and in 2020 will reach 42 TWh (growth by more than 10% in comparison with 2014). At the same time the maximal load will reach 6745 MW. Those assumptions of growth look a bit too optimistic as during the last 10 years electricity demand increased by less than 10% and there are no premises for the faster demand growth in the nearest future. As heat demand in the country was stable for the last dozen years and will not increase in the nearest future there will be no demand for a new construction of combined heat and power plants. Development of the grid will be aimed first of all to integration of the new nuclear power plant into the power system. It will require a construction of new high voltage (330 kv and 110 kv) lines, medium and low voltage lines; in total about 1500 km of new lines to be built and some existing lines upgraded and modernised. Construction of the Belarussian nuclear power plant will cause a new problem of daily load curve regulation which requires the development and implementation of specific activities. Such activities could include: electrical direct heating; installation of electric boilers at boiler houses; the direct use of electrical energy storage heat for heating and hot water supply of newly built residential, public and industrial buildings, as well as in certain technological processes; establishment of peak gas turbines; production of hydrogen; use of electrical vehicles; deeper differentiation of tariffs at day and night, at different seasons, etc. The Programme envisages a reform in the management of the power system. The reform should be developed along the following directions: unbundling of potentially competitive activities (generation and supply) from the monopolistic activities (transmission and distribution): implementation of the full cost recovery principle; implementation of competition in the competitive areas of the power sector; assurance of the balance of economic interests of consumers and producers, etc. The reforms are necessary as Belarus has become a member of the Eurasian Economic Union and this requires having a common regional electricity market with the harmonised rules and principles. On May 15, 2015 Belarus together with Russia, Kazakhstan and Armenia signed a document titled Concept of creation of a common electricity market of the Eurasian Economic Union. It envisages a 23

24 fully functioning competitive regional electricity market before As Belarussian electricity market is less developed than the markets of the three other countries it requires additional efforts of the Government of Belarus to move faster with reforms. The reform needs a legal background a law on functioning of electricity market. A Law on Electricity was drafted some time ago it undergoes discussion among different stakeholders and should reach the Parliament soon. The law alone is not enough to give a legal basis for the sector, a number of secondary legislation documents should be drafted, discussed and approved Legislative framework on electricity pricing There is no Law on electricity in Belarus, so electricity (also natural gas and district heating) pricing is regulated by other laws and regulations. There are two laws: Law on Natural Monopolies and Law on Pricing as also the Presidential Decree No. 72 from February 25, 2011 On some issues of price (tariffs) regulation in the Republic of Belarus, they define the principles of electricity pricing in the country. Article 9 of the Law on Pricing declares that The state policy on pricing in accordance to the Constitution determines the President of the Republic of Belarus. Further in the same Law Article 10 we may find that the state institutions responsible for pricing are: 1) the state institution responsible for the management of economic affairs of the country, 2) other state agencies responsible for regulation and control of prices, 3) regional and Minsk city executive institutions. In the President s Decree No.72 one may find that the President of Belarus allocated responsibilities for pricing among the different Ministries and state agencies. Electricity pricing according to this Decree is responsibility of the Ministry of Economy, but electricity tariffs for residential consumers are set by the Cabinet of Ministers. Electricity tariffs for residential consumers are set according to the Decree of the Council of Ministers titled On setting natural gas, electricity and heat residential tariffs from December 30, 2013 (as amended on February 27, 2015) No Electricity tariffs for non-residential consumers are calculated according to the Regulation on formation of prices (tariffs) for natural and liquefied gas, electric and thermal energy, approved by the Decree of the Council of Ministers of the Republic of Belarus of March 17, 2014 No According to this Decree the basic electricity tariff is a monetary value of the item supplied electricity to the consumers in Belarus, which assures reimbursement for costs associated with the production, transmission, distribution and sale of a unit of electricity, taxes and fees, as well as the means required for expanded reproduction of energy supply organisations. One may see that the cost recovery principle is clearly defined in the Government s Decree. As residential tariffs are set separately and based on different principles the cost recovery principle could not be fully implemented. In this case further in the Decree the issue is resolved in introducing cross-subsidies: if tariffs for a certain consumer group or groups are set below the cost, tariffs for other consumer groups should be increased to cover the loss for the energy company. The scheme of electricity tariffs calculation and setting is presented in Figure 6. Figure 6: Calculation and approval of electricity tariffs in Belarus 24

25 Regional affiliates of Belenergo Costs and outputs of each regional company Belenergo Total company s costs and outputs Ministry of Energy Calculated cost covering tariffs Ministry of Economy Tariffs set Non-residential consumers Calculated and proposed residential tariffs Council of Ministers Tariffs set Residential consumers Source: data provided by the Ministry of Energy The Government s Decree No. 222 clearly defines which costs are included into the revenue requirement and how they are calculated, how the output of electricity is assessed and forecasted. Profit is calculated as a return on the total costs. The current organisational and methodological system of tariffs for electricity matches the existing vertically integrated management structure of the electricity sector, where the entity carries out the full technological cycle from electricity production to its supply to the consumer. Under such an organisational structure of the industry electricity tariffs are calculated and set for end-users and contains cost of production, transmission, distribution and supply as also a fixed profit Structure and levels of electricity tariffs Electricity is sold to final end-users at regulated, unified tariffs all over the country differentiated for different consumer groups. The Government Decree No. 89 from February 10, 2015 has allocated responsibilities to the Ministry of Economy and Ministry of Energy in differentiation of electricity tariffs. The two Ministries may decide for which groups of consumers and how the tariffs may be differentiated (except for the residential consumers group). Currently there are the following groups of consumers: industrial consumers with the capacity not less than 750 KVA; industrial consumers with the capacity less than 750 KVA; electrified railway; urban electrical transport; budgetary organisations; 25

26 other non-industrial consumers; utility services in rural areas; street lighting; electricity for heating and hot water supply; electricity used in heating and ventilation systems; agriculture. Differentiation to the above consumer groups is done according to the tradition following social welfare, but not cost coverage principles. Electricity tariffs valid since are presented in the following table: Table 7: Electricity tariffs to legal persons and individual enterprises from (with an assumption of the exchange rate BYR/USD = ) Consumers group 1. Industrial consumers with the capacity not less than 750 KVA Tariff, BYR/kWh - capacity fee, BYR/kW/month Industrial consumers with the capacity less than 750 KVA Electrified railway Urban electrical transport Budgetary organisations Other non-industrial consumers Utility services in rural areas Street lighting Electricity for heating and hot water supply at night ( h) during the rest of the day Electricity used in heating and ventilation systems from 1100 to 1700 and from 2100 to 800 hours during the rest of the day Agriculture Source: Belenergo As an exchange rate changes in time (especially significant changes were during the last year) the tariffs should be adjusted according to the Regulation of the Ministry of Economy No. 24 from February 28, The commercial consumers must pay according to the relevant tariffs in Belarussian roubles indexed by the USD/BYR exchange rate on the day of payment of the bill. The indexation is performed by the following formula Тa = Тb * (0,11+0,89 Кa/Кb), where Тa electricity tariff, indexed by the exchange of the Belarussian rouble with the U.S. dollar at the day of preparation of the bill and Tb - electricity tariff, indexed by the exchange of the Belarussian rouble with the U.S. dollar at the day of paying the bill; Кa USD/BYR exchange rate at the day of preparation of the bill and Кb USD/BYR exchange rate at the day of payment of the bill. Industrial consumers with the installed capacity 750 kva and above, having the automatic system of control and distribution of electricity and capacity, can switch to two component tariffs and to the time of use tariffs. Such a system of tariffs stimulates consumers to interact efficiently with the system, as well as gives economic incentives to reduce the cost of electricity. 26

27 Electricity tariffs to residential consumers are much lower than to the industrial and commercial ones the system of cross-subsidies is in place. The latest residential tariffs valid from December 1, 2015 are shown in the following table: Table 8: Residential electricity tariffs valid since December 1, 2015 Consumers group Tariff structure Tariff, BYR/kWh 1. Residential consumers with electric stoves simple h 589 Peak time: h Residential consumers using electricity for heating At night Any other time Source: Belenergo All other residential consumers simple h 693 Peak time: h 1980 The State Programme of Development of the Belarussian energy system for the period up to the year 2016, approved by the Decree of Council of Ministers on February 29, 2012 No. 194, envisages reduction of cross-subsidies with a faster increase of residential tariffs they were supposed reaching the cost recovery level by the year Unfortunately, the economic slowdown and deterioration of the Belarussian rouble value (in comparison with the US dollar) did not allow reaching this target. Currently we see significant cross-subsidies still in place. Development of electricity tariffs for different consumer s groups is shown in the following figure: Figure 9: Development of electricity tariffs for different consumer groups 27

28 5 Tariff Settting 5.1 Tariff Design Principles Tariff design is the process by which the cost of providing the services is allocated between the consumers who incur those costs. For example, a large consumer directly connected to the transmission network should not incur any distribution costs, a consumer with a high load factor should incur a lower proportion of the cost of providing reserves than a consumer with a low load factor. When designing a tariff methodology, the following major pricing principles are taken into account: economic efficiency, cost recovery, simplicity and transparency, non-discrimination and also social affordability and political acceptance. Economic efficiency means that efficient tariff structure should signal to users the marginal costs that they impose on the regulated company and encourage the operator to utilise its assets optimally. Cost recovery means that the tariff system allows the regulated service provider to recover the operating and maintenance costs and also capital costs that are commensurate with the efficient provision of the service. Efficient regulation aims to minimise the costs to the service provider of complying with the regulation. Simplicity and transparency means that the regulated tariffs are understandable and transparent so that users can readily determine the charges they face and respond to them. Furthermore, to avoid disputes the tariff regime needs to be clear and should be based on explicit rules as far as possible. Finally, transparency can be seen as a prerequisite for general acceptance by users and the general public. Non-discrimination principles are required to ensure that a level playing field is created for all service users - all users should be treated equally, irrespective of size, ownership or other factors, i.e. non-discrimination between users even though they generate different underlying cost patterns. In practice, this means that all users should face the same methodology for calculating charges not necessarily the same charges. Social affordability and political acceptance is another important issue. Introducing cost reflective tariffs often means high price increases for smaller customers, especially, residential ones. Introduction of two component tariffs usually means also an increase of payments for small consumers (single persons, pensioners, etc.). Calculation of cost reflective tariffs is a quantitative effort and depends mainly on the quality of available data and professional knowledge, but their implementation for all customer categories cannot be completed overnight. Therefore, in order to achieve political acceptability and social affordability, a gradual approach supported by transition arrangements may be required. Otherwise a reliable social protection system should be put in place, which is usually not a case. Two component tariff structures for residential consumers generally consist of a customer charge and a commodity (energy) charge and are used in many countries in order to better reflect the cost of providing service to consumers by the utility. In this tariff structure, the monthly bill for each consumer would consist of a fixed customer charge and a commodity charge that would be based on the monthly electricity or gas usage, as recorded by the billing meter. Two component tariffs for industrial consumers would consist of a demand charge (for the capacity measured or agreed in a contract) and a commodity (energy) charge recorded by the meter. Another important reason for a two component tariff is that it will result in more revenue stability for the company, thus preventing the large swings in revenue that result from changes in weather (especially for gas consumption). From the customers perspective, the two component cost structure will provide better information so that they can make proper economic choices in their use of energy. 28

29 5.2 Tariff setting in the EU Member countries Implementation of the so-called Third Energy Package in the EU member states (completed in 2011, with some exceptions among Member States) requires that retail pricing is opened to competition, so that only the network (transmission and distribution) tariffs are regulated. It does not preclude regulation of supply and generation activities in case if there is insufficient competition in the market. There is no single uniform approach to tariffs in the EU, nor a specific tariff-setting methodology that is uniformly applied throughout. There is no clear tendency towards a preferred network pricing model in Europe, for example in the application of different cost concepts, and there are varying approaches for transmission and distribution. The lack of uniformity is itself a function of the different physical properties of electricity and gas transmission and distribution systems in the EU and the different scope of the services provided by utility companies. To date, in the EU the regulation of electricity and natural gas networks (transmission and distribution) is implemented nationally by local legislation reflective of the relevant directives. The decentralised decision making and development of national regulatory regimes (dependent on individual sector characteristics, historical evolution of the regulatory design, national policy priorities, regulatory capabilities, etc.) have resulted in a wide heterogeneity of current regulatory practices. First, it may be observed that various forms of general price control mechanisms co-exist, including cost-plus, rate-of-return, price-cap and revenue-cap regulation, although the majority of countries have moved to incentive pricing (price cap or revenue cap). Incentive pricing is applicable in a stable economic environment, with all cost elements sufficiently stable over a certain period of time and governments are eager to give more incentives to the energy companies to reap the benefits of more efficient operation. Generally, in the EU an integral part to setting a tariff is the method for allocating costs across categories of users. Unless the costs to be recovered are allocated appropriately then the tariff structure for an individual customer category cannot achieve cost reflectivity. The EC Commission as part of its overall review of the progress towards the liberalisation of the energy sector and the creation of an internal market examines the costing methods used for class allocation and tariff design in the electricity generation, transmission sub-sectors. There are broadly at least three approaches to tariff setting identifiable in the EU. These are: The Average Historical Cost Approach The average historical cost approach entails taking the expenses actually being incurred or allowed by the energy regulator and a return on capital invested in the past as a starting point. This bucket of revenue is classified as being related to demand, energy consumption, and number of customers being served. The classified costs are then allocated across the various customer classes based on measures of their demand, energy use, and customer counts. The classified and allocated costs are then converted to tariff charges by dividing the identified costs of customer group categories by billing units (e.g. kwh, customer-months). The Average Reproduction Cost The average reproduction cost approach modifies the average historical cost approach by adjusting assets values to reflect the cost of replacement. The re-valuation affects the return on asset base, but not the depreciation charges. The Marginal Cost approach The marginal cost approach is a forward-looking process that estimates the change in the cost of producing or delivering energy in response to a small change in customer usage. In many systems, the marginal cost of generation will be the market price. The marginal cost of transmission however, is a function of: 29

30 Congestion and losses reflected in locational marginal prices although these are not included in all EU Member States; and The annualised cost of incremental investment needed to accommodate load growth. The marginal cost of distribution is the annualised cost of incremental local facilities needed to connect customers and the annualised cost of higher voltage facilities needed to accommodate increased use by many customers. The output from a marginal cost study is unit marginal costs, per kwh by time period, per kw and per customer. These unit costs can be used to compute the marginal cost revenues (the marginal unit costs multiplied by units expected to be sold) by customer category and in total. Since total marginal revenue does not necessarily match the allowed revenue requirement, adjustments must be made to cover any positive or negative gap. The adjustment can be proportional (so that all classes are allocated the same percentage of their marginal cost revenues) or on a differential basis that takes other factors into account. As applied to the generation sector, the cost of building power generation capacity is a stock concept, marginal cost (and more usually, long-run marginal cost) is a flow concept which relates to the cost per period of producing an additional kwh. Peak load pricing is a system of price discrimination whereby peak time users pay higher prices to reflect the higher marginal cost of supplying them. There are two benefits from adopting peak load pricing: Peak time users pay for the higher marginal costs that they impose on the system; Those users who would not mind consuming at a different time (for example, residential customers who can use electricity at a different time when marginal costs are cheaper) are induced by cheaper prices to switch to consuming at off-peak times. By spreading total daily consumption more evenly, the service provider reduces the peak in demand and has to devote less resources to building new power stations whose number is determined by peak usage. In some cases, regulators can use a hybrid approach, which uses a combination of marginal and average allocation of costs. For example, average historical costs could be used to allocate the revenue requirement to customer categories (eliminating the need to close the marginal cost revenue gap at the class level) and marginal costs could be used for tariff design within a category (with the gap closing done at the tariff component level). 5.3 Removal of cross-subsidies Energy subsidies are measures that keep prices for consumers below market levels or for producers above market levels, or reduce costs for consumers and producers. Energy subsidies may be direct cash transfers to producers, consumers or related bodies, as well as indirect support mechanisms, as tax exemptions and rebates, price controls, trade restrictions and limits on market access. Cross subsidisation is the practice of charging higher prices to one group of consumers in order to subsidise lower prices for another group of consumers. This is well spread approach among less developed countries when usually residential consumers are subsidised by the commercial ones. The following graph shows an example of using cross-subsidies in electricity sectors in the economies in transition of some East European countries (Figure 10). 30

31 Figure 10: Cross-subsidies in electricity sectors in some East European countries (source: ERRA) Source: Consultant Cross-subsidies in the energy sector can lead to serious problems for a country. These problems tend to intensify over time as energy providers encounter increased difficulties in raising needed capital funds to maintain or expand their capacity capabilities. Efforts to reform the sector should include, if not begin with, addressing ways to more rationally restructure tariffs in line with economic principles. Such efforts are hampered by the unavailability of good data and strong political pressures in opposition to harming the beneficiaries of the current tariff structure. The adverse consequences of cross-subsidies have several components. First, cross-subsidies are unfair to some members of society. For example, they result in some consumers paying less for the services than what it costs society to provide them with those services. Second, cross-subsidies are economically inefficient: they provide wrong signals to consumers on the amount of energy they should consume; and they may cause the lowest cost sources of utility services to be under-utilised or un-utilised when the prices for other sources (e.g., state-owned enterprise) are being subsidised. In setting tariffs, economic efficiency should be considered as it takes into account the aggregate benefits and costs. When a new tariff is set, for example, to improve economic efficiency, the implication is that societal welfare has increased. Third, cross-subsidies generally discourage private investments; a private power producer being required to offer wholesale electricity at a price subsidized to retail consumers, for example, would tend to be discouraged from entering the market; this is especially true if it is unable to earn what it considers a minimally acceptable rate of return. Fourth, cross-subsidies implemented over a long period of time inevitably lead to shortages; this is exemplified by inadequate new capacity and under-maintenance of existing capacity; in addition, deterioration of service quality and safety may result. The effort to reduce cross-subsidies stems from the recognition that social objectives have imposed a high cost on the energy sector as well as on the overall economy. These costs include economically inefficient energy systems, inadequate investments, and degradation of the environment. As a political matter, in spite of the high costs that may be attached to cross-subsidies, consideration should be given to avoiding an abrupt change in tariffs. Dramatic increases in tariffs over a short period of time could unduly burden certain consumers, specifically low-income households, unless coordinated with government social safety-net programs. 31

32 A major obstacle in reducing cross-subsidies is the political opposition by interest groups who perceive the taking away of benefits. These benefits, which some may consider as entitlements, are in the form of lower prices for energy. By more rationally setting prices to reduce cross-subsidies, some consumers would be expected to pay higher prices, especially in the short term. For consumers with moderate or high incomes, higher prices would pose a lesser burden: although allocating a higher percentage of their incomes to utility services, these consumers would not likely have to forego other essential goods and services. The situation for low-income consumers is more serious. Higher utility prices may burden their budgets to where they may have to choose between utility services and other essential goods and services. In this circumstance, the government has two choices: 1) raise income support payments to low-income consumers through the governmental budgeting process to compensate for the higher prices for utility services, or 2) require energy companies to target lower prices to only low-income consumers. EU legislation does not tolerate cross-subsidies, therefore countries when entering EU were removing the existing until that time cross subsidies. The following figure shows how the crosssubsidies were gradually removed in Bulgaria and Romania: Figure 11: Removal of cross-subsidies between residential and commercial electricity consumers in Bulgaria and Romania Source: ERRA 5.4 Tariff setting examples from countries with high share of nuclear generation Slovakian electricity tariff structure in the early nineties At the beginning of the 1990 s after the old communist system collapsed and liberal changes started in the Slovak economy, the Slovak electricity system was a monopoly, later it was gradually unbundled and liberalised. At that time the Slovak power system consisted of a single state-owned generation and transmission utility (Slovenske Elektrarne, SE), three state-owned regional distribution utilities (RDUs), and some generation facilities owned by manufacturing industries. There were three RDUs: the West Slovak Distribution Company (ZSE), the Central Slovak Distribution Company (SSE), and the East Slovak Distribution Company (VSE). The power sector was in a period of transition. Prior to 1990, SE and the RDUs belonged to a single organisation. SE became a joint-stock company in November SE was responsible for most power generation, power imports and exports, and the 220 kv and 400 kv network. The RDUs were responsible for the network below the 200 kv level. The RDUs were allowed to operate combined heat and power (CHP) facilities and small hydro plants. Electricity was 32

33 also generated at industrial plants. This generation was primarily utilised for the own use, but some sales were made to the RDUs. SE operated most of the generating capacity in Slovakia; however, SE generation was supplemented by imports, by electricity generation from CHP facilities operated by the RDUs, and by generation by industry. The main generator at that time was the Bohunice nuclear power plant, and over 45% of generation requirements for 1993 were supplied by the nuclear power, the rest 25% by fossil-fuel powered facilities, and the remainder with a combination of hydroelectricity, industry-owned generation, and imports. SE provided capacity and energy to the three RDUs and directly to four large industrial consumers. The price and terms of delivery were negotiated separately with SE and each of the three RDUs and four industrial consumers on an annual basis. The average bulk price for electricity in 1993 was slightly more than 35 $/MWh and the average retail price was approximately 47 $/MWh. There were no direct subsidies, and a review of the cost information from the various power supply organisations indicated that the prices reflected all operating costs, but limited the ability to replace existing assets. Customer categories were defined by service voltage as follows: Directly served Very High Voltage (VHV) kv (corresponds to Tariff Category A customers) High Voltage (HV) kv (corresponds to Tariff Category B customers) Low Voltage (LV) - less than 1kV (corresponds to Tariff Category C customers) Low Voltage customers included residential and commercial categories. Due to the high share of nuclear and coal fired power plants the system was not flexible and required rather complicated system of tariffs to reduce consumption during peak hours and encourage during off-peak time. In 1993 for the contractual arrangements by SE and RDUs there were used three time zones (peak, mid-peak and off-peak), they were different during different time seasons (Table 12). The contracts between SE and the RDUs and retail tariffs allowed for a quarterly modification of the time period definition to reflect changes in load shapes. Table 12: Time zones for setting electricity tariffs First and fourth quarters Second and third quarters Peak, h and Mid-peak, h ; ; Off-peak, h and Source: SE and RDUs There were several classes of retail tariffs as follows: Large customers connected to the electric network at a voltage over 52 kv. This was referred to as the Very High Voltage (VHV) level. There were three tariffs serving these customers: tariffs A1, A2, and A10. Large customers connected to the network at a voltage from 1 to 52 kv (High Voltage or HV customers). These customers were served by tariffs B1, B2, B3, B4, B5, B6, B10, B11, B12, and B13. 33

34 Large customers connected to the electric network at a voltage less than 1 kv. These customers were billed based on tariffs C1, C2, C3, C4, C10, and C11. This class of tariffs was to serve residential customers (households). There were many tariffs that suited different customers with varying consumption needs for electricity. Their features included peak, mid-peak, and off-peak energy pricing. Customers were given some economic signals for differentiated production cost periods. The C category and the residential customers were served with the connections below 1kV, referred to as the Low Voltage (LV) level. Ultimate customers in the Slovakia were served by the RDUs except for four large customers, which were directly served by SE. Let us overview the various tariff categories: Very High Voltage Tariffs Tariff A1 accounted for 80% of the Tariff A sales in It was applied to Very High Voltage customers with a demand charge for the agreed-upon maximum. Key features of this tariff were as follows: Negotiated meter charge. Demand charge which was based on two basic components: a 74 Sk/kW rate for the technical maximum demand of the month, and a second part equal to 163 Sk/kW for the agreed-upon 15-minute monthly peak. The demand charge was adjusted for exceeding the agreed-upon 15- minute peak demand using 550 Sk/kW. Energy rates were 0.83, 0.66, and 0.61 Sk/kWh during peak, mid-peak, and off-peak periods respectively. Tariff A2 was applied to Very High Voltage customers with a demand charge for the measured maximum. This tariff is similar to Al from the energy point of view, but the demand charge components are based on two rates for the monthly technical maximum demand and the monthly measured 15-minute peak. These rates were 74 and 185 Sk/kW, respectively. Tariff A10 was applied to railways connected to a voltage exceeding 52 kv. This tariff had a single rate for energy consumption. The energy charge was 1.10 Sk/kWh. High Voltage Tariffs These tariffs were applicable to large customers connected to a high voltage (defined as the range of 1 to 52 kv). Tariffs B1 and B2 were applied to customers with an agreed-upon monthly technical maximum peak equal to or more than 1,000 kw. These tariffs are described below. Tariff B1 was very similar in structure to Tariff A1 except that the rates are different. This tariff had three parts, and they were as follows: Meter charge. Demand charge with two rates of 90 and 185 Sk/kW for the monthly technical maximum peak and agreed-upon monthly 15-minute peak respectively. The demand charge is adjusted for exceeding the agreed-upon 15-minute peak demand using 640 Sk per kw. Energy charge was based on three rates equal to 0.93, 0.74, and 0.66 Sk/kWh for peak, midpeak, and off-peak period respectively. 34

35 Tariff B2 was very similar to A2 in structure. This tariff applies to customers with a demand charge based on monthly measured 15-minute maximum demand. Demand and energy charges were as follows: Demand charge is based on two rates for the monthly technical maximum demand and the monthly measured 15-minute peak. These rates are 90 and 211 Sk/kW respectively. Energy charges are exactly the same as in Tariff A2. Tariffs B3 and B4 apply to customers with an agreed-upon monthly technical maximum peak from 150 kw to 1,000 kw. Both tariffs have two energy rates for mid-peak and off-peak periods. Tariff B3 is similar to Tariffs A1 and B1 from the demand charge structure point of view. This tariff applies to customers with a demand charge for agreed-upon maximum. The components of the tariff were as follows: The demand charge had two rate parts, and these are 90 Sk/kW for the monthly technical maximum and 207 Sk/kW for the agreed-upon 15-minute monthly peak. The penalty for exceeding that maximum was 700 Sk/kW. The energy charge only had two parts, and these were 0.74 and 0.66 Sk/kWh for mid-peak and off-peak period respectively. Tariff B4 was similar to the Tariffs A2 and B2 from the demand rate structure point of view. This tariff was for customers with the measured maximum demand. Aside from the meter charge, demand and energy charges were as follows: The demand charge is based on two rates, and these are 90 Sk/kW and 235 Sk/kW for the monthly technical maximum and the measured 15-minute monthly peak respectively. The energy charge is based on two rates as mentioned above. Tariffs B5 and B6 were applied to customers with demand equal to or less than 150 kw. Both tariffs had two rates for the energy charge. These rates were applicable to mid-peak and off-peak periods. Tariff B5 was applicable to customers with measured maximum demand. Aside from the meter charge, the demand and energy charges were as follows: The demand charge was based on two rates. These were 90 Sk/kW and 235 Sk/kW for the monthly technical maximum and the measured monthly 15-minute peak respectively. The energy charge was based on two energy rates, and these were 0.74 and 0.66 Sk/kWh for mid-peak and off-peak periods respectively. Tariff B6 was a demand charge based on connected transformer size with a rate equal to 139 Sk/kVA. The energy charge was based on 0.74 and 0.66 Sk/kWh for mid-peak and off-peak periods. It was planned to abolish this tariff. Tariffs B10, B11, B12, and B13 were for special customers, and they were the High Voltage customers. Tariff B10 was applicable to railways, and it had only an energy rate. The energy charge was 1.46 Sk/kWh. Energy consumption was considered to be during mid-peak period. Tariff B11 was applied to customers with off-peak heating to total installed power requirement ratio of not less than 80%. Aside from the meter charge, there were two basic charges and they were as follows: The demand charge was based on 320 Sk/kW for the measured demand during high tariff band. The energy charge was based on 0.74 and 0.66 Sk/kWh for mid-peak and off-peak periods. 35

36 Tariff B12 was applicable only to customers with a measured 15-minute monthly peak who met certain criteria as stated below: The customer must have his electrical heating controlled by the remote control system. The ratio of installed power for the electric heating to the total installed power should be less than 80 percent. The components of the B 12 tariff were as follows: Demand charge was based on 320 Sk/kW for the measured 15-minute monthly maximum during the high tariff band. Energy charge was based on 0.93 and 0.73 Sk/kWh for energy consumed during mid-peak and off-peak periods. Tariff B13 had a meter charge and an energy charge. The energy charge was based on two rates, 3.70 and 0.66 Sk/kWh for energy used during mid-peak and off-peak periods respectively. Low Voltage Tariffs This class represents residential and commercial (business) customers. These customers have two basic charges; these are energy and customer charges. These tariffs are discussed below. BS-V tariff was recommended by the Ministry of Economy for residential customers with consumption less than 451 kwh per year. It was applied to energy consumed during the high-tariff period. BS-N tariff was the same as Tariff N. This tariff was combined with Tariff BS-V for customers with two zones kwh meters. B-V tariff was for residential customers with a meter to measure energy consumption during the high-tariff period. B-N tariff was the same as Tariff N. This tariff was combined with Tariff B-V for customers with two zones kwh meters. N tariff was applied to customers with consumption during the system's low loads. BV-V and BV-N tariffs were applicable to residential customers with electric storage heating and hot water storage tanks. The monthly fixed charge was based on the apartment size. The energy charge was based on two different rates for different periods of the electric system load. The equipment was controlled by a bulk remote control. BH-V and BH-N tariffs were applied to customers with a combination of electric storage heating and a hot water storage tank. The monthly fixed charge was based on the apartment size. The energy charge was based on two different rates for different periods of the system load. This equipment was controlled by a bulk remote control. BP-V and BP-N tariffs apply to residential customers with electric heating. The monthly fixed charge was based on the size of apartment's main circuit breaker. The energy charge was based on energy consumed during different times of the day. Low Voltage customers other than residential These customers were defined as businesses and placed under C tariffs which are summarized below. C1-V tariff applies to small businesses with annual energy consumption less than 500 kwh. This tariff includes a monthly fixed charge and an energy charge for usage during high-tariff period. 36

37 C1-N tariff used Tariff C4 for billing and was used for energy consumed during the low-tariff period. C2-V tariff generally applied to customers with low consumption. This tariff had a fixed charge and a high energy charge. C2-N tariff was the same as Tariff C4 and had a fixed monthly charge and an energy rate for usage during the low-tariff period. C3 tariff was used for small customers. It had relatively high customer charge and high energy charge C8 was used for not metered consumption C10 tariff was used for public space illumination. It had an energy charge based on a rate for the high-tariff period. C11 tariff was used for customers with electric heating, and it had two energy rates for highand low-tariff periods. In addition to the energy charge, there was a monthly fixed charge that varied and depended on the main circuit breaker size. Analysis of the above tariffs gives us some examples how to smooth the load curve in the vertically integrated monopoly. When there are no independent energy consumers (or very few like in the Slovakian case) and there is no third party access and all tariffs are set for all final customers the system works very well. Three time zones were identified with different energy charges at each the highest for the peak and the lowest for the off-peak for almost all consumers. This gave a clear signal to consumers how to plan their behaviour accordingly seeking reduction of their electricity bills. Additionally, to tariff differentiation during the day there were some customers using electricity for heating and hot water preparation who were controlled remotely, i.e. the distribution company s dispatcher had a right to switch on and off them when needed. This was an additional element for the load smoothing. Such were tariffs B12, BV-V, BV-N, BH-V and BH-N. In general, the Slovakian system tariff system was too complicated and designed to satisfy the energy monopolist s needs, but not the customers needs. Later the system was re-designed and tariff structures were simplified, especially, for the residential consumers Lithuanian electricity tariff structure at the beginning of the century Until the end of the first decade of the current century in Lithuania the dominant electricity generator was the Ignalina Nuclear Power Plant with the installed capacity of 2600 MW, as the maximum load of the system was less than 2000 MW. In the nineties all generation, transmission and distribution services were in one company and tariffs to all final consumers were set as a united system covering all the system costs. At the beginning of the new century the energy monopoly was dissolved with the monopolistic activities of transmission and distribution separated from the competitive generation and supply. Separate companies for transmission and distribution (two of them) were established, their tariffs were calculated separately and approved by an independent energy regulator. As Ignalina was the dominating generator its tariffs were also regulated. Therefore, almost all tariffs were regulated still, but two distribution companies were applying a bit different distribution tariffs to their clients. We will further present and discuss the electricity tariffs approved by the regulator to one of the distribution companies (named VST) in Consumers were split into groups based on their connection level (high voltage, medium voltage and low voltage) there was a separate group of residential consumers. As the nuclear power plant was dominating in the market the tariff structure was designed for sending price signals to the consumers how to shape better their loads to fit to the system load. Therefore, consumers connected to medium and high voltage grid were supposed of 37

38 using the time of use tariff and this was also optional for residential consumers connected at low voltage network. All residential consumers wanting to apply the two time zones (day and night) tariff were encourage to ask the distribution company to install a special meter for two time zones and pay accordingly. Electricity tariffs for residential consumers connected to the distribution network of the VST distribution company were paying the following rates (in Lithuanian cents, exchange rate 1 EUR = 3.45 LTL) (Table 13). Table 13: VST tariffs to residential consumers in 2007 Tariff type One component tariff 1.1. Residential consumers Residential consumers with electric stoves Residential consumers consuming more than12000 kwh/y 30.0 Time of use tariff 2.1. Day time 2.2. At night and weekends 24.0 Source: National Control Commission, Lithuania ( Tariff, ct/kwh Commercial and industrial consumers connected to the medium voltage network (from 6 to less than 110 kv) besides the differentiation of the tariffs according to the time of use were obligatory paying for the capacity and energy (two component tariffs). Additionally, according to their consumption patterns they were able to choose a structure of a two component tariff: high payment for the capacity and low for energy or opposite low for capacity and high for energy. These tariffs are shown in the following table: 41.0 Table 14: VST tariffs to commercial consumers connected to the medium voltage network Tariff type Units I plan II plan III plan 1. Two component simple tariff: 1.1. Capacity charge (monthly) LTL/kW/m Energy charge ct/kwh Two component two time zones tariff: 2.1. Capacity charge (monthly) LTL/kW/m Day time ct/kwh Night time and weekends ct/kwh Two component time of use tariff: 3.1. Capacity charge (monthly) LTL/kW/m Minimal load ct/kwh Average load ct/kwh Peak load ct/kwh Holidays and weekends ct/kwh Source: National Control Commission, Lithuania ( 38

39 6 Electricity Demand Forecast in Belarus In this section, the power demand up to 2030 is reviewed according to historical trends in consumption growth. Two approaches are taken, a bottom-up forecasting technique based on specific consumption, and a top-down forecasting technique based on the correlation between GDP and electricity consumption. 6.1 Demand Forecasts Historical Electricity Consumption Growth Belaurs electricity consumption has grown slowly over the last five years at a compound annual growth rate of 0.7%. Table 15: Belenergo Electricity Demand Growth (kwh; ) Purchases Sales Losses Loss Factor kwh kwh kwh Factor MW Consumer Demand ,168,000,000 27,838,316,000 3,450,000,000 12% 5, ,823,000,000 28,746,004,000 3,578,000,000 12% 6, ,316,000,000 28,898,358,000 3,634,000,000 13% 5, ,311,000,000 29,343,273,000 3,841,000,000 13% 5, ,433,000,000 27,449,163,000 3,724,000,000 14% 6, ,143,000,000 29,295,437,000 3,714,000,000 13% 6, ,178,000,000 29,970,325,000 3,487,000,000 12% 6, ,156,000,000 30,200,802,000 3,774,000,000 12% 6, ,308,000,000 29,554,772,000 3,412,000,000 12% 6, ,784,000,000 29,754,677,000 3,406,000,000 11% 6, ,277,000,000 29,519,122,500 3,660,470,000 11% 6,300 Source: Belenergo Electricity consumption growth and GDP growth are strongly correlated. The reported compound annual growth rate in GDP over the last five years was 0.7%, indicating an average elasticity of 1.1 and an electric intensity of 650MWh per unit of GDP Planning Assumptions Key drivers of electricity demand are the growth in customers (the growth in subscription rates) and the growth in the specific consumption of each customer class (average kwh per customer). Future growth rates can be expected to fall in line with historical trends. The Consultant is not aware of any significant reason why the country s electric intensity will change in the coming five years. The following planning assumptions were used to compute demand and consumption forecasts: Table 16: Planning Assumptions Growth Driver Unit Business as Usual Annual residential electricity connection rate to 2030 Average annual growth in Residential Class (MW) Average annual growth in Commercial customers to 2030 Average annual growth in Commercial Class (MW) Count 44,000 MW -7.5 Count 3,200 MW

40 Growth Driver Unit Business as Usual Average annual growth in Industrial customers to 2030 Average annual growth in Industrial Class (MW) Source: Consultant Count 65 MW Specific Consumption Growth Rates Specific consumption growth rate assumptions are presented in the following figure for commercial and industrial customer classes. Figure 17: Specific Consumption Growth Rate Assumption Source: Consultant The specific consumption in 2015 was 1,650 kwh per customer. It has been assumed that this rate will continue to Growth in Customer Subscription (Customer Counts) The rationale for the assumed growth in customer subscription follows a market trend for industrial and commercial customers. In the case of domestic consumers, the growth is a function of the underlying historical trend in new connection rates. 40

41 Figure 18: Industrial Customers to 2020 Source: Consultant Figure 19: Commercial Customers to 2020 Source: Consultant Figure 20: Residential Customers to 2020 Source: Consultant 41

42 6.1.4 Energy Consumption Projections Energy consumption and demand projections follow according to the abovementioned assumptions for the specific consumption growth rate and the number of customers. Figure 21: Industrial Consumption (kwh) to 2030 Source: Consultant Figure 22: Commercial Consumption (kwh) to 2030 Source: Consultant 42

43 Figure 23: Domestic Consumption (kwh) to 2030 Source: Consultant Figure 24: Total Electricity Consumption Growth Trajectory to 2030 (not including losses) Source: Consultant 43

44 Figure 25: Total Electricity Demand Growth to 2030 (not including losses) Source: Consultant The trajectory for transmission and distribution losses is assumed as follows: Figure 26: T&D Loss Trajectory to 2035 Source: Belenergo to 2015; thereafter Consultant s Analysis Figure 27: Total Electricity Consumption (kwh) by Class to 2035 (including losses = sent-out) Source: Consultant 44

45 6.1.5 GDP Projections For Belarus, the relationship between energy consumption and GDP was highly linear from 2000 to 2008, prior to the Global Financial Crisis. This relationship was used to calibrate the demand forecast and to make projections of GDP. Figure 28: GDP Regressed on Energy Consumption (kwh) Source: Consultant s Analysis; 2000 to 2008 Figure 29: BaU - GDP by Sector to 2035 (USD, const 2005) Source: Consultant s Analysis 45

46 Figure 30: GDP Per Capita to 2035 (USD, const 2005) Source: Consultant s Analysis The Consultant s projection of electricity demand growth according to a business-as-usual scenario is given by the following table: Table 31: Growth Rate Outcomes to 2020 Factor Growth Rate GDP Agriculture 0.5% GDP Services 1.5% GDP Industry 2.6% GDP Total 1.9% GDP per Capita 2.0% Electricity (MWh) consumption 0.2% Demand (MW) 0.2% Source: Consultant The Consultant s projection compares to the projection given in the report КОНЦЕПЦИЯ ГОСУДАРСТВЕННОЙ ПРОГРАММЫ РАЗВИТИЯ БЕЛОРУССКОЙ ЭЛЕКТРОЭНЕРГЕТИЧЕСКОЙ ИСТЕМЫ НА ПЕРИОД ДО 2020 ГОДА in Figure

47 Figure 32: Comparison Belenergo and Consultant s Electricity Sent-Out Electricity Demand Forecast Source: Consultant s Analysis 47

48 6.2 Consumer Demand Profiles The typical daily consumer demand profiles were given by Belenergo as follows: Figure 33: Consumer Demand Profiles Source: Belenergo For the purpose of modelling load shifting from peak to other time periods, the Consultant prepared two additional sets of consumer load profiles. The profiles are named as a Moderate load shift profile and a High load shift profile. The Moderate load shift is based on a 20% reduction in the peak industrial load and a 15% reduction in the peak commercial load. The High load shift is based a 30% reduction in the peak industrial load and a 25% reduction in the peak commercial load. The adjusted load profiles are given by the following figures: Figure 34: Moderate Load Shift Profiles Source: Consultant Figure 35: HIgh Load Shift Profiles Source: Consultant 48

49 7 Supply Outlook for Belarus In this section the results of needed electricity production modelling are presented. The energy supply production mix determines the hourly cost of supply, both average and marginal costs, and is therefore a key input to the computation of cost-reflective time-of-use energy tariffs. The Belarus supply sector comprises a number of Combined Heat and Power Plants (CHP). CHPs produce electricity in two modes co-generation (electricity and heat) and condensing (electricity only) with different fuel conversion efficiencies. The production modelling of the CHPs has taken these modes into account based on the heating degree day concept. 7.1 Input Assumptions for the Supply Sector The power plants listed in Table 36 were grouped according to fuel type and age. Table 36: Belarus Existing Power Plants Power Plant Age Installed capacity, MW Available capacity, MW Production in 2014, GWh CF in 2014 Berezovsk TPP % Lukoml TPP % Novopolotsk CHP % Gomel CHP % Svetlogorsk CHP % Mozyr CHP % Grodno CHP % Minsk CHP-3 with GT % Minsk CHP-5 with GT % Minsk CHP % Mogilev CHP % Bobruisk CHP % Source: Belenergo; Consultant for grouping Table 37: Belarus Existing Power Plant Groupings (Summary) Plant Plant Group Berezovskya 1 Lukoml 2 Mozyr, Minsk CHP-4 3 Minsk CHP-5 4 Minsk CHP-3 5 Novopolotsk, Gomel, Grodno, Svetlogorsk, Mogilev, Bobruisk 6 Power plant efficiencies were set according to an analysis of plant performance statistics provided by Belenergo. 49

50 Table 38: Performance Statistics Belenergo Power Plant Fleet ( ) Past Sent Out Station Name Design Capacity Firm Capacity Minimum Operating Level Fuel Consumption Heat 2014 Fuel Consumption Electricity 2014 Nat Consumption gas MWe MWe MWe MWhe MWhe MWhe tons standard fuel tons standard fuel million cub m Berezovskaya GRES , Lukoml power station , Novopolotsk CHP , Gomel CHPP , Svetlogorsk CHP , Mozyr CHP , Grodno CHPP , Minsk CHPP-3 with PSU , Minsk cogeneration plant-5 with PSU , Minsk cogeneration plant , Mogilev CHPP , Bobruisk CHPP , Source: Belenergo 50

51 In addition, it was assumed that: Imports would effectively cease in 2018 Industrial captive power plant capacity of 706 MW would not be converted to Belenergo supply The nuclear plant (2 x 1184 MW) would commence operation in two stages, Unit 1 CoD in 2018 and Unit 2 in The operating cost (MWh fuel to MWhe) of the nuclear plants was determined based on a screening curve analysis Table 39: Power Plant Efficiency Assumptions (MWh fuel / MWhe) Plant Group 1 Plant Group 2 Plant Group 3 Plant Group 4 Plant Group 5 Plant Group 6 Nuclear Cogen Heat Rate Cogen Efficiency 77% 77% 84% 84% 80% 80% 100% Condensing Heat Rate Condensing Efficiency 37% 37% 37% 40% 37% 37% 0% Source: Consultant analysis Table 40: Power Plant Cost Assumptions (USD per MWhe) Plant Group 1 Plant Group 2 Plant Group 3 Plant Group 4 Plant Group 5 Plant Group 6 Nuclear Fuel cost Cogen Fuel cost Condensing Variable O&M cost Source: Consultant analysis As described in Section 4 above, three cases were considered for hourly dispatch based on an assumption that consumer load could be shifted from the existing period in which the peak occurs for each consumer class. The results of the dispatch are subject to assumptions regarding the technical operating regime as well as costs. In this case operating costs were by necessity used for dispatching purposes. The dispatch produces typical daily dispatch curves by month (the electrical output of a CHP is a function of heat production and therefore ambient temperature) and a load duration curve for the year. A load duration curve (LDC) is a representation of all of the one hour loads (MW) occurring throughout the year, arranged from highest to lowest. Accordingly, the x-axis of an LDC is 8760 hours and the y-axis scale is in MW. The dispatch was calibrated for year 2014 by ensuring that the reported capacity factors of all plants were met, as well as the reported level of imported power. 51

52 Figure 41: Load Duration Curve for 2014 (calibration case) Source: Consultant analysis The dispatch was then extended to 2020 to capture the impact of the nuclear plant. The typical daily January 2018 profile for the existing consumer load profile is shown by the Figure 42. Figure 42: Typical Daily Load Profile February 2018 Source: Consultant analysis The daily load profile shows the anticipated excess generation in the early hours of the morning in February when heat production is high but electricity demand is low. The matching LDC for 2018 is 52

53 shown by Figure 43. The excess generation can be seen appearing above the load (blue line at the top of the curve). The off-peak time period is occurring towards the tail end of the LDC: Figure 43: Load Duration Curve 2018; existing consumer load profile 7, , , ,000.0 MW MW 3, , , Source: Consultant analysis Nuclear Plant Group 2 Plant Group 3 Plant Group 6 Plant Group 5 Plant Group 4 Load Duration Curve The load duration curve is used for two purposes 1) for generation expansion planning based on economic dispatch principles, and 2) for computing the costs of production. In the latter case, the production volumes and production costs of each plant can be used to compute the cost of supply since it is known how each MW hour is to be supplied. The load duration curves follow for years 2018 and 2020 for each of the three consumer profile cases, Case 1 existing load profile, Case 2 moderate load shift profile and Case 3 high load shift profile. These production schedules were used to compute tariffs as discussed in Section 6 that follows; the hourly production MW (co-generation and condensing) are given by separate tariff models provided as Appendices to this report. Figure 44: Case 1 - Load Duration Curves 7, , , , , , , Nuclear Plant Group 2 Plant Group 3 Plant Group 6 Plant Group 5 Plant Group 4 Load Duration Curve

54 1 Figure 45: Case 2 - Load Duration Curves Figure 46: Case 3 - Load Duration Curves 8, , , ,000.0 MW 4, , , , Nuclear Plant Group 2 Plant Group 3 Plant Group 4 Plant Group 6 Plant Group 5 Import Load Duration Curve Source: Consultant analysis It can be seen that the estimated excess generation increases significantly when the second nuclear unit is commissioned in Conclusions CHP power plant co-generation production is a must-run production. The electricity is a by-product of heat production and cannot be rejected unless the condensing steam turbine is by-passed. Turbine by-pass is not a routine operational practice and therefore the must-run electricity must be used. The nuclear plant is also considered as a must-run plant. The plant must-run at the highest possible capacity factor to justify the high front-end capital investment. The load duration curves show that there will be excess generation in 2018 and The challenge for Belarus is to find ways to absorb this excess power. The options are to introduce differentiated time-of-use tariffs with incentive power sufficient to encourage load shifting to the times when excess generation is to be expected, often in the early hours of winter mornings. Another possibility is to use the excess electricity generation to heat water in large distributed electric boilers, after which the hot water can be returned to the district heating networks supplied by the CHPs. These options are considered in the sections of this report that follow. 54

55 8 Tariff Strategies to Support the Nuclear Plant of Belarus In this section the three consumer profiles presented in Section 4.2 and the supply production cases considered in Section 5 are used to compute differentiated tariffs. The differentiation is based on seasonal and time-of-use considerations. The existing time-of-use periods in force in Belarus have been used for tariff modelling. The computation of the time-of-use tariffs is given in tariff models provided as Appendices to this report. 8.1 EU Practice in Tariff Differentiation In most countries, notably in the European Union, energy prices follow as a consequence of the operation of wholesale energy markets. It is common to find differentiated network tariffs used as the means to reduce peak consumption. Since peak consumption is markedly higher in the winter, seasonal time-of-use tariffs are used. In countries where energy supply prices are set by regulatory determination, a typical summer incentive power, measured as the ratio of off-peak to peak tariff rates, is around 50% for Small-to-Medium Enterprise and industry. In winter the incentive power can be as high as 85%. The use of differentiated tariffs to solve an over-capacity problem has rather few precedents and the impact of such tariff reform is less certain than the impact of electric boilers. In recent years, tariff differentiation has been used as the means to avoid curtailing night-time windfarm production. In Texas for example, off-peak electricity is free for industry. In Belarus a discounted off-peak rate, with strong incentive power, could be adopted as one of the means to encourage the economic use of power plants following the commissioning of the nuclear plant. The tariff setting should be arranged such that it is revenue neutral for each consumer class. The relationship between incentive power of off-peak electricity rates and load shifting is unknown in Belarus. Anecdotal evidence suggests that industry will incur added costs to operate at night, suggesting that the off-peak incentive would need to be strong to overcome such objections In any case, it must be recognized that the introduction of the nuclear plant will result in an increase in tariff rates due to the significant capital investment. 8.2 Tariff Setting Approach for Belarus Tariff differentiation is based on seasonal and time-of-use considerations. The existing time-of-use periods in force in Belarus have been used for tariff modelling: Peak period hours: 1700 to 2359 Shoulder period hours: 0700 to 1659 Off-peak period hours: 2400 to 0659 Tariff incentives have also been differentiated into winter and summer season incentives, whilst recognizing that the over-capacity problem faced by Belarus is a winter phenomenon. Incentives have been applied by reducing off-peak tariffs whilst maintain revenue neutrality within each tariff class (residential, commercial and industrial). As consumer response to tariff incentives cannot be predicted without market research, and even then imperfectly, the analyses presented 55

56 here should be understood to offer a range of possibilities of tariffs and tariff incentives, as one of the inputs to the development of the government s energy policy. 8.3 Case 1 Tariffs with No Load Shift The consumer profile for the business-as-usual case was given in Section 4.2 as Case 1. In this case no load shifting was considered. Using the marginal costing technique, wherein the highest cost generator sets the hourly cost of energy, it is estimated that average tariffs will need to increase as shown in Figure 47. Figure 477: Case 1 Average Annual Energy Rate Rise from 2016 to 2020 (marginal cost-basis) Source: Consultant analysis The increase in tariffs results because a nuclear plant has high up-front investment costs. In the long term energy rate rises will be modest because the operating costs of a nuclear plant are low. This is a selling feature supporting the introduction of the nuclear plant which will dominate the energy mix. It is estimated that the average monthly bills for each class would have to increase as shown in Figure 48. There are no cross-subsidies embedded in the tariffs; as such the monthly bill rises reflect cost recovery based on the full user-pays principle. In practice the real tariff rises may need to entertain cross-subsidies to protect vulnerable residential customers. In any case, the Government of Belarus should consider the best social support scheme to assist low income residential consumers in coping with the potential tariff increase. 56

57 Figure 488: Case 1 Average Monthly Bill Increase from 2016 to 2020 (marginal cost-basis) Source: Consultant analysis It should be noted that the tariff projections in Figure 47 and Figure 48 are dependent on assumptions and parameter settings that were set based on high level information. The figures should be considered indicative because the compressed nature of this tariff study did not allow for the usual standard of due diligence in making assumptions and setting parameters that would apply in the case of the development of an Electricity Masterplan or traditional Cost of Service Study. 8.4 Case 2 - Tariffs with Moderate Load Shift The moderate load shift scenario was given in terms of consumer profiles in Section 4.2 as Case 2. It has been assumed that the moderate load shift will require off-peak tariff incentives applied on a time-of-use basis as shown in Table 49 and Table 49. The discounts are applied as reductions to the average tariff rates determined using the marginal cost determination: Table 49: Winter Off-peak Incentives Case 2 Incentives as Discount Peak 1700 to Shoulder 0700 to 1659 Off-Peak 2400 to 0659 Peak 1700 to 2359 Shoulder 0700 to 1659 Residential 0% 0% 50% 0% 0% 50% Commercial 0% 0% 50% 0% 0% 50% Industrial 0% 0% 50% 0% 0% 50% Source: Consultant analysis Table 490: Summer Off-peak Incentives Case 2 Incentives as Discount on Marginal Cost Rates Off-Peak 2400 to 0659 Peak 1700 to Shoulder 0700 to 1659 Off-Peak 2400 to 0659 Peak 1700 to 2359 Shoulder 0700 to 1659 Residential 0% 0% 10% 0% 0% 10% Commercial 0% 0% 10% 0% 0% 10% Industrial 0% 50% 20% 0% 0% 20% Source: Consultant analysis Off-Peak 2400 to

58 It is estimated that average tariffs will need to increase as shown in Figure and Error! Reference source not found.. Figure 51: Case 2 Average Monthly Billing Increases by Time-of-Use 2014 to 2018 (marginal cost-basis) Source: Consultant analysis The tariff rates, expressed as the ratio of the consumer class time-of-use rates against the residential off-peak rate, are given in Table 502 and Table 513. Table 502: Case 2 Winter Off-peak to non Off-Peak Time-Of-Use Rates Peak 1700 to 2359 Shoulder 0700 to 1659 Off-Peak 2400 to 0659 Peak 1700 to 2359 Shoulder 0700 to 1659 Off-Peak 2400 to 0659 Residential Commercial Industrial Source: Consultant analysis Table 513: Case 2 Summer Off-peak to non Off-Peak Time-Of-Use Rates Peak 1700 to 2359 Shoulder 0700 to 1659 Off-Peak 2400 to 0659 Peak 1700 to 2359 Shoulder 0700 to 1659 Off-Peak 2400 to 0659 Residential Commercial Industrial Source: Consultant analysis 58

59 In the long term energy rate rises will be modest due to the dominance of the nuclear plant in the energy mix, wherein operating costs of the plant will be relatively low. This is a selling feature supporting the introduction of the nuclear plant. It is estimated that the average monthly bills for each class in 2020 would have to increase relative to the Case 1 average bill payment in 2020 as shown in 4. Figure 524: Comparison Average Monthly Bill Increase in 2020 for Case 2 over Case 1 Source: Consultant analysis 8.5 Case 3 Tariffs with High Load Shift The moderate load shift scenario was given in terms of consumer profiles in Section 4.2 as Case 3. It has been assumed that the moderate load shift will require off-peak tariff incentives applied on a time-of-use basis as shown in Table 535 and 59

60 Table 546. The discounts are applied as reductions to the average tariff rates determined using the marginal cost determination: Table 535: Winter Off-peak Incentives Case 3 Incentives as Discount Peak 1700 to Shoulder 0700 to 1659 Off-Peak 2400 to 0659 Peak 1700 to 2359 Shoulder 0700 to 1659 Residential 0% 0% 50% 0% 0% 50% Commercial 0% 0% 50% 0% 0% 50% Industrial 0% 50% 85% 0% 50% 85% Source: Consultant analysis Off-Peak 2400 to

61 Table 546: Summer Off-peak Incentives Case 3 Incentives as Discount on Marginal Cost Rates Peak 1700 to Shoulder 0700 to 1659 Off-Peak 2400 to 0659 Peak 1700 to 2359 Shoulder 0700 to 1659 Residential 0% 0% 20% 0% 0% 20% Commercial 0% 0% 20% 0% 0% 20% Industrial 0% 50% 50% 0% 50% 50% Source: Consultant analysis Off-Peak 2400 to 0659 It is estimated that average tariffs will need to increase as shown in Figure 55 and Figure Figure 557: Case 3 Average Monthly Billing Increases by Time-of-Use 2014 to 2018 (marginal cost-basis) Source: Consultant analysis 61

62 Figure 5856: Case 3 Average Monthly Billing Increases by Time-of-Use 2014 to 2020 (marginal cost-basis) Source: Consultant analysis The tariff rates, expressed as the ratio of the consumer class time-of-use rates against the residential off-peak rate, are given in Table and Table 57. Table 59: Case 3 Winter Off-peak to non Off-Peak Time-Of-Use Rates in Peak 1700 to 2359 Shoulder 0700 to 1659 Off-Peak 2400 to 0659 Peak 1700 to 2359 Shoulder 0700 to 1659 Off-Peak 2400 to 0659 Residential Commercial Industrial Source: Consultant analysis Table 570: Case 3 Summer Off-peak to non Off-Peak Time-Of-Use Rates in Peak 1700 to 2359 Shoulder 0700 to 1659 Off-Peak 2400 to 0659 Peak 1700 to 2359 Shoulder 0700 to 1659 Off-Peak 2400 to 0659 Residential Commercial Industrial Source: Consultant analysis 62

63 It is estimated that the average monthly bills for each class in 2020 would have to increase relative to the Case 1 average bill payment in 2020 as shown in Figure 58. Figure 581: Comparison Average Monthly Bill Increase in 2020 for Case 3 over Case 1 Source: Consultant analysis 8.6 Recommendations 1. Consider to introduce seasonal time-of-use rates immediately to pre-condition electricity consumers to the new approach. A two-prong marketing campaign would be desirable, to i) explain the adjustment to the rates due to the introduction of the nuclear plant and ii) the competitive advantage that time-of-use differentiated tariffs offers Belarus, in attracting new industry and offering the opportunity for existing industry to reduce net operating costs. 2. Clearly tariff reform will require a marketing and communications plan to ensure that consumers understand why tariffs should rise. The timing of tariff reform should proceed in concert with the timing of the nuclear plant commissioning. Seasonal time-of-use tariffs will need to be in force in Given a lead time of only 2 years, the introduction of tariff reform is indicated as a matter of urgency. At the same time Government of Belarus should consider a social support scheme to assist the low income consumers. 63

64 9 Electric Boilers It was shown in Section 5 that Belarus is faced with an over-capacity problem due to the must-run production of the CHP s and the nuclear plant. In this section a brief discussion is made concerning the use of large scale distributed electric boilers. Such electric boilers can be guaranteed to absorb excess electricity generation and by returning heat to district heating networks can offer CHP fuel savings. 9.1 Excess Generation in Belarus As was shown in Section 5, an over-capacity problem is anticipated in 2018, on commencement of operation of the nuclear plant, worsening in The supply dispatch modelling produced the count of incidents of excess capacity due to the must-run component of production as shown by the following charts for 2018 and Figure 592: Incidents of Excess Must-Run Supply Capacity in 2018 Source: Consultant analysis Figure 603: Incidents of Excess Must-Run Supply Capacity in 2020 Source: Consultant analysis 64

65 Clearly the size and frequency of the incidents of excess capacity can be expected to increase. To absorb the excess capacity will surely require a combination of strategies. Off-peak tariff incentives are one option but their impact remains uncertain at this time. Electric boilers on the other hand, electric boilers are guaranteed to absorb excess electricity, particularly in a CHP / nuclear system. 9.2 Electric Boiler in a CHP System In certain cases, where the supply of electricity exceeds the demand, generating heat using excess electricity is a viable option. The excess electricity can be used for heating the circulating water in district heating schemes either with heat pumps or directly using resistance heaters in an electric boiler. In a case of an oversupply of electricity, an electric boiler reduces the oversupply via two separate mechanisms. i. Firstly, excess electricity is converted into heat i.e. electricity is being consumed ii. Secondly, as heat is being generated in electric boiler(s), using excess electricity, CHP plant(s) can be operated at a lower load level (as heat demand is partially covered by the heat generated by the electric boiler), which reduces the generation of electricity (as well as heat). Such electric boilers are available and the technology is well proven. The efficiency of an electric boiler is close to 100 %, meaning almost all of the electricity is converted into heat. A 25 MW electric boiler costs approximately Euro 500,000 at the European market. Besides the boiler itself, electrical connection and a transformer as well as feed water purification system (reverse osmosis system) are other main components required for a functioning system. Assuming the electric boiler would be placed at a same property as a power plant, the connection to national grid and the required reverse osmosis plant can already be assumed to be available and in such a case the needed investment besides the boiler would be limited to transformer, civil works, procurement, design etc. Adding these expenses, the overall investment is estimated to be approx. Euro 850,000. As an example a boiler that could reduce the oversupply of electricity by approximately 40 MW (direct consumption of 25 MW and indirect reduction as the heat load of a CHP plant reduces by 25 MW) would correspond to a reduction in electricity generation of approximately 15 MW (Figure ). Figure 64: Approximately 45 MW fuel input is needed for the generation of 15 MW of electricity and 25 MW of heat in a modern CHP plant Source: Consultant analysis 9.3 Recommendations It is strongly recommended to consider the introduction of up to 1200 MW of large scale distributed electric boiler capacity. The proper dimensioning requires a detailed feasibility study; the study 65

66 should include an economic evaluation to establish whether the economic benefits are sufficient to justify the long-term investment; however, given that the economic value of the excess power capacity is otherwise zero, the payback appears to be assured. It should be noted that the cost of electric boilers was not included in the tariff computations given in Section 6. 66

67 10 The final workshop on electricity tariffs and possible tariff strategy for Belarus A workshop was organized during the second visit of the INOGATE experts to Minsk. According to the ToR it was targeted not only to present the draft results of the assignment, but to introduce experience of the EU Member States in setting tariffs, tariff structures and social support schemes. Medium level specialists from the Ministry of Energy, the Ministry of Economics, and the state owned power company Belenergo, the State Energy Efficiency Department and experts from the research institute BelTEI were invited to take part in this workshop. The total number of participants was 13; it allowed a good interaction and debate. Before the start of presentations and discussion the participants were asked how much they were familiar with the main items in the following discussion: how the tariff setting principles applied in the EU, how the tariffs are differentiated, how the vulnerable customers are protected and so on. The following graph (Figure 65) shows which topics discussed during the workshop were familiar to the participants and which ones were less known to them. One may notice that the topic on subsidies and cross-subsidies was the most familiar to the participants as it was discussed several times by international experts and by the local politicians. Figure 65: Familiarity of the audience with the topics discussed at the workshop at the start of the event Source: Consultant analysis The Government of Belarus was promising to remove cross-subsidies in the electricity sector by the year 2017, but very recently postponed the date to Time-of-use tariffs were also known to the participants as two time zones tariffs are used in Belarus and with the construction of the Belarusian 67

68 nuclear power plant this approach to tariff setting in order to utilize nuclear power plant more efficiently was broadly discussed. But the participants were less informed how the tariffs are set in the EU Member States and which tariffs are regulated there and which are set by the market (average valuation was only about 2 points out of 5). Support schemes for vulnerable consumers applied in the EU countries were also not very well known to the participants. Presentations On the electricity tariff structures and differentiation and Strategy of electricity tariffs in Belarus were met with interest. Questions and discussions on the issues raised followed. The workshop participants improved their knowledge, especially on the issues less familiar to them, as shown in the following figure: Figure 616: The improvement in understanding of certain topics presented during the workshop at the beginning of the workshop and at the end of it Source: Consultant analysis One may notice a small improvement in understanding the topics which were rather familiar to the participants before the workshop, like cross-subsidies and significant improvement in understanding how electricity tariffs are calculated in the EU member states, which tariffs are regulated and which are set by the market forces. To the question which topics were the most interesting to the participants there were different answers; but the most interesting and useful for majority of the participants were the EU experience in tariff setting, tariff differentiation and in regulation of certain tariffs. The following graph shows, which topics were the most interesting and useful to the participants (Figure 17). 68