Document of ESMAP and the World Bank Report No: ACS12721 MOLDOVA ELECTRIC POWER MARKET OPTIONS SECTOR STUDY June 11, 2015 Energy and Extractives Global Practice Energy Sector Management Assistance Belarus, Moldova and Ukraine Country Unit Program Europe and Central Asia Region Standard Disclaimer: . This volume is a product of the staff of the International Bank for Reconstruction and Development/ The World Bank. The findings, interpretations, and conclusions expressed in this paper do not necessarily reflect the views of the Executive Directors of The World Bank or the governments they represent. The World Bank does not guarantee the accuracy of the data included in this work. The boundaries, colors, denominations, and other information shown on any map in this work do not imply any judgment on the part of The World Bank concerning the legal status of any territory or the endorsement or acceptance of such boundaries. . Copyright Statement: . 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Table of Contents Table of Contents ................................................................................................................................................3 Executive Summary ............................................................................................................................................ i I Sector Background ......................................................................................................................................1 1.1 Overview .............................................................................................................................................1 1.1.1 Main characteristics of the power system in Moldova................................................................1 1.1.2 Government Policy and Strategy in Electricity ...........................................................................2 1.2 Power Supply System .........................................................................................................................4 1.2.1 Existing Right and Left Bank capacity .......................................................................................4 1.2.2 Participation in load demand (domestic and foreign) .................................................................4 1.2.3 Existing electricity import arrangements ....................................................................................5 1.3 Transmission Grid ...............................................................................................................................7 II. Demand and Load Forecast.........................................................................................................................9 2.1 Assumptions used for Demand Projection ..........................................................................................9 2.1.1 Electricity demand forecast .........................................................................................................9 2.1.2 Peak load forecasts ....................................................................................................................10 2.1.3 Seasonal forecasts through 2023 ...............................................................................................11 2.1.4 Annual forecasts through 2033 .................................................................................................12 2.1.5 Domestic generation capacity assumptions ..............................................................................13 2.1.6 Energy balance forecast ............................................................................................................14 III Scenario Analysis..................................................................................................................................15 3.1 Alternative Scenarios Analyzed ........................................................................................................15 3.1.1 Self-Sufficiency scenarios................................................................................................................17 3.1.2 Synchronous scenarios .....................................................................................................................17 3.1.3 Asynchronous scenarios ...................................................................................................................19 3.1.4 Scenario investment costs and 20-year levelized tariff levels..........................................................20 3.2 Ranking of the Scenarios ..................................................................................................................21 3.3 Asynchronous Interconnection Scenarios .........................................................................................22 3.3.1 Investment costs by Asynchronous scenario.............................................................................22 3.3.2 Tariff levels by Asynchronous scenario ....................................................................................23 3.3.3 Sensitivity analysis....................................................................................................................23 3.4 Conclusion of the Multi Criteria Decision Analysis .........................................................................24 3.5 Social and Environmental Aspects .......................................................................................................24 IV. Wholesale Market Design .....................................................................................................................26 4.1 Existing Market Arrangements .........................................................................................................26 4.1.1 Producers and suppliers. ...........................................................................................................26 4.1.2 No structural basis for a competitive market. ...........................................................................26 4.1.3 Most TSO roles are missing from legislation. ..........................................................................27 4.1.4 Regulations on wholesale competition missing. .......................................................................27 4.1.5 Wholesale import market is not competitive. ...........................................................................27 4.1.6 Retail market to be fully opened in 2015. .................................................................................27 4.1.7 The current situation can be changed only in the medium-long term. ......................................28 4.2 Market Models ..................................................................................................................................28 4.2.1 General principles. ....................................................................................................................28 4.2.2 EU Target Market Model. .........................................................................................................28 4.2.3 Competitive wholesale market criteria......................................................................................29 4.2.4 Market design options ...............................................................................................................29 4.3 Recommended Market Design Option ..............................................................................................30 4.3.1 Competition mostly outside Moldova .......................................................................................30 4.3.2 Market structure ........................................................................................................................31 4.3.3 Market rules ..............................................................................................................................31 4.3.4 Balancing ..................................................................................................................................31 4.3.5 Institutions.................................................................................................................................32 V. Overall Conclusions ..................................................................................................................................33 VI. Next Steps .............................................................................................................................................35 6.1 Implementation of Recommendations ..............................................................................................35 6.1.1 Attracting investments ..............................................................................................................35 6.1.2 Additional studies needed .........................................................................................................36 6.1.3 Legislative/regulatory changes required ...................................................................................36 6.1.4 Institutional capacity building/strengthening ............................................................................37 6.1.5 Operational issues .....................................................................................................................38 6.2 Requirements for Joining ENTSO-E ................................................................................................38 6.3 Coordination .....................................................................................................................................39 Maps Map 1-1. Moldova and neighboring power systems ........................................................................... 3 Map 1-2. Capacities of the Moldovan power grid (RB) ..................................................................... 8 Tables Table 1-1. Peak Load Demand and Supply, 2008 – 2013 (MW) ........................................................ 4 Table 1-2. Key components of the Moldovan electricity transmission network ................................. 7 Table 2-1. Actual and forecast electricity and peak load demand, by season (2012-2023) .............. 11 Table 2-2. Electricity Demand and Peak Load Forecast through 2033 ............................................. 12 Table 2-3. Forecasted domestic power generation capacity (MW) ................................................... 13 Table 2-4. Peak load demand and capacity deficit coverage through 2033 by source of supply (in MW) ................................................................................................................................................... 15 Table 3-1: Investment costs and levelized tariffs by scenario (base case) ........................................ 20 Table 3-2: Ranking of scenarios based on MCDA (base case) ......................................................... 21 Table 3-3. Investment costs by asynchronous scenario (base-case; US$ million) ............................ 22 Table 3-4. End-user tariff forecasts by asynchronous scenario (base-case). ..................................... 23 Table 4-1. Alternative supply scenarios and matching market design options................................. 30 Figures Figure 1-1. Power sources participation in Load Duration Curve during 2012.................................. 5 Figure 2-1. Electricity demand forecasts with alternative annual growth rates ................................. 10 Figure 2-2. Summer and winter typical daily load curve................................................................... 11 Figure 3-1. Nine variants of three basic scenarios analyzed .............................................................. 16 Figure 3-2. Alternative asynchronous scenarios ................................................................................ 25 Figure 4-2. The competitive wholesale market with appropriate rules for energy trading and cross- border capacity allocation .................................................................................................................. 33 Annexes Annex 1: Moldova in the Energy Community ................................................................................... 40 Annex 2: Demand and Load Forecasts .............................................................................................. 43 Annex 3: System Planning Model ..................................................................................................... 47 Annex 4. Scenario Ranking and Sensitivity Analysis ....................................................................... 49 Annex 5: Alternative Scenarios: Self-Sufficiency and Synchronous Interconnection ...................... 57 Annex 6: Asynchronous Interconnection Scenarios .......................................................................... 69 Annex 7: Market Design Options and Evaluation ............................................................................. 76 Annex 8: Requirements for Joining ENTSO-E ................................................................................. 84 Acknowledgements This report presents a summary of the main finding from the activity “Moldova: Electric Power Market Options Study,� which was financed by the Energy Sector Management Assistance Program (ESMAP) together with the World Bank’s Energy & Extractives Global Practice. The team was led by Sandu Ghidirim (Senior Operations Officer and Task Team Leader) and included Shinya Nishimura (Senior Energy Specialist), Koji Nishida (Senior Energy Specialist), Pekka Salminen (Senior Energy Specialist), Henk Busz (Strategy and Policy Consultant), Lucian Palade (Market Structure Consultant), and Ion Comendant (System Planning Consultant). The final report was written by Sandu Ghidirim and Henk Busz. The team would like to acknowledge contributions and valuable feedback provided by Katsuyuki Fukui, Marcelino Madrigal, Maria Vagliasindi, Victor Loksha, Efstratios Tavoulareas, Alica Dzelilovic, and Ranjit Lamech (Practice Manager). The team also greatly acknowledges the close cooperation and support from the Ministry of Economy (MoE) of Moldova and its General Directorate for Energy Security and Energy Efficiency, Moldelectrica (National Transmission Operator), ANRE (National Agency for Energy Regulation), other Moldovan and Romanian stakeholders, and development partners. The report also benefitted from a stakeholder workshop held on May 14, 2015 in Chisinau, where representatives of MoE, other Moldovan stakeholders and development partners provided feedback, shared their views, and discussed the findings and recommendations of the Study. Participants in the workshop commended the Study for its unique and comprehensive approach and being a very important basis for future analytical work and investments to improve the security and efficiency of electric power supply. The Study was revised to acknowledge the feedback received during the workshop. CURRENCY EQUIVALENTS (The Official Average Exchange Rate for October 20141) Currency Unit = Moldovan Leu US$1.00 = MDL14.94 FISCAL YEAR January 1 – December 31 LIST OF ACRONYMS AC Alternating Current ACER Agency for the Cooperation of Energy Regulators ANRE National Energy Regulatory Agency AS Asynchronous Scenario BtB Back-to-Back station CAO Coordinated Auction Office CCGT Combined Cycle Gas Turbine CHP Combined Heat and Power Plant CPP Coal Power Plant DAM Day-Ahead Market DC Direct Current EC European Commission EnC Energy Community ESCR Effective Short-Circuit Ratio ENTSO-E European Network of Transmission System Operators for Electricity ESMAP Energy Sector Management Advisory Program EU European Union GAES Hydro Storage Power Plant (Russian for -) GDP Gross Domestic Production GT Gas Turbine HPP Hydro Power Plant HVDC High Voltage Direct Current HVL High Voltage Line IEM Internal Energy Market IPS/UPS Integrated Power System (Ukraine, Kazakhstan, Kyrgyzstan, Belarus, Azerbaijan, Tajikistan, Georgia, Moldova and Mongolia)/Unified Power System (Russia) LB Left Bank LCC Line Commutated Converter LTC Long Term Contract MCDA Multi-Criteria Decision Analysis MD Moldova MGRES Moldavskaya GRES MW Megawatt 1 The National Bank of Moldova. NC Network Codes NEEAP National Energy Efficiency Action Plan NREAP National Renewable Energy Action Plan NTC Net Transmission Capacity OM Operation Margin PP Power Plant PPP Purchasing Power Parity PV Present Value PX Power Exchange RB Right Bank RED Electricity Distribution Network Operator RES - E Renewable Energy Source - Electricity SCR Short-Circuit Ratio SOLR Supplier of Last Resort SS Self-Sufficiency Scenario STATCOM Static Synchronous Compensator SyS Synchronous Scenario TSO Transmission System Operator UEEC Ukrainian Energy Exchange Company UNFCCC United Nations Framework Convention on Climate Change UA Ukraine VSC Voltage Source Converter WASP Wien Automatic System Planning WB World Bank Regional Vice President: Laura Tuck Country Director: Qimiao Fan Senior Global Practice Director: Anita Marangoly George Practice Manager: Ranjit J. Lamech Task Team Leader: Sandu Ghidirim Executive Summary The principal strategic challenges that the electricity sector in Moldova currently faces are to increase the security of electricity supply by diversifying sources, and to provide affordable, reliable, and sustainable energy services. To some extent this could be achieved by increasing and/or rehabilitating local generation capacity where economically justified. In addition, establishing an effective interconnection with the European Network of Transmission System Operators for Electricity (ENTSO-E) would enable the import of competitively priced power from the Energy Community (EnC) and would help overcome Moldova’s electricity sector challenges. Although Moldova joined the EnC in 2010 after having implemented major and successful sector reforms, its electric power system is physically still part of the former Soviet Union’s Integrated Power System/United Power System (IPS/UPS) and is effectively not interconnected with the EU/EnC’s Internal Energy Market (IEM). This limits the current supply options and exposes the country to very significant energy security risks. Interconnection to the IEM via Romania would increase and diversify Moldova’s sources of electricity supply and fuels used and provide access to competitively priced electricity. In 2013 the Government asked the World Bank to carry out a technical and economic analysis of Moldova’s power sector that would inform its decision-making regarding the policy options and measures necessary to improve the security and efficiency of the country’s energy supply. The World Bank, with funding support of the Energy Sector Management Assistance Program (ESMAP), agreed to do so. This Sector Study provides guidance to the Government on significantly improving Moldova’s security of energy supply via interconnection with ENTSO-E and therefore with the EU/EnC’s internal energy market. Based on the results of this study, asynchronous interconnection by 2020 with Romania and a market design that facilitates the import of competitively priced and procured electric power to meet the balance of Moldova’s electricity demand is the recommended solution. It would improve Moldova’s security of supply, help put downward pressure on electric power prices, and integrate the Moldovan electric power sector into the Energy Community. Basic characteristics of the Moldovan power system Moldova meets on average only about 25% of its electricity demand from domestic (i.e., Right Bank) generation and 75% through imports from Ukraine and (currently almost exclusively) from a large power plant on the Left Bank referred to as MGRES. About 95% of domestic generation comes from old and inefficient CHP plants which generate power at a high cost of about US$115/MWh, compared to an average electricity price of US$60/MWh (EUR45/MWh) in the EU. Even imports from Ukraine and MGRES, produced by mostly fully depreciated power plants, are priced around US$68/MWh. All power plants in Moldova, many in Ukraine and the MGRES plant (owned by Inter RAO-UES) use natural gas supplied by Gazprom, so that Moldova is also subject to substantial gas price and supply disruption risks, both inside and outside the country. i Interconnection scenarios The study consists of two main parts: (i) electric power system planning and (ii) power market design, plus associated annexes. The planning part of the study examines eight plausible interconnection scenarios: two self-sufficiency scenarios, four synchronous scenarios, and three asynchronous scenarios. It determines the parameters of the scenarios with the aid of an Excel-based model and uses Multi Criteria Decision Analysis to rank the scenarios. The criteria used to evaluate the scenarios through 2033 include: (i) present value of investments; (ii) levelized average end-user tariffs; (iii) security of supply provided; (iv) level of competition; (v) capacity to transit electricity between East and West; (vi) environmental impact; and (vii) operational difficulty. The scenario with the highest total score would rank number 1 and would be most suitable for Moldova. Our analysis concludes that the self-sufficiency scenarios rank lowest because of their high cost and resulting high tariff levels. Also, security of supply could become an even greater issue than it is at present because of the increased reliance on natural gas under these scenarios. The synchronous scenarios generally rank between the self-sufficiency and asynchronous scenarios. They would appear to offer the prospect of Moldova joining ENTSO-E as a full member, but the studies and testing that are required before that can happen are likely to take 10-15 years after completion of feasibility studies. It would also require disconnecting Moldova from the Ukrainian and Left Bank power systems, which would deprive Moldova from an important and possibly competing source of electricity supply. Recommendation 1. The top ranked interconnection scenarios are three alternative asynchronous interconnection scenarios with Romania, each scenario having two interconnections. Although one of these scenarios, referred to in this study as Asynchronous-2, ranks under most assumptions higher than the other two, the three scenarios are within one percent of each other in terms of ranking. For that reason we recommend that these three scenarios be studied at the same time at feasibility stage in order to ultimately select the most appropriate one for implementation. The scenarios consist of two Back-to-Back stations at Vulcanesti and Straseni (Asynchronous-1), Balti and Straseni (Asynchronous-2), or Vulcanesti and Balti (Asynchronous 3), respectively, along with associated high voltage lines and substation equipment. The investments required are estimated to range from US$421-441 million in current dollars, depending on the asynchronous scenario ultimately selected following feasibility studies. Implementation would result in a 20-year levelized tariff of about US$ 15.5 cents/kWh, which is affordable and therefore acceptable. The great advantage of an asynchronous scenario is that it can be implemented by 2020 and that it would not require disconnecting from Ukraine and MGRES. That way Moldova could benefit from obtaining electricity supply both from the East as well as the West (the Energy Community/EU electricity market) in a competitive manner. Under the asynchronous scenarios Moldova could become a Participant in ENTSO-E, with all the advantages of full Membership. Market Design The market design part of the study is based on the need for Moldova to obtain competitively priced electricity to the maximum extent possible, in order to offset the high production cost of regulated domestic cogeneration plants. The market design needs to comply with the EU’s target electricity market model, both because Moldova has undertaken to do so in the EnC context as well as because of the proposed integration of its market with the Romanian electricity market. This represents a ii major opportunity for Moldova to obtain more abundant and cheaper electricity than it can access at present. To build a truly competitive wholesale market in Moldova requires meeting the following criteria: (i) ensuring an appropriate structure by having enough sellers and buyers to provide competition on both the supply and demand side; (ii) adopting appropriate market rules; (iii) ensuring efficient balancing through provision of ancillary services and a balancing mechanism/market; and (iv) creating appropriate institutions with adequate capacity. These criteria define the structure of each of the three market design options analyzed by the study. Those market design options correspond to the self- sufficiency, asynchronous and synchronous interconnection scenarios, respectively. Recommendation 2. The market design recommended for Moldova, corresponding to an asynchronous interconnection scenario, would have appropriate competition rules for energy trading and cross-border capacity allocation. Moldova would seek to obtain competitively priced and procured supplies of electricity primarily from an existing well-organized and competitive wholesale market (Romania). Because there would be few domestic producers in Moldova and their prices would be regulated, this would not necessarily result in domestic wholesale competition. Instead, Moldovan suppliers would move the electricity obtained from Romania/EnC directly into the retail market. The retail market would increasingly be the main beneficiary of the competition in the Romanian/EnC wholesale market, thus gradually improving conditions for full market opening. At the same time, because of the asynchronous interconnection Moldova would continue to be able to import electricity from Ukraine and MGRES, but on more competitive terms than is presently the case. This market design would appear to be the best in the medium term because it would achieve rapidly the desired increase in security of supply for Moldova. In addition, the wholesale competition in the markets outside Moldova could exert downward pressure on end-user prices in Moldova. Implementation Implementation of any of the asynchronous interconnection scenarios would also require significant investments in strengthening the domestic power transmission system. Those investments are included in the total cost estimate for each scenario. They are necessary to enable full use of the interconnection and to provide a secure and reliable supply of electricity to Moldova. Feasibility studies will be needed for each major system component. In addition, comprehensive system planning would have to be done by Moldelectrica to determine the required structure of the power transmission system. This is necessary (and legally required) even without the interconnection option. Capacity building would be needed for Moldelectrica so it can perform and regularly update system planning based on changes in the demand for electricity and market signals. It should be emphasized that implementation of the recommended market design would require a number of legislative, regulatory and institution-building steps, many of which are already required to be undertaken in the context of the Energy Community. iii I Sector Background 1.1 Overview 1.1.1 Main characteristics of the power system in Moldova The main characteristics of Moldova’s electric power system are as follows: • Like the country itself, the power system is divided into two parts, covering the Right Bank and Left Bank of the Nistru River, respectively2. Moldelectrica (located on the Right Bank) is officially the transmission system operator for both the Left Bank and the Right Bank, i.e., it ensures system dispatch, even though it does not control the Left Bank’s transmission assets; • Limited domestic generation (25% of demand). Only up to 25% of Moldova’s electricity demand is met by domestic generation since the country has few reliably available generation assets. About 95% of that portion of demand is met by old, inefficient and expensive Combined Heat and Power Plants (CHPs) whose output must be bought at regulated prices of about US$ 115/MWh3. The remaining 5% is generated by the Costesti hydro power plant. All plants operate in base load, so there is no balancing reserve; • Extreme dependence on imports (75%). With declining efficiency and capacity to generate, Moldova is for 75% of its electricity demand dependent on imports of electricity from two sources: Ukraine and Moldova GRES (MGRES)4, a large power plant on the Left Bank of the Nistru. This reflects the fact that Moldova’s power system was designed as part of the former Soviet Union’s IPS/UPS power system and has remained so to this date. The combination of expensive domestically produced power with relatively expensive imported power due to a lack of effective connections to the West, this combination of factors leaves Moldova with high priced electricity in the range of US$ 80/MWh. • Direct power imports from Ukraine have decreased in recent years and come to a virtual halt on November 28, 2014, due to a power deficit in Ukraine. MGRES now accounts for virtually 100% of imports. As a result, security of supply has become an even more urgent issue. If power production from MGRES decreases sharply or if the plant is disconnected, massive load shedding will be necessary unless the shortfall can be covered by imports; • The Left Bank has three operating power plants: MGRES, Dubasari HPP and Tirotex CHP. MGRES (owned by Inter RAO-UES) represents about 97% of the total installed capacity there and accounts for about 95%5 of total generation output. At present MGRES alone has enough 2 The terminology Left Bank and Right Bank is in accordance with the Government’s official documents and statistics, including the Government’s Energy Strategy. 3 Current wholesale electricity prices in the EU are in the Euro 45/MWh (US$ 60/MWh) range. 4 Moldova GRES (owned by Inter RAO UES and situated on the left bank of the river Nistru) has 12 units each rated 200 MW of nominal capacity. The net transfer capacity of power transmission network between Ukraine and Moldova varies from 1,000 MW when 2 units are operating in MGRES to 1,200 MW when 6 units are operating in MGRES. Increased electricity production by MGRES means more operating units are producing. This increases the available transfer capacity for electricity imports from Ukraine and the reliability of power supply in Moldova. 5 http://mepmr.org/gosudarstvennaya-statistika/informacziya/70-osnovnye-pokazateli-raboty-promyshlennosti 1 capacity to meet Moldova’s electricity demand through 2020. Significant investments in the plant would be needed after that date to meet Moldova’s demand; • Cross-border connections. Moldova’s electricity system is synchronously interconnected with that of Ukraine, which is also part of the IPS/UPS system (See Map 1-1). It does not have a 400 kV line with Ukraine and the junction Moldova-Ukraine was not developed as a country-to-country interconnection. In fact, Moldova’s network is used by the Ukrainian system to transfer electricity for its own purposes from North to South. This is an element in favor of Moldova during power import price negotiations with Ukraine. An existing 400 kV line with Romania was against expectations not used for imports and has not been maintained; and • Near-exclusive dependence on one source/supplier of natural gas. With the minor exception of hydropower, natural gas is currently the only fuel in the electricity generation mix. Not only all domestic CHPs but also MGRES and to a lesser extent imports from Ukraine depend on Gazprom as gas supplier. Its transit and price determine security of supply and affordability of energy in Moldova. Consequently, in the absence of functional and reliable interconnections with ENTSO-E6 as well as commercial relations with the EnC, Moldova is vulnerable to all events that could impact the price and availability of gas. 1.1.2 Government Policy and Strategy in Electricity The Government has identified the main focus of its policy to be security of energy supply for Moldova. The factors that make the country’s security of supply vulnerable are the following: (a) inadequate and inefficient sources of domestic power generation; (b) near-exclusive dependence on one source/supplier of natural gas; and (c) dependence on two power import sources, which have shown oligopolistic tendencies in their pricing. In recent years the Government has set in motion a series of policy reforms and set strategic targets for the energy sector to address these concerns. Reform through 2011. The power sector of Moldova has achieved important results over the last 15 years through a process of reform, privatization and restructuring. About two-thirds of the distribution system is operated by a private strategic investor, Union Fenosa. The sector now has strong payment discipline with collections at nearly 100% of billings. An independent and competent Energy Regulatory Agency (ANRE) started work in 1997. As a result of these successful initial reforms, Moldova could join the EnC as a Contracting Party in 2010 (Annex 1). Moldova’s Energy Strategy through 2030. In the Energy Strategy of the Republic of Moldova until 20307, the Government set itself three main objectives: (i) security of supply; (ii) development of competitive markets and their regional (i.e., in South Eastern Europe, the 8th region) and European integration; and (iii) sustainable development and climate change abatement. It recognizes that in the absence of physical electricity and natural gas interconnections competitive markets cannot be realized. Interim objectives through 2020 are to: (i) consolidate Moldova’s role as an electricity transit country; (ii) ensure interconnection to ENTSO-E (either synchronous or asynchronous); (iii) create a 6 Moldova is interconnected with ENTSO-E (Romania) but these connections are limited and in practice not usable. 7 Energy Strategy of the Republic of Moldova until 2030 (February 2013) 2 Map 1-1. Moldova and neighboring power systems 3 powerful generation platform; and (iv) build a modern and competitive institutional framework. To that end the Strategy proposes ambitious targets: (a) building large interconnectors; (b) a 20% RES- E share of gross electricity consumption; and (c) 800 MW in new generation capacity. Reaching all these targets will be time consuming and expensive. Achieving interconnection at acceptable cost and implementing an appropriate market design could save both time and money. Interconnecting to ENTSO-E. The Strategy states that Moldova intends to physically join the EnC’s electricity market in order to foster competition and increase security of supply and energy efficiency. Connecting to the ENTSO-E system is listed as one of the main priority actions to achieve this objective. Establishing a functional interconnection with Romania represents a critical first step in this regard. By doing so Moldova would diversify its sources of external electric power supply, reduce its almost exclusive dependence on the two current sources of supply, foster competition, and limit electric power price increases. This kind of integration into the regional power market was Moldova’s primary objective in joining the EnC. Measures facilitating this are therefore a clear policy priority. 1.2 Power Supply System 1.2.1 Existing Right and Left Bank capacity Right Bank capacity deficit, Left Bank surplus. Although Moldova’s (Right Bank) installed capacity as of January 2014 was 376 MW, available capacity was only 247 MW. While the Right Bank experienced a peak load capacity deficit of 584 MW in 2012, the Left Bank had a capacity surplus of 1,131 MW during that year. Moldova’s own electricity sources covered on average only up to 30% of peak load demand during 2008-2013. The remainder, currently around 600-625 MW, was covered by MGRES and Ukraine (Table 1-1). Table 1-1. Peak Load Demand and Supply, 2008 – 2013 (MW) 2008 2009 2010 2011 2012 2013 Annual Peak Load Demand 792 780 805 820 831 833 Right Bank Supply of Peak Load Demand, 275 256 260 213 247 209 including: CHP-1 40 30 30 13.7 25 27 CHP-2 210 196 201 173 202 162 CHP-Nord 20 20 20 20 20 20 HPP Costesti 5 9 9 6 0 0 Deficit, covered by: 517 525 545 607 584 624 – MGRES 420 399 438 517 524 545 – Ukraine 187 185 186 Source: Moldelectrica 1.2.2 Participation in load demand (domestic and foreign) Graphic presentations of how load demand was covered in 2012 by the available power sources, corresponding to typical seasonal load curves are presented in Figure 1-1. The graph shows that CHP- 1, CHP-N and HPP Costesti participate occasionally in completing the load curve. However, in the middle of the summer only MGRES and Ukraine were supplying power to Moldova. 4 Figure 1-1. Power sources participation in Load Duration Curve during 2012 Source: Moldelectrica Moldova has a large and growing capacity deficit. If new capacity is not built the 624 MW peak load capacity deficit recorded in 2013 is expected to increase by almost 40% to 870 MW by 2033. In order to eliminate this capacity deficit, the Energy Strategy proposes to build 250-400 MW of renewable sources by 2020 (mainly wind farms), reaching up to 600 MW by 2030. At the same time, the Strategy proposes to build a Combined Cycle Gas Turbine (CCGT) of 650 MW to replace the existing CHP-1 and CHP-2 by 2018-20208. The Strategy also proposes imports through asynchronous or synchronous interconnection to ENTSO-E by 2020 to address the growing supply deficit that the country is expected to face. 1.2.3 Existing electricity import arrangements Electricity imports from Ukraine and the Left Bank (MGRES). Imports from Ukraine are contracted between Energocom (Moldova’s exclusive buyer for electricity imports from Ukraine) and a Ukrainian supplier. The latter is selected based on Ukrainian bids for the allocation of the available Ukraine-Moldova interconnection capacity. The electricity exported from Ukraine must be bought exclusively through the country’s centralized power market based on bids produced each hour. Prices are high during the day, and relatively low at night. In contrast, MGRES is free to negotiate the price and amount of electricity sold with any party in the region 9. It also has another advantage compared with the Ukrainian supplier, due to the currently low price for gas set by the Left Bank’s administration. However, a technical limitation prevents these two suppliers from competing directly: as less MGRES capacity is loaded less power can be imported from Ukraine due to static stability limitations in the regional power system. Possibly because of this constraint there is the appearance 8 Energy Strategy of the Republic of Moldova until 2030 (February 2013) 9 Electricity purchased from MGRES is based on MGRES’s own pricing. There is no documentation available on the cost structure o f electricity sold by MGRES. The cost-benefit analysis in this study uses the expected purchase price of electricity informed assumptions on the cost of fuel (natural gas) – which is believed to be highly subsidized – and O&M costs of generation units comparable to those installed at MGRES. 5 of price collusion between these suppliers, further enhanced by Moldova’s current inability to import power from Romania. The capacity to import from Ukraine is limited by the static stability criterion at the control interface Ukraine - Moldova, which consists of 4 lines of 330 kV Dniestrovscaia HPP (UA) - Balti (MD), Kotovsk (UA) - MGRES (MD) and Adjalik (UA) - Usatovo 1 and 2 (UA). Import capacity depends on the power flow at the control interface for the Odessa region, the configuration of the Moldovan and Ukrainian transmission lines, and the number of generation units in operation at MGRES and Dniestrovscaia HPP. During normal network configuration and operation, the allowable power flow through the control interface depends on the number of units operating at MGRES and the Dniestrovscaia HPP producing 1,250–1,500 MW. In 2011, the maximum load at the control interface to Odessa was 900 MW, while the remaining import capacity for Moldova was in the range of 350- 600 MW. Mutual dependence. Due to both countries’ existing transmission system configuration and being an integral part of the IPS/UPS, Ukraine is dependent on the Moldovan transmission system to supply power to the Odessa region. Moldova, in turn, depends on electricity flows from Ukraine to balance and ensure frequency control of its own transmission system. This is based on an informal agreement between the TSOs of both countries under which Moldova bears the transmission losses associated with providing power to the Odessa region in exchange for receiving Ukrainian electricity to ensure adequate balancing power and frequency control. Those two flows are netted out against each other and reconciled at regular intervals. As explained above, the electricity flows from and to Ukraine are also important for MGRES’ operation. The electricity flows between the two countries, and between the Right Bank and the Left Bank, are metered on an hourly basis. In fact, the Moldovan system is technically a component of a larger loop within the Ukrainian transmission system. The Ukrainian electricity flowing into the Moldovan transmission system ensures the latter’s balancing and frequency control even when no electricity imports are contracted from Ukraine. This has continued to be the case even though Ukraine halted all other supplies to Moldova on November 28, 2014, given the emergence of a power deficit in Ukraine. As a result, all imports other than those necessary for system balancing and frequency control are currently being supplied by MGRES. MGRES cannot provide the necessary balancing power and frequency control for the Right Bank because it does not have the stand-alone gas turbine necessary for that. As discussed in Section 4.3.3 of this study, even after the interconnection capacity with ENTSO-E is established and tertiary reserves can be acquired from Romania, primary and secondary reserves will still need to be acquired from Ukraine. However, this would then have to be done under formal contractual arrangements as per the rules of the Energy Community. Current constraints on imports from Romania. Because Romania is a member of ENTSO-E and follows its standards of maintaining system frequency, only limited quantities of power can be imported from Romania by using the island mode of power supply. The maximum load that can be imported through all interconnection lines together (3 x 110 kV and 1 x 400 kV) is about 200 MW, in island mode and not respecting ENTSO-E’s N-1 criterion.10 Because this is operationally complicated, this possible import venue is not used. To operate the system while respecting the N-1 10 The N-1 Criterion is a rule according to which elements remaining in operation after failure of a single network element (such as transmission line / transformer or generating unit) must be capable of accommodating the change of flows in the Network caused by that single failure. (Source: ENTSO-E metadata repository) 6 criterion would require about 150 km of additional 110 kV lines and appropriate voltage transformers. However, given the limited amount of power that could be imported this way (about 20% of peak demand) it is not cost-effective to split the national grid in two. 1.3 Transmission Grid Moldelectrica operates the electricity transmission networks on the Right Bank, including 5,978 km of 400, 330, and 110 kV transmission lines. There are two 330 kV lines and twelve 110 kV interconnection lines between the Right Bank and the Left Bank (Table 1-2 and Map 1-2). Table 1-2. Key components of the Moldovan electricity transmission network Transformers Voltage level, kV Lines length, km Number Installed capacity, MVA 400 202.5 1*) 500* 330 532.4 5 (3*) 2,515 (1,525*) 110 5,231.1 166 (131*) 3,687 (2,404*) Total 5,977 Source: Moldelectrica Note: *Owned by Moldelectrica The high-voltage interconnection lines with neighboring countries include 7 lines of 330 kV and 11 lines of 110 kV with Ukraine, with a total capacity of 3,150 MW, and 3 lines of 110 kV and 1 line of 400 kV (Vulcanesti-Isaccea) with Romania. Together these lines have a total capacity of 1,040 MW (see Map 1-2). The transmission network of Moldova was built and optimized to serve the needs of the IPS/UPS when it was still synchronized with Romania, Bulgaria and most eastern European countries. Since these countries joined ENTSO-E, the disconnected Moldovan system has experienced certain constraints with regard to operational stability and power exchange. 7 Map 1-2. Capacities of the Moldovan power grid (RB) Source: Moldelectrica 8 II. Demand and Load Forecast 2.1 Assumptions used for Demand Projection In order to determine the capacity of the power sources (own power plants and interconnection lines) and their structure (base load, peak load, etc.) needed for Moldova, the following data should be available: electricity demand forecast, typical load curves, load duration curve, and annual peak load forecast. The data provided below are based on power delivered at frontier to Moldelectrica, i.e., it covers both electricity used by consumers and network losses. The details and additional data are provided in Annex 211. 2.1.1 Electricity demand forecast Average forecast demand growth: 2.1% per year. The demand forecast made in this study was top- down, based on the country’s gross electricity consumption. It was calculated by extrapolating the growth in Moldova’s Purchasing Power Parity GDP12 and gross electricity demand (D) during 2001 – 201313. A scatter chart was used to calculate the electricity demand forecast based on the 2001-13 GDP and demand data, which turned out to have a high 88.3% correlation. The forecast for 2014- 2033 is built based on a linear function (D=f(GDP)) that approximates the relation between D and PPP GDP (GDP), both recorded during 2001-2013 (D=187.85 x GDP + 1,789.7). Assuming for the years after 2014 a GDP growth rate of 3.26%/year, equal to the average annual increase during 2001- 2013, GDP and then D were forecast based on that formula. This corresponds to an average annual growth in electricity demand of 2.1% during 2014-2033. Details of the calculation are in Annex 2. This base case forecast, as well as the evolution of demand using alternative annual demand growth rates, is shown in Figure 2-1. 11 This study’s analysis has revealed a significant lack of data normally required for a thorough analysis and forecast of elect ricity demand in Moldova. Getting that data would require additional collection and compilation efforts, which was not feasible within the existing budget and time frame. Also the study, by design, aims to identify strategic options based on a broad but robust analysis and indicate the directions for further work, rather than being a final system planning study. 12 The evolution of the country’s effective PPP GDP is based on reports from the Ministry of Economy of the Republic of Moldova, Department of Macroeconomic Analysis and Forecasts. 13 Source: ANRE annual reports. 9 Figure 2-1. Electricity demand forecasts with alternative annual growth rates Source: Study calculations 2.1.2 Peak load forecasts Typical load curves. Typical daily load curves in Moldova for all four seasons show that in 2012 the maximum daily peak load in a typical load curve was in December at 759 MW. The minimum daily load was in July, at 278 MW (see Figure 2-2). For statistical purposes these are calculated every Third Wednesday of each month. However, the absolute annual recorded peak load in 2012 was 831 MW on February 2, 2012 (Thursday) and this is considered the reference point for determining security of supply during 2014-2033. Two important factors in the approach used for the peak load forecasts for 2014-33 are: • Moldova’s annual peak load is in the winter. In the summer the peak load is significantly lower, in part because the days are longer and because the use of air conditioning is not yet a major factor. For example, in 2012, the difference between the winter and summer peak loads is about 150-240 MW (Figure 2-2). • The load factor started to increase in 2011, reaching a year-on-year increase of 0.3% in 2013. We are assuming that the load factor will continue to increase by 0.5%/year through 2033 based on increasing use of air conditioning, increased efficiency and use of multiple shifts at enterprises, and introduction of differentiated tariffs after full market opening. This would result in better utilization of available power plants and a saving of 120 MW in generation and grid power capacity by 2033. 10 Figure 2-2. Summer and winter typical daily load curve Source: Based on Moldelectrica data. Total electricity consumed by the Moldovan power system during 2012, including transmission and distribution losses, was 4,050 GWh. The load factor was 4,875 hours or 55.6 %, i.e., much lower than the Ukrainian load factor (6,700 hours or 76.5%) and the Romanian load factor (7,275 hours or 83.0%). However, it should be noted that Moldova’s power plants are essentially all CHPs, some of which do not operate at all while others operate at lower capacity during 5-6 months of the year. 2.1.3 Seasonal forecasts through 2023 Detailed forecasts through 2023. The seasonal electricity and peak load demand for the first 10 years of the analysis was estimated on a more detailed basis than for the last ten years. To this end gross electricity demand for spring, summer, autumn and winter were calculated for 2012, based on available hourly load data. The share of each season’s electricity demand in the total was then kept constant for the next 10 years. The annual 0.5% load factor increase assumption (see section 2.1.2) was added subsequently. Seasonal peak load forecasts were determined in proportion to the corresponding growth in electricity demand. Table 2-1. Actual and forecast electricity and peak load demand, by season (2012-2023) Years 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 Spring 940 945 968 986 1005 1024 1044 1064 1085 1107 1130 1153 Electricity Summer 925 930 952 970 988 1007 1027 1047 1067 1089 1111 1134 demand Autumn 984 989 1013 1032 1051 1071 1092 1113 1135 1158 1182 1206 (mil. kWh) Winter 1202 1208 1237 1260 1284 1308 1334 1360 1387 1415 1444 1473 TOTAL 4050 4072 4170 4248 4328 4410 4496 4584 4675 4769 4866 4967 Spring 690 693 710 723 737 751 766 781 796 812 829 846 Peak Load Summer 724 728 746 760 774 789 804 820 836 853 870 888 Demand (MW) Autumn 766 770 789 803 818 834 850 867 884 902 920 939 Winter 831 833 849 862 873 886 898 911 925 939 953 968 Source: Calculations based on Moldelectrica data. Data for 2012 and 2013 are actuals. 11 Gap between winter and summer peak load decreasing. The results show that summer and spring electricity demand are almost the same, while peak load in the summer is 35 MW higher than in the spring in 2012 and 43 MW higher in 2023. Although both remain much lower than the corresponding numbers for the winter, the gap between winter and summer peak load is decreasing. In 2012 it was 107 MW while in 2023 it is forecast to be 79 MW. 2.1.4 Annual forecasts through 2033 Based on the assumptions above Table 2-2 shows the annual electricity demand and peak load forecasts through 2033, along with other parameters considered in their calculation. By 2033 gross annual electricity demand is forecast to be 6,168 GWh, a 52% increase over 2013. Peak load would reach 1,143 MW, a 37% increase over 2013. The electricity demand forecast as per the Energy Strategy until 2030, forecasts a much higher annual rate of growth of 4.9%. Based on that forecast, electricity demand is expected to reach 9,649 GWh in 2030 and maximum peak load would be 1,815 MW, both 67% more than forecast in this study for the same year. Table 2-2. Electricity Demand and Peak Load Forecast through 2033 Energy Strategy 2030 forecast Electricity Peak Load GDP Load Factor Electricity Peak Load demand demand Year demand demand bill. % mill. % % % mill. % % h MW MW US$ growth kWh growth growth growth kWh growth growth 2012* 11.88 0.01 4050 1.42 4874 0.1 831 1.3 4050 1.4 831 1.3 2013 12.27 3.26 4072 0.53 4888 0.3 833 0.2 4072 0.5 833 0.2 2014 12.67 3.26 4170 2.41 4909 0.4 849 2.0 4580 12.5 933 12.0 2015 13.08 3.26 4248 1.86 4930 0.4 862 1.4 4836 5.6 981 5.2 2016 13.51 3.26 4328 1.89 4955 0.5 873 1.4 5106 5.6 1030 5.0 2017 13.95 3.26 4410 1.91 4980 0.5 886 1.4 5398 5.7 1084 5.2 2018 14.41 3.26 4496 1.94 5005 0.5 898 1.4 5688 5.4 1136 4.8 2019 14.88 3.26 4584 1.96 5030 0.5 911 1.5 5994 5.4 1192 4.9 2020 15.36 3.26 4675 1.99 5055 0.5 925 1.5 6314 5.3 1249 4.8 2021 15.86 3.26 4769 2.01 5081 0.5 939 1.5 6625 4.9 1304 4.4 2022 16.38 3.26 4866 2.04 5106 0.5 953 1.5 6950 4.9 1361 4.4 2023 16.91 3.26 4967 2.06 5132 0.5 968 1.5 7290 4.9 1420 4.4 2024 17.46 3.26 5070 2.08 5158 0.5 983 1.6 7613 4.4 1476 3.9 2025 18.03 3.26 5177 2.11 5184 0.5 999 1.6 7950 4.4 1534 3.9 2026 18.62 3.26 5287 2.13 5210 0.5 1015 1.6 8303 4.4 1594 3.9 2027 19.23 3.26 5401 2.16 5236 0.5 1032 1.6 8630 3.9 1648 3.4 2028 19.85 3.26 5519 2.18 5262 0.5 1049 1.7 8971 4.0 1705 3.4 2029 20.50 3.26 5641 2.20 5289 0.5 1067 1.7 9325 4.0 1763 3.4 2030 21.17 3.26 5766 2.23 5316 0.5 1085 1.7 9649 3.5 1815 3.0 2031 21.86 3.26 5896 2.25 5342 0.5 1104 1.7 2032 22.57 3.26 6030 2.27 5369 0.5 1123 1.8 2033 23.31 3.26 6168 2.29 5396 0.5 1143 1.8 Source: Calculations based on Moldelectrica data and Energy Strategy until 2030 of the Republic of Moldova Note: The year 2012 is considered as the baseline. 12 2.1.5 Domestic generation capacity assumptions Only supply sources that are scheduled to be in operation after 2020 and common to all scenarios are examined here: Renewable Energy Sources, CHP-3, and CHP-N. Any other sources are separately examined under each scenario considered. Renewable Energy Sources – Electricity (RES-E). It was assumed that only 150 MW of new RES- E will be built to help cover Moldova’s electricity demand. This capacity is in accordance with Moldova’s National Renewable Energy Action Plan (NREAP)14. Virtually all of the new RES-E is expected to come from wind farms. RES-E sources cannot meet demand at all times due to their dependence on weather conditions. A 2007 Stanford University study concluded that by interconnecting ten or more wind farms spread over a large area an average of 33% of the total energy produced (i.e., 8% of installed capacity assuming a load factor of .25) can be counted on as reliable base load electric power to handle peak loads, as long as minimum criteria are met for wind speed and turbine height15. However, due to Moldova’s small territory, where wind characteristics do not differ much from site to site, the percentage of base load electric power that can be relied on to handle peak loads will be much lower. This is assumed to be equal to 2% of installed capacity, or 3 MW base load equivalent (based on a 150 MW installed RES-E capacity). Combined Heat and Power Plant 3 (CHP-3). CHP-3, with a capacity of 250 MW, will replace CHP-2 in 2020, according to the concept for the corporate, institutional and financial restructuring of the District Heating system in Chisinau approved by the Government16. CHP-N in Balti will keep its capacity of 20 MW until 2033. Table 2-3. Forecasted domestic power generation capacity (MW) Source 2013 2014 2015 2016 2017 2018 2019 2020 2021 2025 2030 2033 HPP 0 0 0 0 0 0 0 0 0 0 0 0 CHP-1 27 25 0 0 0 0 0 0 0 0 0 0 CHP-2 162 202 202 202 202 202 202 0 0 0 0 0 CHP-3 0 0 0 0 0 0 0 250 250 250 250 250 CHP-Nord 20 20 20 20 20 20 20 20 20 20 20 20 RES-E 0 0 0 0 0 0 0 3 3 3 3 3 Total Local 209 247 222 222 222 222 222 273 273 273 273 273 available capacity Source: Study calculation. Factors influencing the development of Moldova’s own power generation capacity are: (i) consumers’ capacity to pay for electricity produced by new power plants; (ii) capacity reserves in Ukraine, MGRES and Romania; and (iii) interconnection capacities with Ukraine and Romania (the latter is discussed in Section 1.2.3). (i) capacity to pay Consumers’ capacity to pay is low and not expected to go up much through 2020. The average wage of US$ 302/month is considered the lowest in the Europe17. The average household paid 14 National Renewable Energy Action Plan of the Republic of Moldova for 2013-2020 (December 2013) 15 Supplying Baseload Power and Reducing Transmission Requirements by Interconnecting Wind Farms. Cristina L. Archer and Mark Z. Jacobson, 2007, Journal of Applied Meteorology and Climatology, Vol. 46, November 2007. 16 Decision of the Government of Moldova, dated November 18, 2011, on the Concept for corporate, institutional, and financial restructuring of the District Heating system in Chisinau. 17 IMF Country Report, February 2012 13 US$ 12/month for electricity consumed in 201218. However, as the analysis in our study will show, building domestic capacity to the point of Self-Sufficiency is the most expensive of all options and would lead to unaffordably high electricity tariffs for a large part of Moldova’s energy consumers. (ii) capacity reserves in Ukraine, MGRES and Romania Ukraine: inadequate capacity starting in 2018. Analysis of the power capacity available in Ukraine to meet Moldova’s maximum load deficit up to 2033 shows that currently a large part of Ukraine’s power-generation and transmission assets are almost fully depreciated19. Prior to the current conflict in Eastern Ukraine, which impacts on the coal supply, it was already estimated that Ukraine would not have enough capacity to satisfy its own peak demand starting in 2018 and thus it cannot cover Moldova’s power deficit through 2033 either20. Doing so would require investments of at least US$ 1.0 billion per year, which Ukraine cannot afford under current circumstances and private investors are unlikely to provide given the lack of an adequate market environment in the country. The ongoing conflict has brought the capacity shortage date in Ukraine forward and accelerated the need for new investment. MGRES: enough capacity but significant investments needed after 2020. MGRES was built during 1964-1982. Although total nameplate capacity is 2,520 MW, actually available capacity is much lower21. Capacity available for Moldova through 2020 would not exceed 950-1,000 MW. Significant investments are needed to maintain this capacity after 2020, but information on MGRES’ investment plans could not be obtained and it is not obvious where the funding for these investments would come from. Thus there is also a question mark over MGRES’ ability to cover Moldova’s power deficit beyond 2020. Romania: enough capacity through 2033. Under most scenarios both security of supply for and competition in Moldova’s power system depends very much on the capacity reserves of Romania’s power system once the Moldovan power system joins the Romanian power system. Analysis conducted under this study indicates that Romania will have more than enough excess baseload capacity to meet Moldova’s load deficit up to 2033. Specifically, even after Romania satisfies Moldova’s load deficit it will still be able to export about 3,000 MW at any time during 2020-2033. Furthermore, this number excludes about 4,500 MW in intermittent RES-E capacity in Romania. 2.1.6 Energy balance forecast The analysis shows that the annual peak load demand of 831 MW in 2012 is expected to increase by almost 38% to 1,143 MW in 2033. Based on our assumptions, domestic generation will cover about 24% of peak load demand, or 273 MW. The expected peak load capacity deficit of 870 MW by 2033 (Table 2-4) would have to be covered by imports. Given the shortcomings described above it would be very risky to rely on the existing import arrangements. Therefore, the study proposes to establish interconnection with the EnC’s electricity market via Romania. This would improve Moldova’s security of supply and facilitate import of competitively priced and procured electric power. 18 ANRE Annual Report 2012 and http://www.statistica.md 19 http://www.energy-community.org/portal/page/portal/ENC_HOME/MEMBERS/PARTIES/UKRAINE 20 The Ukrainian Energy Exchange Company (UEEC) forecasted in 2010 a peak load deficit starting in 2014. (http://www.slideshare.net/EnergotradingUA/pres-ueex-v30rus) 21 As designed, MGRES has 12 condensing units with a capacity of 200-210 MW each, along with two 40 MW gas turbines. The last two, together with 2 condensing units of 210 MW each, form two combined cycle units of 250 MW each, built in 1980 and 1982, with a design efficiency of 42%. However, a number of units are no longer in operation. MGRES can produce electricity based on coal, natural gas- and heavy fuel. 14 Table 2-4. Peak load demand and capacity deficit coverage through 2033 by source of supply (in MW) Year 2012 2013 2015 2019 2020 2025 2030 2033 Annual Peak Load Demand 831 833 862 911 925 999 1,085 1,143 Domestic Generation 247 209 247 247 273 273 273 273 CHP-1 25 27 0 0 0 0 CHP-2 202 162 202 202 0 0 0 0 CHP-3 0 0 0 0 250 250 250 250 CHP-Nord 20 20 20 20 20 20 20 20 RES-E 0 0 0 0 3 3 3 3 TOTAL Deficit 584 624 640 689 652 726 812 870 Covered by: MGRES imports 399 438 400 400 Depending on the scenario selected Ukraine imports 185 186 240 289 Source: Forecasts based on ANRE data. Data for 2012 and 2013 are actuals. III Scenario Analysis 3.1 Alternative Scenarios Analyzed Scenario analyses on how electricity could be supplied to Moldova were conducted based on the assumptions outlined above and the investment costs, resulting end-user tariffs and other variables. Nine variants of three basic scenarios were analyzed: • Synchronous interconnection with ENTSO-E, under which Moldova disconnects Ukraine and MGRES, being part of the IPS/UPS. Under this scheme two sub-categories of scenarios were considered: (i) self-sufficiency; and (ii) interconnection development • Asynchronous interconnection with ENTSO-E through a direct current (DC) link connecting Romania and Moldova via Back-to-Back (BtB) stations, under which Moldova, Ukraine and MGRES would remain in the IPS/UPS. This scheme has only interconnection development. The scenarios are summarized in Figure 3-1. They were analyzed using an excel-based power system planning model (see Annex 3). 15 Figure 3-1. Nine variants of three basic scenarios analyzed Self-Sufficiency Scenarios SS-1 SS-2 Suceava Suceava Balti Balti Straseni Ribnita Straseni Ribnita Iasi Chisinau Iasi Chisinau Vulcanesti Vulcanesti MGRES MGRES Isaccea Isaccea Synchronous Scenarios S-1 S-2 S-3 S-4 Suceava Suceava Suceava Suceava Balti Balti Balti Balti Straseni Ribnita Straseni Ribnita Straseni Ribnita Straseni Ribnita Iasi Chisinau Iasi Chisinau Iasi Chisinau Iasi Chisinau Vulcanesti Vulcanesti Vulcanesti MGRES MGRES MGRES Vulcanesti MGRES Isaccea Isaccea Isaccea Isaccea Asynchronous Scenarios A-1 A-2 A-3 Suceava Suceava Suceava Balti Balti Balti Straseni Ribnita Straseni Ribnita Straseni Ribnita Iasi Chisinau Iasi Chisinau Iasi Chisinau MGRES MGRES MGRES Vulcanesti Vulcanesti Vulcanesti Isaccea Isaccea Isaccea 16 Common assumptions. The capacities of new High Voltage Lines (HVL) and Back-to-Back (BtB) stations were determined based on the forecast annual peak load demand in the 330-400 kV nodes. As stated above, in the interconnection development scenarios (Synchronous and Asynchronous) the annual peak load demand is covered by local power sources (CHP-1, CHP-2, CHP-N and RES-E; after 2020 CHP-1 and CHP-2 will be replaced by CHP-3), imports from Romania and – under some scenarios – Ukraine and MGRES as well. The maximum load of local power plants is assumed to be constant during the forecasting period, including 3 MW of RES-E starting in 2020. In 2012 local power plants covered 31% of maximum load demand. 3.1.1 Self-Sufficiency scenarios Self-Sufficiency scenarios assume the construction of power capacities in Moldova that can adequately satisfy the country’s peak load. As soon as that goal is reached, Moldova would be capable of being solely responsible for frequency control, which is the main requirement for joining ENTSO- E. Two scenarios were examined under Self-Sufficiency: Self-Sufficiency 1 (SS-1) based on use of both coal and natural gas (CHP-3, Combined Cycle Power Plant, Coal fired Power Plant); and Self-Sufficiency 2 (SS-2) based solely on natural gas use (CHP-3 and Combined Cycle Power Plants). The PV of total investment costs for each of these scenarios is more than US$1.0 billion, virtually all of it for generation capacity. Since the location of most new plants is not known at this stage an assumed 2.5% of total generation investment costs was included for transmission investments. Because investors would not build power plants in Moldova without adequate guarantees, such plants would be built under the tendering (rather than the authorization) procedure with long-term power purchase and sales agreements. This is expected to result in relatively high prices, to be paid by the Moldovan consumers through 2033. In addition, the self-sufficiency scenarios would not increase but rather decrease Moldova’s energy supply security, since they would further increase dependence on Russian natural gas due to limited alternative fuel sources available. Details of the Self- Sufficiency scenarios are in Annex 5. 3.1.2 Synchronous scenarios Synchronous interconnection has the major advantage of connecting Moldova directly to the EU/EnC’s Internal Energy Market via Romania, potentially allowing procurement of a large array of competitively priced supplies and fuel sources. However, complex technical problems would need to be resolved before being able to join ENTSO-E and that process may take 10-15 years. Also, all but one (S-3) of the synchronous scenarios have the disadvantage of requiring disconnection of the Left Bank and Ukraine, since they would remain part of the IPS/UPS. This would raise political issues and deprive Moldova of those sources of electricity supply from the East and enhanced competition with supply sources from the West. Both the synchronous and asynchronous scenarios depend very much on the capacity reserves of Romania’s power system once Moldova is connected to it. This is realistic because our analysis concluded that even after Romania meets Moldova’s expected load deficit it will still be able to export about 3,000 MW at any time during 2020-2033. 17 This study considered four synchronous interconnection scenarios: • Synchronous 1 (S-1) assumes that Romania covers both the entire power deficit and all ancillary services of Moldova’s power system, thus respecting ENTSO-E requirements regarding Moldova’s eventual integration into ENTSO-E. It implies the construction of new power plants as in SS-2 scenario above; • Synchronous 2 (S-2) assumes the same as S-1 except for different interconnection points and required transmission lines; • Synchronous 3 (S-3) assumes that the power deficit would be covered by both Romania and MGRES, while the ancillary services would be covered only by Romania. The entire Moldovan power system, including most assets located on the Left Bank, would be connected synchronously with ENTSO-E. However, this scenario may not be realistic in view of the political realities in Moldova, the ownership of MGRES and the subsidized price on natural gas it uses as fuel, which would be against the rules of IEM. • Synchronous 4 (S-4) assumes that Romania would cover both the entire power deficit and all ancillary services similarly to S-1, but it will require much larger investments in the domestic transmission grid to enable synchronous operation with Romania and to ensure that n-1 criterion is met, as it assumes only one interconnection line with Romania in the South. Our analysis of these four synchronous configurations concluded that these would be at best very long-term options for the following reasons: • ENTSO-E is prepared to study Ukraine and Moldova joining ENTSO-E simultaneously. It is far from certain that it would be willing to undertake similar studies and accompanying measures for Moldova alone. As it is, the joint feasibility study on Ukraine and Moldova, which was supposed to start in 2006, may start only in 2015 and would take two years to complete; • The synchronous scenarios require disconnection from Ukraine and MGRES, who are currently providing both power and ancillary services to Moldova. Disconnection from Ukraine would require substantial investments into Moldova’s domestic transmission network and significant institutional capacity building for both the TSO and the power plants; • The requirement for full synchronous interconnection with ENTSO-E will only be met after substantial technical, regulatory, legislative and institutional measures have been completed. This process will be time consuming; • The above process can be expected to take about 10-15 years, based on ENTSO-E assessments and considering recent examples such as Turkey. During all this period Moldova would have to absorb all the associated costs of compliance with the ENTSO-E requirements, while continuing to be exposed to major energy supply security risks. Details of the synchronous scenarios are also in Annex 5. 18 3.1.3 Asynchronous scenarios Two power systems with different frequency standards (“asynchronous� systems) can be linked either through High Voltage Direct Current (HVDC) lines or Back-to-Back (BtB) Stations. A HVDC line takes electrical power from an alternating current (AC) system and converts it into high voltage direct current (DC) using a converter station. It then transmits the DC to a remote system through a DC line, where it is converted back to AC by another HVDC converter station. BtB stations are also HVDC systems, but the second convertor is located in the same place as the first converter, i.e., there is no need for a HVDC line. Assuming that synchronous interconnection with the Energy Community is the country’s longer-term goal, those lines can be used for future synchronous interconnection as well should that become a feasible option. The three main asynchronous scenarios considered in the analysis are described in detail in Annex 6 and are summarized below. Each scenario would have two interconnections and would ensure a good level of energy security for Moldova as the electricity could be bought from East and/or West. The following BtB station locations and capacities are proposed for each of the three alternative scenarios, respectively (see Figure 3-2 below): Asynchronous 1 (A-1) – Vulcanesti (525 MW VSC)22 and Straseni (522 MW LCC); Asynchronous 2 (A-2) – Balti (522 MW LCC) and Straseni (522 MW LCC); and Asynchronous 3 (A-3) – Vulcanesti (525 MW VSC) and Balti (522 MW LCC) In addition to the BtB Stations, each scenario also includes the investments required in transmission lines and the appropriate substation equipment to provide adequate capacity to supply power to the load centers and to ensure system stability. Technology selection between VSC and LCC should be determined based on economic and operational characteristics. There are two primary BtB technologies: Line Commutated Converter (LCC) and Voltage Source Converter (VSC). BtB substations based on conventional LCC technology depend on the Short Circuit MVA (SCMVA) at the connection point to the grid (Annex 6). The new VSC technology substations can operate independently from the SCMVA at the connection point. Today, both technologies are being used. While thyristors are utilized in conventional LCCs, VSCs employ Insulated Gate Bipolar Transistors. According to independent studies, this makes the unit cost of VSC-based technology about 25% higher than that of LCC23. These operational and economic characteristics should be carefully analyzed to determine which technology is most appropriate for the system. Asynchronous interconnection offers several benefits to Moldova: • Diversification of power and fuel sources. This option would allow Moldova to procure competitively priced electricity from Romania and from plants using a variety of fuels 22 The VSC technology is proposed for Vulcanesti because of the very low Effective Short Circuit Ratio (ESCR) there, even though VSC is about 25% more expensive and has 0.5% higher electricity losses than LCC technology. 23 Review of Worldwide Experience of Voltage Source Convertor (VSC) High Voltage Direct Current Technology (HVDC) Installations, Sinclair Knight Merz, Sinclair Knight Merz (Europe) Limited, 2013, https://www.ofgem.gov.uk. Actual costs will vary depending on local conditions. Suppliers’ literature claims lower costs but this is not considered to b e sufficiently objective. 19 (coal, gas, nuclear, renewables). At the same time it would keep open the possibility of purchasing power from Ukraine and MGRES, which would increase competition; • No need for disconnection from Ukraine/MGRES. The asynchronous interconnection allows Moldova to still benefit from ancillary services provided by Ukraine and MGRES. Disconnection from these systems could lead to destabilization of the Moldovan system and would require substantial investment to prevent such events; • Shorter implementation period. Compared to synchronous interconnection, asynchronous interconnection could be completed in a much shorter period of time. Therefore, the benefits would be received much quicker as well. The main drawbacks of asynchronous interconnection are: (i) higher investment costs than for synchronous scenarios (but not as high as for the Self-Sufficiency scenarios); and (ii) Moldova could get the status of Observer at ENTSO-E but would not be eligible to become full member because its power system would remain part of the IPS/UPS. In practice, however, this would not be a significant drawback for Moldova. Details of the asynchronous scenarios are in Annex 6. 3.1.4 Scenario investment costs and 20-year levelized tariff levels The values for two major criteria (PV of investments and 20-year levelized tariffs) out of a total of seven criteria used in the ranking of the scenarios are shown in Table 3-1. The difference in the 20- year levelized tariffs (used only for ranking purposes) between the most expensive scenario (SS-1) and A-2 is US$ 1.2 cents/kWh. However, actual end-user tariffs for A-2 are estimated to be US$ 3.6 cents/kWh lower than for SS-1 in 2020. This difference between the two scenarios' actual tariff levels decreases gradually thereafter through 2033 as assets depreciate and the allowed return on net investments declines in importance (affecting SS-1 more because of its higher initial cost) while the combination of fuel costs (due to CHP-3) and costs of imports rises faster for A-2. The scenario ranking process and outcome using all criteria is discussed in section 3.2. Table 3-1: Investment costs and levelized tariffs by scenario (base case) Total Investments (US$ million) 20-year levelized tariffs, (US$ Scenarios Nominal PV* cents/kWh) SS-1 1,445 1,023 16.60 SS-2 1,005 700 16.31 S-1 410 285 15.01 S-2 383 266 14.96 S-3 348 242 14.94 S-4 463 322 15.07 A-1 709 491 15.45 A-2 715 495 15.43 A-3 728 504 15.48 * Using a 9% discount rate 20 3.2 Ranking of the Scenarios An Excel-based model using Multi-Criteria Decision Analysis (MCDA) was used to establish the ranking of the scenarios. The MCDA model consists of the following steps: (i) identify objectives and criteria including, notably, the PV of investment costs and resulting end-user tariffs; (ii) assess the expected performance of each option against the criteria (scoring); (iii) assign weights to each of the criteria to reflect their relative importance in the decision (weighting); (iv) combine the weights in a linear additive manner for each scenario to derive an overall value; (v) examine the results; and (vi) perform sensitivity analyses. The following criteria were taken into consideration for each scenario: (i) present value of investments made until 2033; (ii) levelized average tariff applied to final consumers until 2033; (iii) security of supply level; (iv) level of competition for cheapest electricity; (v) capacity to transit electricity between East and West leading to lower transport tariff; (vi) environmental impact; and (vii) operational difficulties associated with a given scenario. All these criteria are quantified and the numbers are calculated automatically by the model based on the input data. Scoring is also done automatically by the model, based on the actual values obtained for each scenario. Details of the model used are in Annex 3. A summary of the ranking of the scenarios, taking into account all seven criteria, is in Table 3-2. The highest possible score (100) is best and is assigned for the lowest value, and the lowest possible score (zero) is worst and is assigned for the lowest value (except for the Security of Supply (Criterion 3), which gets 100 and 0 points for highest and lowest values respectively.). A detailed explanation of the ranking process and sensitivity analysis is presented in Annex 4. Table 3-2: Ranking of scenarios based on MCDA (base case) Criteria and Scoring* Total Scenarios Ranking 1 2 3 4 5 6 7 score SS-1 0 0 13.2 0.0 1.9 0.0 11.0 26.11 9 SS-2 9.1 3.8 11.3 0.0 1.9 1.1 11.0 27.20 8 S-1 20.8 21.1 0.0 6.6 0.0 0.1 0.0 48.65 6 S-2 21.3 21.8 0.0 6.6 0.0 0.1 0.0 49.81 5 S-3 22.0 22.0 8.8 13.2 5.8 0.4 3.8 72.22 4 S-4 19.7 20.3 0.0 6.6 0.0 0.1 0.0 46.73 7 A-1 15.0 15.3 13.0 19.8 11.0 0.3 11.0 74.32 2 A-2 14.9 15.5 13.0 19.8 11.0 0.3 11.0 74.42 1 A-3 14.6 14.9 13.0 19.8 11.0 0.3 11.0 73.54 3 * Criteria: (i) PV of investment costs; (2) 20-year levelized tariff; (3) Security of supply; (4) competition for least-cost electricity; (5) capacity to transit electricity between East and West; (6) CO2 emissions factor; and (7) operational difficulty (disconnection of HVL). Scoring ranges from zero (worst) to 100 (best). The three Asynchronous scenarios are ranked 1 through 3, respectively, with A-2 top-ranked. However, as discussed in more detail in the subsequent sections, given the very small differences in ranking between the three alternative scenarios we recommend that they be studied simultaneously during the feasibility study phase in order to select the most appropriate one for implementation. 21 3.3 Asynchronous Interconnection Scenarios 3.3.1 Investment costs by Asynchronous scenario Excluding the generation investments in CHP-3 and RES-E that are constant for all scenarios, the total investment costs required for implementation of the Asynchronous-1 are estimated at US$421 million in current dollars. It would involve the construction of: • two BtB stations, one based on VSC and one based on LCC technology, at an estimated cost of US$303 million; • three 400 kV lines and one 330 kV line at an estimated cost of US$108 million; and • substation equipment at an estimated cost of US$11 million. The total investment costs required for the implementation of Asynchronous-2 (also for the interconnection part only) are estimated at US$427 million. This would involve the construction of: • two BtB stations based on LCC technology at an estimated cost of US$268 million; • three 400 kV lines and two 330 kV lines at an estimated cost of US$149 million; and • substation equipment at an estimated cost of US$10 million. The total investment costs required for the implementation of Asynchronous-3 (also for the interconnection part only) are estimated at US$441 million. This would involve the construction of: • two BtB stations, one based on VSC and one based on LCC technology, at an estimated cost of US$303 million; • three 400 kV lines and one 330 kV line at an estimated cost of US$126 million; and • substation equipment at an estimated cost of US$12 million. The above system components are needed for each alternative scenario to meet the n-1 criterion and to ensure having the 870 MW transmission capacity to/from Romania to satisfy Moldova’s power demand. Each component is described in detail in Annex 6. The total investment costs for A-1 are 3% and 4% lower than the total investment costs for A-2 and A-3, respectively. Table 3-3. Investment costs by asynchronous scenario (base-case; US$ million) Total Investments 2015 2016 2017 2018 2019 2020 2033 Nom PV 2014 Total 709 491 0 0 28.3 456.9 223.5 0 0 A-1 Generation 287 200 0 0 28.3 168.5 90.7 0 0 Total 715 495 0 0 28.3 461.1 225.4 0 0 A-2 Generation 287 200 0 0 28.3 168.5 90.7 0 0 Total 728 504 0 0 28.3 470.2 229.6 0 0 A-3 Generation 287 200 0 0 28.3 168.5 90.7 0 0 22 Under all three scenarios investments would peak in 2018 and be completed by 2020. That date was fixed in the model as the target completion date given the Government’s stated objective to interconnect with ENTSO-E by 2020. 3.3.2 Tariff levels by Asynchronous scenario Levelized average tariffs were calculated to determine the impact of the scenarios on consumers’ electricity bills, as affordability of energy services is an important issue in Moldova. The following timeframes were used for the end-user tariffs: (i) tariffs for each year to 2033; (ii) levelized tariffs for 10 years, starting with 2013; (iii) levelized tariffs for 20 years, starting with 2013; and (iv) the maximum tariff during 2020-2025, when investment costs fully impact the tariffs. Table 3-4. End-user tariff forecasts by asynchronous scenario (base-case). Levelized Levelized 2020-2025 2020-2025 Scenarios (US$ cents/kWh) (bani/kWh) maximum (US maximum 10 years 20 years 10 years 20 years cents/kWh) (bani/kWh) A-1 14.134 15.445 186.57 203.88 17.31 228.43 A-2 14.125 15.429 186.45 203.66 17.27 228.00 A-3 14.151 15.475 186.79 204.28 17.36 229.21 The tariff level for levelized 10 and 20-year tariffs is only up to 0.3% lower for A-2 than for A-3, and up to 0.6% lower for the maximum 2020 – 2025 tariffs. While this favors the A-2 scenario we consider that these differences are too small to recommend one scenario over the other. 3.3.3 Sensitivity analysis A sensitivity analysis was done to determine how variations in the main parameters would impact end-user tariffs for all the different scenarios, including the Self-Sufficiency, Synchronous and Asynchronous scenarios. The parameters examined are: (i) investment costs of CCGT and CPP; (ii) natural gas price; (iii) price of imported electricity; and (iv) investment costs of BtB stations. The impact of changes in these parameters was evaluated on levelized tariffs for a 20 year period. The detail of the sensitivity analysis is in Annex 4 and is summarized below: • A 25% decrease in CCGT and CPP investment costs leads to a 2.6% and 1.6% tariff decrease of SS-1 and SS-2. However, the tariffs of the SS scenarios would remain much higher than those of other scenarios; • Assuming that the annual gas price variations change from –0.89%/year to +1%/year would increase the tariffs of SS scenarios by 4.5 – 6.9% and those of other scenarios (Synchronous and Asynchronous) by around 3%. Thus, SS scenarios would become even less attractive; • Electricity import prices would have to rise to over US$9.65 cents/kWh in order for the SS tariffs to be equal to the tariffs of other scenarios (the 2014 import price was US$6.8 cents/kWh, so this would mean an increase of 42%). Synchronous and Asynchronous scenario tariffs would reach the same level if in the Asynchronous scenarios the import price would decrease by about US$1.0 cent/kWh as a result of wholesale competition in Romania; and • A 14% decrease in BtB station investment costs does not have much of an impact on tariffs, as they change only by about minus 0.36-0. 43%, depending on the scenario examined. 23 An additional sensitivity analysis was done to assess the impact on scenarios rankings of different electricity demand growth rates (i.e., 0, 5 and 7% per annum) and other economic variables and reducing the number and weighting of the criteria used in the MCDA, such as using only the PV of investment costs as a criterion. The additional sensitivity analyses confirmed the robustness of the Asynchronous scenarios, which rank highest in most cases, except if the PV of investments or PV of investments plus tariff levels are used as the only criteria. Using just those criteria would rank Asynchronous scenarios behind all Synchronous scenarios analyzed. However, considering the technical and other constraints on implementation of the Synchronous scenarios, Asynchronous remains the recommended option. 3.4 Conclusion of the Multi Criteria Decision Analysis Asynchronous scenarios rank highest. Given the criteria, their weighting and their scoring in the MCDA model, Asynchronous scenarios rank highest among all scenarios with scores of 73.5 or higher, with A-2 having the highest score (74.4). This compares to the best Synchronous interconnection scenario (72.2 for S-3, which, however, is not a realistic option) and the best Self- Sufficiency scenario (27.2). Asynchronous scenarios also rank consistently highest when doing sensitivity testing except when the only criterion considered is the PV of investment costs. Asynchronous scenarios can be fully operational by 2020. Not only will the investments have been completed but electricity can start flowing from Romania to Moldova. This is in sharp contrast to any of the synchronous scenarios, which would not be usable immediately after 2020 and possibly not until about 2030. Therefore, an Asynchronous scenario is the recommended interconnection option for Moldova. It would ensure greater energy security of supply and better prices for Moldova, as the imported electricity could be bought from East and/or West in a competitive manner. The investments required to implement the scenario are estimated to cost US$421-441 million and result in a 20-year levelized tariff of about US$ 15.5 cents/kWh, which is affordable. 3.5 Social and Environmental Aspects24 Gender issues. This analysis of electric power interconnection and market design options will not have gender-specific operational impacts on end-users of electricity at the household level. Therefore, no detailed gender analysis, actions and/or monitoring and evaluation indicators are required. Implementation of the proposed recommendations will benefit men and women equally, both in urban and rural areas. Climate Change aspects are addressed in the study as follows: (i) CO2 emission levels of different options is one of the criteria used for the ranking of the interconnection scenarios; and (ii) all scenarios analyzed assume that 150 MW of RES-E capacity will be built to help cover Moldova’s electricity demand and meet its EU commitments. 24 Note: Coverage of these aspects is a World Bank requirement 24 Stanca-Costesti 110 kV Kotovsc Suceava Ribnita UKRAINE Balti BtB capacity ca 3 x BtB units a Tutora - Ungheni 110 kV N-1 criteria is BtB capacity a 185 MW Iasi Straseni Needed new H 2 x 400 kV Suc Chisinau 1 x 330kV Balt 1 x 330kV Stra Cioara - Husi 110 kV 254 MW Total new HVL MGRES ROMANIA 2 x 400 kV Suc 2 x 400kV Iasi- Asynchronous 2 Isaccea 224 MW 400kV Vulcanesti 330kV 110kV new HVL х - disconnection Power absorbed from 330 - 400 kV grid Back-to-Back station (BtB) Stanca-Cosesti 110 kV Kotovsc Suceava Ribnita UKRAINE Balti Tutora - Ungheni 110 kV 185 MW Iasi Straseni Chisinau Cioara - Husi 110 kV 254 MW MGRES ROMANIA Asynchronous 3 (Gov) Isaccea 224 MW 400kV 330kV Vulcanesti 110kV new HVL х - disconnection Power absorbed from 330 - 400 kV grid Back-to-Back station (BtB) Figure 3-2. Alternative asynchronous scenarios25 25 A detailed representation of the Asynchronous scenarios is in Annex 6. 25 IV. Wholesale Market Design 4.1 Existing Market Arrangements Restructuring of the energy sector in Moldova started in 1997, when the vertically integrated electricity monopoly was unbundled into 5 distribution companies, a transmission system operator company and four generation companies. In 2000 Moldova privatized three of the five power distribution companies (about 70% of the distribution sector), which merged into RED Union Fenosa SA. RED Nord SA and RED Nord Vest SA remained state owned. Moldova’s grid losses and quality of service indicators improved significantly after that restructuring. 4.1.1 Producers and suppliers. There are six licensed producers in Moldova, as well as eight sup pliers at non-regulated tariffs (ENERGOCOM SA, a state owned enterprise managing imports from Ukraine and seven smaller suppliers, the market share of non-regulated tariffs being about 2% during 2010-12). The lion’s share of the market goes to three suppliers at regulated tariffs, which are the three distribution companies (RED Nord with a market share of 16.7% of consumption in 2012, RED Nord-Vest (8.7%) and RED Union Fenosa (71.1%). The accounts for supply and distribution of these companies are being separated while the legal unbundling required by the Electricity Law of 2009 has been postponed to January 1, 2015. An electricity supplier must be a legal entity that is registered in Moldova and fulfils the requirements of the Electricity Law. The three distribution companies act as default suppliers and are appointed as suppliers of last resort but this attribute is not yet defined in the market rules. Their responsibilities include providing balancing energy for their consumers, dispatching generation units connected to the distribution grids, purchasing energy to cover distribution grid losses, and maintaining, planning and developing the distribution grid. On the Left Bank all network and generation activities, other than MGRES26, are bundled. 4.1.2 No structural basis for a competitive market. Moldova’s wholesale market is currently split into two segments: fully regulated domestic generation and non-competitively procured supplies from Ukraine and MGRES. Both are discussed in Section Two of this report. Domestic generation is for 95% provided by CHPs that must operate base-load during the heating season and whose output must be bought at regulated prices. Being run of river, HPP Costesti cannot provide ancillary services to the system. Both Costesti and the CHPs operate in base-load, i.e., they have no balancing reserve for RES-E integration. Electricity from Ukraine is required for system balance and frequency control and (if adequate capacity is available) to help meet base-load demand. Purchases from MGRES make up the difference, including electricity needed to follow the load curve. Moldova’s small amount electricity consumption cannot provide enough incentives for private sector investment in generation under competitive bidding procedures. Building interconnections to the Energy Community is the primary way to solve Moldova’s current system weaknesses. 26 MGRES is owned by Inter RAO-UES 26 4.1.3 Most TSO roles are missing from legislation. The Electricity Law of 2009 appointed Moldelectrica to be the TSO for Moldova but de facto it can administer only the transmission assets on the Right Bank. Most of the roles of a TSO are still missing from both the Electricity Law and Moldelectrica’s license: ensuring ancillary services (reserve, load- frequency control and balancing energy) and dispatching of generation units connected to the transmission grid.27 Moldelectrica is required by primary legislation to ensure congestion management, system maintenance and planning/developing the transmission grid. The associated secondary legislation has to be developed or updated by ANRE. 4.1.4 Regulations on wholesale competition missing. Although Moldova’s Electricity Law states that the wholesale market is competitive, the regulations that should rule competition are mostly missing. The relationships between market participants are set by the Power Market Rules approved by ANRE and are based on bilateral contracts. According to the Law, the distribution companies (holders of licenses for distribution and power suppliers at regulated tariffs) have the right to sign bilateral contracts with any generation company or power supplier, including from abroad. However, their procurement of electricity is reduced to regulated contracts with domestic generators and acquisitions of imports. Any licensee has the right to non- discriminatory open access to transmission and/or distribution networks. Tariffs for transmission, distribution and regulated power supply are approved by ANRE based on its respective tariff methodologies. Electricity suppliers at regulated tariffs have exclusive rights to supply electricity to all non-eligible consumers within their authorized territory but not to the eligible customers there. 4.1.5 Wholesale import market is not competitive. Electricity demand in Moldova is met by two main supply sources: domestic power plants (25%) and imports from MGRES and Ukraine (75%). Although a generation license is granted to MGRES every 6 months, its participation in the market is of an import nature. While ANRE sets regulated prices for energy produced by domestic generators, which in the case of CHP depends largely on natural gas price variations, the two import sources coordinate their pricing which limits the power of domestic suppliers to bargain. Although all suppliers have the legal right to import and export energy, state- owned Energocom has a monopoly on imports from Ukraine, reportedly as required by the Ukrainians, while Union Fenosa deals with MGRES.28 Prices and volumes are decided during yearly negotiations. As a result, neither real competition nor a trading framework exist and market-based price references are totally missing. 4.1.6 Retail market to be fully opened in 2015. Moldova has had a 10% level of retail market opening since 2002 but needs to achieve 100% market opening by January 1, 2015 in order to meet the requirements of the EU’s energy Directive 2009/72/EC. The low level of market opening results from the fact that differentiated distribution and transmission tariffs have not yet been approved and a realistic assessment of the very limited possibilities for suppliers to compete while having regulated/fixed wholesale prices. The main retail market issue in the context of the Directive is removal of regulated prices. Regulated prices in the wholesale electricity market of Moldova cover only about 25% of procured electricity, i.e., domestic 27 Security of supply statements of the Republic of Moldova 28 It appears, however, that Energocom has also taken over that part of imports as imports from Ukraine have been shrinking. 27 generation. However, this is not a regulatory success but the result of the low share of domestic generation in meeting demand. 4.1.7 The current situation can be changed only in the medium-long term. The supply at regulated prices comes from inefficient CHPs whose operating regimes are driven by thermal load. Meanwhile, the share of electricity that is currently traded in the wholesale market at non-regulated prices (about 75%) comes from the MGRES – Ukraine duopoly, so even these non- regulated prices are not the result of competition. Clearly, competition will come only when Moldova gets an effective interconnection to ENTSO-E, i.e., by 2020. 4.2 Market Models 4.2.1 General principles. To achieve a competitive market framework, the following principles should apply: (i) if additional generation capacity is needed, such capacity should be obtained only under the authorization procedure29, in order to limit the size of the regulated market; and (ii) the remaining deficit in forecast peak load demand will be covered by a combination of imports plus additional domestic generation or by imports only. The latter is the preferred option. A properly functioning wholesale electricity market can offer: (i) efficient pricing mechanisms for energy over all applicable contractual time horizons, thus delivering a reliable price reference for investment decisions; (ii) rapid and safe settlement and payment of transactions, which attracts the interest of market participants and enhances market liquidity; and (iii) incentives to participants to limit their imbalances and mechanisms to involve them in system balancing, thus limiting the effect of any possible individual failures to deliver the agreed amount of energy at the appropriate time. 4.2.2 EU Target Market Model. The EU is in the process of elaborating a target market model. When adopted, this market model will also become mandatory for the EnC Contracting Parties, including Moldova. The main features of the target model are that it: • Is based on the zonal pricing model to eventually calculate cross border capacities in a flow- based manner, i.e. as required for actual energy flows; • Defines auction products to facilitate trading of electricity and cross-border capacity for different contractual time horizons; • Addresses the relationships between the TSOs, responsible for cross-border capacity allocation, and the Power Exchanges (PXs) which develop, organize and administer the day- ahead markets and their coupling; 29EU Directive 2009/72/EC requires member states to adopt a competitive authorization procedure for investment in new generation capacity, to be conducted in accordance with objective, transparent and non-discriminatory criteria. The investor would assume all market and price risks. The tender procedure can be used only when the security of supply is endangered because market conditions do not attract sufficient investor interest. Under the tender procedure investors would require long-term power sales/purchase agreements, thus reducing the competitive power market for the duration of the agreements by the amount of their generation covered by those agreements. 28 • Does not envisage regulatory intervention by setting price caps because price spikes may indicate either the need for investment or design flaws. Instead, financial hedging against price volatility will be necessary so complementary financial instruments will be required; and • May include a reserve capacity market to support investment in difficult investment climates due to decreasing prices in wholesale markets. However, this is issue still being debated. Target model implementation is aimed at barrier removal, thus providing a level playing field to all players, enabling cross-border trade enlargement and improving competition and price leveling. Also, such a large, harmonized, competitive market should be better able to attract investment. The instrument introduced by the EU’s Third Energy Package to provide harmonization is the Network Codes. The target model will have been successfully implemented if there are compatible electricity markets across Europe for all timeframes. 4.2.3 Competitive wholesale market criteria. If the conditions for real competition do exist – as required by the EnC – then that will ensure security of supply and greater affordability. However, a competitive legal framework may in itself not provide enough incentive for investment in generation under the authorization procedure. The absence of such investment hinders achievement of a market structure that enables effective competition, unless competitively priced electricity can be imported. To build a truly competitive wholesale market in Moldova means meeting the following criteria: • Ensuring an appropriate market structure (i.e., having enough sellers and buyers to enable competition on both the supply and demand side); • Adopting appropriate market rules for trading electricity as well as for procuring cross- border interconnector capacities over the various contractual time horizons; • Ensuring efficient balancing (i.e., provision of ancillary services by contracting reserves in a regulated and competitive manner and using such reserves through a reliable balancing mechanism). Curtailment rules are part of system balancing and those rules have to consider RES-E priority access and imbalance payment responsibilities); and • Strengthening existing institutions and creating appropriate additional institutions, including capacity building where appropriate. 4.2.4 Market design options For Moldova we examined three possible design options to ensure wholesale market competition (see Annex 7 for detail). For each of them the security and affordability they provide were analyzed. The three options are compatible with the EU Target Model and correspond to the three interconnection scenarios discussed in the system planning part of the Study: 1. A standalone competitive wholesale market. This corresponds to synchronous connection to ENTSO-E combined with system self-sufficiency. The share of electricity that would be subject to competition (but only in the long term) would to a large extent be produced inside the country. 29 2. A competitive wholesale market with appropriate rules for energy trading and cross-border capacity allocation. This is the option recommended by this Study as it corresponds to asynchronous interconnection with ENTSO-E while the interconnection with Ukraine and MGRES would also enable supplies from those two sources. Moldovan suppliers would be able to procure electricity from East or West, depending on price. For the most part competitively priced electricity would come from outside Moldova and its wholesale market. In particular, Moldova would benefit from the competitiveness of the Romanian market and the latter’s connection to the CEE markets following recent market coupling. 3. Merging with an already competitive wholesale market. This corresponds to synchronous interconnection to ENTSO-E without aiming for self-sufficiency. With the Moldovan market de facto merging with the Romanian market under this option, the electricity would be produced in this common market territory but not necessarily in Moldova. The three market design options and corresponding interconnection scenarios are summarized in Table 4-1 below. Table 4-1. Alternative supply scenarios and matching market design options Alternative Scenarios Market Design Options Self-Sufficiency scenarios: SS-1 A standalone competitive wholesale market* and SS-2 Synchronous scenarios: S-1, S-2, S- Merging with an already competitive wholesale market** 3, and S-4 Asynchronous scenarios: A-1, A-2 A competitive wholesale market with appropriate rules for and A-3 energy trading and cross-border capacity allocation – the recommended market design Note: * – This corresponds to synchronous connection to ENTSO-E combined with system self-sufficiency. ** – This corresponds to synchronous interconnection to ENTSO-E without aiming for self-sufficiency. 4.3 Recommended Market Design Option 4.3.1 Competition mostly outside Moldova Given this Study’s technical recommendation to proceed with asynchronous interconnection and the criteria for a competitive market structure as listed above, the “competitive wholesale market with appropriate rules for energy trading and cross-border capacity allocation� (Option 2 in section 4.2.4) is the most appropriate for Moldova. Once the asynchronous interconnection is in place a regulatory framework in compliance with EU/EnC rules would permit the competitive purchase of electricity from Romanian and CEE wholesale markets, transfer it to Moldova and sell it into the Moldovan market. At the same time, however, the asynchronous interconnection would enable Moldova to also import electricity from Ukraine (if available) and MGRES, thus further stimulating competition. The necessary legislative and regulatory changes required are discussed in Section 6.1.3 of this Study. Completion of the interconnection and undertaking the already required legal/regulatory measures would help achieve rapidly the desired increase in security of supply and possible downward pressure on end-user prices due to some degree of competition. Under this option wholesale competition would take place mostly outside Moldova. A detailed discussion of this market design follows below. 30 4.3.2 Market structure If the conditions for system self-sufficiency are not met, a functional standalone wholesale market cannot be built due to limited competition on the sell side even in the long term. Option 2 does not assume an appropriate market structure in terms of producers because the high cost of investment combined with low consumption discourages investment via the authorization procedure. The Government would use tendering for RES-E, rehabilitation, refurbishment, or replacement of CHPs, and gas turbines. Accordingly, the amount of electricity brought into the competitive wholesale market by domestic generation would be very limited as the regulator would continue to regulate prices and quantities of domestic generation30. However, even then organizing a competitive market that is highly dependent on power exchanges with more mature and liquid markets makes sense. To have competition on the sell side, thus making the existing competition rules in the Moldovan wholesale market effective, requires an electricity injection from the West. Coupling with the Romanian day-ahead market would mimic the submarine cable connection of Poland with Sweden that allowed coupling of Poland with NordPool. However, it will not necessarily improve domestic wholesale competition. This is so because the flows may correspond not only to traders’ activity but rather to the activity of domestic suppliers who take electricity from Romanian/EnC wholesale markets and move it directly into the Moldovan retail market. In that case the retail market in Moldova will increasingly be the main beneficiary of the competition in the Romanian/EnC wholesale market, thus gradually improving conditions for market opening. 4.3.3 Market rules In this case appropriate market rules can still be adopted by replacing domestic generators on the sell side, as envisaged under Option 1, with foreign/domestic traders who move electricity from abroad, either from the West (asynchronously) or from the East (synchronously). Of paramount importance is to ensure sufficient interconnection capacity with ENTSO-E where the electricity will come across the border. Although competition does not currently exist in the Ukrainian market and a monopolistic export situation may persist there despite EnC rules, from time to time an opportunity to buy cheap electricity from Ukraine may come up and compete with EnC sources of electricity. In case Option 2 is adopted the rules of cross-border capacity allocation should mix explicit and implicit allocations, reflecting the breakdown of available cross-border capacity as decided by the regulator. Even when only implicit allocation becomes the rule (for day-ahead trading), explicit allocation has to remain a fallback option. Adherence to the Coordinated Auction Office (CAO) in Montenegro would be desirable once Romania becomes a member, the CAO’s role not being limited only to coordinated explicit allocation but also to coordinated available capacity calculation. 4.3.4 Balancing Regarding balancing capacity, the obligation to develop 150 MW of RES-E remains, independent of the extent of new generation based on conventional sources (CHP-3 and GT). Under option 2 the balancing capacity of the domestic system would be much lower than in the case of a self-sufficient standalone market. However, the interconnection capacity with ENTSO-E as well as the quest for 30 There are three (non exclusive) alternatives for the electricity from rehabilitated CHPs to enter a competitive market: a) partly, if not all its generation capacity will be granted a purchase obligation at regulated tariff; b) entirely, if a cogeneration bonus scheme is in place; and c) entirely, after investment costs have been recovered. Without rehabilitation/refurbishment that generation will not be able to compete and regulated price and purchase obligations will have to be maintained. 31 tertiary reserves become much more important, while other reserves would continue to be acquired from Ukraine. 4.3.5 Institutions The reason for creating a market operator is to develop, organize and administer at least the day-ahead and centralized forward markets. In the case of asynchronous connection and a missing appropriate market structure on the sell side, the existing and potential suppliers acting as buyers will have the obligation to purchase electricity from domestic generators and the opportunity to buy electricity from the Ukrainian or EnC wholesale markets. The Moldovan centralized trading platform (if any) will not benefit from the direct presence of Romanian electricity producers as long as Romanian law does not allow the latter to sell electricity outside the centralized market in Romania. On the other hand the Romanian centralized markets are much more competitive and liquid due to the existence of numerous buyers and sellers, intense trading activity and the much larger volume. Whether setting up separate centralized platforms in Moldova can be successful is debatable. If a separate Moldovan market operator is not successful it will bring stranded costs and negative signals for market development. It would be better to negotiate the opening of a subsidiary of OPCOM in Chisinau. In that case, if domestic centralized platforms are not successful the stranded costs will be only administrative and would not be borne by Moldovan electricity consumers. 32 V. Overall Conclusions Asynchronous interconnection scenarios rank consistently highest in the multi-criteria decision analysis. Also because each one of these alternative scenarios can be comfortably implemented by 2020, this is the recommended interconnection option for Moldova. Given the very small differences in ranking between the three alternative scenarios we recommend that they be studied simultaneously during the feasibility study phase in order to select the most appropriate one for implementation. An asynchronous interconnection with two interconnection locations (see Figure 3-2, p. 27) would ensure greater energy security and better prices for Moldova as the electricity could be bought from East and/or West in a competitive manner. The investments required to implement the recommended scenario are estimated to range from US$421-441 million, depending on the asynchronous scenario selected following feasibility studies. Implementation would result in a 20-year levelized tariff of about US$ 15.5 cents/kWh, which is affordable and therefore acceptable. The proposed competitive wholesale market design, with appropriate rules for energy trading and cross-border capacity allocation, is recommended as the best option in the medium term (see Figure 4-2.). It would help achieve rapidly the desired increase in security of supply and exert possible downward pressure on end-user prices due to competition in part of the market, outside Moldova. Most of the necessary legislative, regulatory and institutional actions to implement this market structure (as well as the other options considered) are already mandatory under the EnC Treaty. They are also in compliance with the EU’s Internal Energy Market’s target model, which will become mandatory for EnC Members and Contracting Parties. MD TSO MD consumers RETAIL MARKET DISPATCHING • Contracts from UKR TSO Beneficiaries of Universal Service (under article 3 of IEM directive) primary and secondary • Procure electricity from SOLRs at regulated tariffs, set by MD regulator according to reserves / balancing. clearing price of joint auctions organized by RO PX subsidiary in MD. • Contracts from RO market Non-Beneficiaries of Universal Service tertiary reserves. • Procure competitively electricity from suppliers to end-consumers at negotiated prices Joint MD and RO TSOs MD suppliers to end-consumers CROSS-BORDER ALLOCATION MD & RO TSOS jointly set • Procure competitively electricity for their customers a) directly from EU/MD CAPACITY and operate cross-border traders, b) from RO PX markets c) from UKR if opportune, and at regulated capacity calculation and price from domestic generators (based purchase obligation) including RES-E allocation procedures, (through aggregator). compliant with ENTSO–E SOLRs WHOLESALE MARKET applicable rules. • Jointly procure competitively electricity for their customers using the joint auctions organized by RO PX subsidiary in MD exclusively for SOLRs. • Procure electricity for their customers from domestic generators (including RO PX ELECTRICITY COMPETITIVE RES-E through aggregator based purchase obligation) at regulated prices set RO Headquarter by MD regulator. FRAMEWORK OF • Provides framework for PROCUREMENT RO Market competitive operator procurement EU/MD traders by MD/RO traders • Procure competitively electricity from centralized markets organized by RO (including DAM coupling). PX in RO (or directly from other EU/MD traders in MD) and from UKR if RO PX subsidiary in Moldova opportune, and sell it to MD suppliers to end-consumers or in joint auctions • Provides joint auctions in organized by RO PX subsidiary in MD for SOLRs. MD for procurement by • Procure competitively cross-border capacities from auctions jointly MD SOLRs. organized by MD, RO TSOs to allow electricity transfer from RO to MD. Figure 4-2. The competitive wholesale market with appropriate rules for energy trading and cross-border capacity allocation 33 The recommended interconnection scenario31 and market design would help Moldova achieve more rapidly the desired increase in security of energy supply; possibly exert downward pressure on end- user prices due to wholesale competition for electricity obtained from outside Moldova; and lead to integration of its electric power sector into the Energy Community’s electricity market in the shortest period of time compared to other options. This recommendation is robust irrespective of changes in the internal or external environments, such as re-integration of the Left Bank (Transnistria) with the Right Bank and improved conditions in Ukraine. 31 I.e., one of the three asynchronous scenarios having two interconnection locations. 34 VI. Next Steps 6.1 Implementation of Recommendations The Government should undertake the actions listed below in order to implement the recommended asynchronous interconnection option and market structure. These actions would help Moldova to relatively rapidly interconnect with the EnC/EU’s energy market and improve its security of supply at an affordable price. 6.1.1 Attracting investments To ensure that there is adequate interconnection capacity to supply Moldova’s electricity demand, substantial investments are needed. On the generation side CHP-3 will need to replace existing CHP- 1 and CHP-2 and the investments made in this plant will be covered by a long-term power purchase/sale contract, i.e., the electricity produced by CHP-3 is regulated, not exposed to competition for the cheapest electricity on the market. Renewable sources also fall under the regulated regime. In other words, a tendering (rather than an authorization) procedure would be used by Moldova to attract investments in the construction of those regulated power plants. On the transmission grid side a tendering procedure would be used as well to build the necessary high voltage internal and interconnection lines, transformer stations and BtB stations. In this study a 9% rate of return on net investments was used. This value may be changed at the prefeasibility study stage to be done for each power system component that needs to be built. As soon as the power plants and grid transmission elements are built, investors would start recuperating their investments through both the price of electricity sold and the transmission tariff. Alternatively, the Government could borrow the funds needed to implement a scenario and organize the bidding for construction of power plants and transmission grid components. Repayment of the loans could be financed from a special margin included in the end-user tariffs. A gradual approach in implementing these investments is recommended to reduce the financial impact on end-user tariffs. Important investments need to be implemented to strengthen the domestic power transmission system. New high voltage transmission lines and substation equipment need to be built to allow full use of the interconnection and BtB stations as planned, as well as to ensure that the N-1 criterion is respected in order to enable a secure and reliable supply of electricity to the Moldovan consumers (see Section 3.3.1). SCADA completion. The Energy II Project funded by the World Bank allocated to Moldelectrica US$ 17.5 million to implement SCADA (Supervisory Control and Data Acquisition) and the system is now in operation. Thirty two Moldelectrica transmission stations, including four power plants, are presently covered by SCADA.32 In order to make the system fully operational, about 400 additional remote control units need to be installed at power stations and transformer substations during the next 4-5 years. This would require funding in the amount of US$9.2 million/year. 32 Source: Moldelectrica 35 6.1.2 Additional studies needed System Planning. A comprehensive planning study is needed to determine the required structure of the domestic power transmission system. This is necessary even without the interconnection option. It should show power generated, DC linkage capacity, power consumed, power traded in the country and in the region, and local and cross-border congestion. Feasibility studies. Feasibility studies will be required for each major domestic system component, which would also include the normal and transient regimes needed to determine the level of grid node voltages and the system’s static and dynamic stability. 6.1.3 Legislative/regulatory changes required Updates of the primary and secondary energy legislation are necessary to open up Moldova’s electricity market and to align Moldova with the requirements of the EU Electricity Directive and the Energy Acquis. Primary legislation changes would cover areas like: full market opening when actual conditions permit; TSO certification; RES-E responsibilities of the TSO in terms of system balancing; a monitoring system to ensure fulfillment of Moldova’s 2020 RES-E targets as per the NREAP; and compliance with provisions on conditions for access to the network for cross-border exchanges of electricity (in terms of transparency/reporting); and setting up a power exchange. Secondary legislation. The following regulatory requirements need to be clarified through appropriate rules: (i) Enabling market liberalization. • The 100% retail market opening that Moldova committed to by adhering to the EnC Treaty cannot become effective unless the necessary conditions are created for end-users to choose their electricity supplier. To enable that, an appropriate framework should be put in place in the wholesale market, which is currently lacking competition. Market rules have to be amended to enable the import of competitively procured electric power supplies from Romania. • If Energocom is to retain its monopoly role in contracting for imports from Ukraine (and potentially also from MGRES) it should be brought under ANRE’s supervision in order to ensure transparency of its market operations and related remuneration. (ii) Electricity trading for differentiated volumes and different term frames. • ANRE has to establish the rules enabling organized trading of electricity in Moldova for differentiated volumes and time frames, i.e., annual, monthly, daily, and hourly contracts. Such an organized market, even if not as liquid Romanian, will help suppliers to adjust their portfolios and reduce the risks associated with price differences in the wholesale and retail markets. • ANRE needs to provide the enabling framework for SOLRs to jointly procure electricity from the auctions organized by the future power exchange in Moldova (Section V, figure 4-2), or, from an established “single buyer� at equal price. 36 • Beneficiaries of universal service would procure electricity from SOLRs at tariffs set by the Moldovan regulator according to the clearing price of joint auctions organized by the power exchange in Moldova. Non-beneficiaries of universal service would procure electricity from suppliers at negotiated prices and thus be incentivized by better price offers. However, this is possible only if suppliers are provided by ANRE with the instruments necessary to manage risks associated with price differences in the wholesale and retail markets. (iii) System balancing/imbalances settlement and the long term system adequacy. • ANRE has to define appropriate rule for system balancing and the distribution of the cost of imbalances to participants generating those imbalances. Moldelectrica has to develop its responsibility and capacity to apply these rules. RES-E generators have to pay the cost of their imbalances and this should be clearly stated in the rules and it should be understood when tenders are organized. To ensure that it is not assumed that balancing is an additional cost to the cost of RES-E it has to be included in the tender price. • Moldelectrica’s responsibilities have to be clearly stated and enforced by the secondary legislation. When system planning indicates that Moldova’s domestic system is not able to provide balancing power, such balancing power (primary/secondary/tertiary) should be contracted for from the outside. • Moldelectrica’s responsibility for long-term system adequacy is defined in the Energy Law, but it is not enforced by regulations and therefore not fulfilled by the TSO. ANRE has to enforce Moldelectrica’s responsibility for annual long-term system planning but should also provide the latter with adequate resources to do so (see also Section 6.1.4). (iv) Curtailment rules. During normal system operation generation may have to be curtailed to balance the system. The succession and proportion of curtailed generation has to respect clear operational rules in order to avoid arbitrary and discriminatory decisions. RES-E priority access has to be respected, subject to system security. (v) Cross-border capacity allocation rules. Implementation of the provisions of EC Regulation 714 on conditions for access to the network for cross-border exchanges requires joint bidding by the two TSOs involved and full cross-border capacity allocation by one of the TSOs for each contract. The recent start-up of the Coordinated Auction Office in Montenegro, and introduction of the new IEM network codes, should improve the coordination of capacity allocation in the region. 6.1.4 Institutional capacity building/strengthening Capacity building/strengthening of existing institutions. To ensure successful implementation of a program that aims to introduce the selected wholesale market option, Moldova needs to develop the institutional capacities of the Ministry of Economy (MoE), Moldelectrica, and ANRE. • MoE. Develop MoE’s capacity to prepare amendments to primary legislation and to prepare the secondary legislation necessary for smooth functioning of the selected wholesale market design. MoE’s capacity to organize and coordinate the tenders for RES-E also needs to be developed. 37 • ANRE. Develop the capacity of ANRE to prepare regulations to implement the provisions of the Internal Energy Market’s network codes, including consultation with stakeholders, and to set up a direct relationship with the Agency for the Cooperation of Energy Regulators (ACER) as recommended by the Energy Community Regulatory Board (ECRB). • Moldelectrica. The transmission system planning task requires capacity building at Moldelectrica to perform and regularly update system planning based on changes in the demand for electricity and market signals. Although Moldelectrica is required by Law to do this on an annual basis, in practice this has not been done and the last system planning exercise was in 2007. Capacity development of new institutions. Successful implementation will also require establishing and developing capacity in several new institutions as follows: • The Moldovan Government should agree with OPCOM’s owner (the Romanian Government) that it will open a subsidiary in Chisinau. Whether setting up separate centralized platforms in Moldova can be successful is debatable. If a separate Moldovan market operator is not successful it will bring stranded costs and negative signals for market development. It would be better to negotiate the opening of a subsidiary of OPCOM in Chisinau. In that case, if domestic centralized platforms are not successful the stranded costs will be only administrative; • Establish an aggregator for RES-E generation and develop its capacity; and • Establish a single buyer for SOLR needs and develop its capacity. 6.1.5 Operational issues • The administration of the markets for energy (market operator) or for ancillary services, balancing and cross-border capacities (TSO), requires training and the existence of trading platforms. Those platforms can either be built from scratch or services could be procured from other operators if needed, as per the requirements of each option; • The process of introducing and successfully implementing a given wholesale market option is complex and requires the involvement of all relevant entities. It requires building institutional capacity, developing rules, acquiring logistics capacities, and proper coordination to ensure coherence; and • The task of process coordination should be entrusted to a market committee that includes representatives of the ministry of economy, regulator, transmission network operator, distribution network operator, market operator, generators, and suppliers. The committee should be co-chaired by representatives of MoE and of ANRE. 6.2 Requirements for Joining ENTSO-E The minimum requirements for joining ENTSO-E are stated in article 6 of its Articles of Association33. Article 6 states that the ENTSO-E Assembly may decide to admit new Members subject to the following minimum requirements: • the proposed Member is a legal person constituted under the laws of his country of origin; 33 ENTSO-E, Articles of Association, 2011 Edition. 38 • the proposed Member is designated as a TSO according to any Regulation or Directive in force concerning common rules for the IEM; • the TSO is solely responsible for frequency control (primary and secondary) and for maintaining the power interchange at the scheduled value within a given area ("Control Area") which is located within the European Union or in a country that has entered into an agreement with the European Union governing its relationship with the IEM; • the TSO shall belong to a country or Control Area relevant to the IEM in terms of market conditions and/or the physical reality of its transmission interconnections; • the TSO disposes of or has access to the financial means needed to fulfill the obligations which directly or indirectly arise from its membership of the Association; and • the TSO complies with the technical criteria and standards of the synchronous area to which it is or will be connected, in order to safeguard the stability and quality of operations of that synchronous area. The actions needed to fulfill the above requirements are described in Annex 8. 6.3 Coordination Concerted action from both Moldova and Romania is needed to realize the scenario chosen that would enable Moldova to join ENTSO-E. Assistance from the EU, the Energy Community, ENTSO-E and international donors would be highly desirable in this process. Nevertheless Moldova, as the most interested party, should play the lead role in bringing together and strengthening all the parties and institutions that will play a role in supporting this important undertaking. 39 Annex 1: Moldova in the Energy Community Member States and Contracting Parties. The Energy Community (EnC) combines the EU Member States, represented within regional institutions and forums by the European Commission (EC) and seven "Contracting Parties"34 who individually aim to adhere to the EU (see Figure A1-1). Romania, Bulgaria and Croatia, formerly Contracting Parties to the EnC, have become EU member states. The group of Contracting Parties is split into a Western and an Eastern area. This corresponds to a technical split: Moldova and Ukraine belong to the IPS/UPS synchronous system while the other Contracting Parties belong to the ENTSO-E synchronous system. EnC Energy Strategy35. The main objectives of the EnC’s Energy Strategy are: (i) creating a competitive, integrated regional energy market; (ii) providing a secure and sustainable energy supply to consumers; and (iii) attracting investments in energy. The second objective acknowledges that security of supply, despite many efforts to improve it, still remains a problem in the region. Figure A1-1. Moldova within the 8th region and the 8th region within the Internal Energy Market. Source: Energy Community Moldova signed the EnC Treaty on March 17, 2010. As a Contracting Party it is obliged to implement the Acquis of the Treaty, including its further amendments as adopted by EnC Ministerial Council decisions. Adherence to the EnC Treaty is laid down in Law 117 of December 23, 2009. The protocol of adherence, which is annexed to that Law, specifies the timetable for Acquis implementation, including the so-called Second Energy Package. At that time the Third Energy 34 Albania, Bosnia & Herzegovina, Kosovo, FYR Macedonia, Moldova, Serbia, and Ukraine 35 Energy Strategy of the Energy Community, Vienna, September 7, 2012 40 Package had been adopted by the EU but its adoption had not yet been recommended to the Contracting Parties by the EnC. Third Energy Package36. The decision to implement the Third Energy Package was adopted by the EnC in 2011, leading to amendment of the Treaty. The key issues for Moldova regarding Third Energy Package adoption are: (i) transposing and implementing provisions on reinforcement of the national energy regulator (ANRE) and the TSO (Moldelectrica) and their cooperation; and (ii) maintaining and improving provisions regarding protection of consumers as the market should become fully liberalized on January 1, 2015 and wholesale competition is introduced over time. Also by January 1, 2015, Moldova needs to adopt and implement the laws, regulations and administrative provisions in compliance with the Directives and Regulations, as adapted by EnC37. Renewable Energy. Adoption by the EnC of the EU’s Renewable Energy Directive (2009/28/EC) in 2011 brought the same obligations for the Contracting Parties of the EnC as for EU Member States in that field. They are obliged to reach an individual overall RES target as specified by the Directive, reach the same 10% biofuels target in the transport sector and prepare a National Renewable Energy Action Plan (NREAP). Countries whose share of RES falls below the indicative trajectory set by the Directive for the preceding two years are obliged to submit an updated Action Plan with the measures necessary to rejoin the indicative trajectory. When the EnC decided to implement the RE Directive, Moldova had already fixed its targets (20% RES and 10% RES-E) and a law supporting RES promotion had already been enacted in 2007. Annex 1 of the Directive actually reduced Moldova’s RES target to a 17% share of total energy consumption by 2020. However, in its NREAP Moldova retained the original 20% target. Any excess RES share over the mandatory 17% can eventually be sold to other countries that might need it to meet their EU commitments38. Moldova’s Performance on Acquis Implementation Paralysis after 2011. A 2011 ESMAP study on market opening gap analysis in the EnC39 used TSO unbundling, supplier unbundling, eligibility, balance, market concentration, transparency, and establishment of a day-ahead-market as evaluation criteria. It concluded that Moldova ranks somewhere between 2 – 6 out of 11 countries. However, most relevant primary legislation was adopted before Moldova joined the EnC, and most secondary legislation was adopted in 2011 and before. Instead, during 2012-13 the focus was on strategic and planning issues: the Energy Strategy to the year 2030, the National Energy Efficiency Action Plan (NEEAP) and the NREAP were all adopted in 2013. The main recommendations of the ESMAP report for closing the gaps addressed the TSO domain: (i) Moldelectrica to become a fully operational TSO with balancing responsibility for Moldova; (ii) improve the national balancing mechanism; (iii) make balancing responsibility mandatory for all wholesale market participants; and (iv) improve transparency. Legislation still pending. The 2013 Annual Implementation Report of the EnC notes that the Moldovan electricity law of 2009 is still in force while amendments prepared during 2011-2013, 36 The components of the Third Energy Package (2009) addressing electricity are: a new Internal Electricity Market Directive (2009/72/EC), the ACER Regulation (2009/713/EC) and the new Electricity Regulation (2009/714/EC). 37 Art. 11 of Directive 2009/72/EC and Directive 2009/73/EC 38 In addition to increasing RES generation themselves Contracting Parties can also use flexible instruments to meet their targets, like statistical transfers, participating in joint projects with other countries and setting up joint support schemes. 39 POYRY - Nord Pool Consulting, South East Europe wholesale Market Opening, Final report - updated with Ukraine and Moldova (December 2011) 41 mainly for transposition of Security of Electricity Supply Directive 2005/89/EC, Regulation EC 1228/2003 and improvement of compliance with Directive 2003/54/EC, are delayed. Balancing rules and the introduction of Balancing Responsible Parties are part of these proposed amendments to the Electricity Law. Several pieces of secondary legislation have also been prepared but adoption is still pending. As a result, implementation of existing primary legislation (notably the procedure for end- user switching) has been delayed. Delayed implementation of other rules (for allocation of interconnection capacities) has been caused by the delayed amendment of primary legislation. Although the methodology for setting distribution tariffs was adopted, new tariffs were not approved. This has blocked since 2009 effectiveness of the provisions of the Electricity Law regarding eligibility of non-household consumers, the effective eligibility being limited to consumers connected to high- voltage lines. The report also notes that end-user tariffs are cost-reflective with regard to the cost of energy imported, but that they don’t include a long-term investment cost component. The EnC Secretariat recommends that Moldova take the following measures to implement the Third Energy Package: • Implementation of the chosen alternative of TSO unbundling requires amendments to the Energy Law40. Also other provisions regarding TSO tasks and competencies41 (viz., ability of the system to meet reasonable demand, adequate means to meet service obligations, adequate transmission capacity and system reliability, managing electricity flows in the context of exchanges with interconnected systems, provision of required information to neighboring TSOs, collecting congestion rents, ensuring non-discrimination between system users and providing them information for efficient access, and confidentiality); • Full independence of ANRE requires full transposition of articles 37 and 38 of Directive 2009/72/EC; • Provisions with regard to vulnerable consumers need to be introduced; and • Moldelectrica has to introduce the required rules for capacity allocation and transparency. Regional Action Plan gaps. Beyond Moldova-specific gaps in Acquis implementation through 2013 there are issues pending for all Contracting Parties. A Regional Action Plan for market integration in South East Europe was adopted by the EnC in 2011, which set specific objectives and deadlines to reach by the beginning of 2014 regarding capacity calculation, forward markets/long-term capacity calculation, and day-ahead markets/market coupling. It is clear that the deadlines for these objectives will not be met because preliminary steps have not yet been implemented. Moldova is currently lagging behind in the formal implementation of the Acquis, notably insofar as primary and secondary legislation, regulations and implementation thereof is concerned. Significant efforts now need to be focused on catching up in this regard. At the same time, formally implementing the Acquis is necessary but not sufficient in order to achieve the goals of the EnC. A functional competitive market can only come about if Moldova is well integrated into the regional EnC market. To become truly part of the EnC and share in the security, competition and investment that this market attracts, Moldova must also invest in reliable electricity interconnections (for electricity exchanges) as well as in natural gas interconnections (since gas is the dominant fuel for domestic electricity generation) with the EnC. 40 Before an entity is approved and designated as transmission system operator, it shall be certified by the regulatory authority, which is obliged to follow the procedures described in article 10 of Directive 2009/72/EC. 41 Articles 12 and 15 of Directive 2009/72/EC. 42 Annex 2: Demand and Load Forecasts Electricity Demand Forecast The evolution of GDP (on a PPP basis), gross electricity demand (Edaf), electricity delivered to final consumers (Ef), and electricity consumed by households (Eh) is shown in Fig. A2-1. Electricity consumed by households was 45.7% of total power consumption in 2012. Figure A2-1. Evolution of GDP (on a PPP basis), gross electricity demand (Edaf), electricity delivered to final consumers (Ef), and electricity delivered to households (Eh) Source: GDP data A scatter chart was used to calculate the electricity demand forecast based on the 2001-13 GDP and Edaf data. The linear approximation function Edaf=f(GDP) is shown in Figure A2-2 and provides a reasonable approximation. The determination ratio expressed by R2 (R squared) is 0.78. Attempts to get a greater degree of approximation by applying exponential, logarithmic and polynomial functions have produced unacceptable outcomes for the years beyond 2013. The accuracy of the linear function for 2008–13 ranges between – 0.7% and +2.5%, which is considered acceptable. Figure A2-2. Edaf – GDP Approximation of Scatter chart 43 Fig. A2-3. GDP and Edaf evolution (the correlation ratio is 0.883). Using alternative annual demand growth rates of 0%, 2.1% (this Study’s forecast), 5% (the Government’s forecast) and 7% per annum, respectively, through 2033 yields the results shown in Figure A2-4 below. Clearly, the base-case growth rate used in this study produces a more realistic and sustainable growth in demand than the alternative growth rates. Figure A2-4. Electricity demand forecasts with alternative annual growth rates 44 Peak Load Forecast Typical load curves. Typical daily load curves in Moldova for all seasons show that in 2012 the highest peak load was in December at 759 MW. The lowest minimum load was in July, at 278 MW (see Figure A2-5). For statistical purposes these are calculated every Third Wednesday of each month. Figure A2-5. Summer and winter typical daily load curve in 2012 Source: Moldelectrica Maximum and minimum loads in 2012. Maximum and minimum loads for each month of 2012 are shown in Table A2-1. The maximum load was 831 MW on February 2, 2012 (Thursday) at 6 pm and the minimum load was 122 MW on April 17, 2012 (Tuesday) at 2 am. The absolute annual peak load in 2012 was 831 MW on February 2, 2012 (Thursday) at 6 pm and is the reference point for determining security of supply during 2014-2033 (see Figure A2-6). Table A2-1. Maximum and minimum loads recorded for each month in 2012 Max/Min/To Month 1 2 3 4 5 6 7 8 9 10 11 12 tal Maximum load, 800 831 715 635 642 581 596 751 624 709 794 813 831 MW Minimum load, 323 268 255 122 200 254 248 261 252 250 302 323 122 MW Total electricity 391 398 357 293 289 294 312 318 294 326 364 412 4,050 demand, mil. kWh Source: Moldelectrica 45 Figure A2-6. Load recorded by hour on February 2, 2012 (Thursday) Source: Moldelectrica 46 Annex 3: System Planning Model An Excel-based model was used to calculate the average electricity tariffs applied to the end-user consumers for each scenario and to rank the scenarios by means of Multi-Criteria Decision Analysis (MCDA). Transmission, distribution and supply tariffs were modeled based on the tariff methodologies in effect. Each type of power plant was modeled separately, since their electricity production prices depend upon their annual load factor, average capacity and other parameters. All other system components were simulated separately as well. The efficiency of power units was modeled as a linear function and was calculated based on the efficiency rates recorded at their minimal and nominal technical capacities. The investments were spread over the time period required for the construction of specific power plants and shaped as an S-curve. The electricity prices for RES-E are fixed and correspond to ANRE’s forecast bidding prices. The annual electricity produced was calculated based on RES-E capacity and on the electricity load factor generated during the year. The study only takes into account the transmission load flows under normal operating regimes. It does not take into account other technical parameters, such as bottlenecks, congestion, line impedance and/or thermal capacity in transitory operation. No contingency or overloading simulations were performed either. The rationale for using the Excel-based model is as follows: • The Energy Strategy and the Chisinau DH System Restructuring Plan determine most power plants’ types and capacities to be built in Moldova through 2030. All the electricity produced by these power plants must be purchased by suppliers and at prices based on long-term contracts: CHP-3 and CHP - Nord due to their district heat production; RES-E due to feed-in tariffs applied; Costesti HPP due to its very low price (hydro power). Even the CCGT and CPP planned in the Self-Sufficiency scenarios would need to sell their electricity based on long-term contracts, because of the lower electricity import prices from the East and the lack of a competitive market in Moldova; • WASP cannot simulate RES-E, which would reach a 150 MW installed capacity by 2020; • WASP cannot take transmission grid development into consideration, including interconnections with Romania and construction of BtB stations. In our study seven of the major scenarios involve primarily grid development; • It is very difficult to simulate in WASP electricity imports and electricity price variation; and • The Excel model can considerably speed up calculations, when testing introduction of power transmission system components other than power plants. The above shows that there is little or no advantage to using a conventional model such as WASP for this study, as WASP was developed to determine the least-cost scenario from multiple combinations of power unit candidates, which are very limited in Moldova’s case. Even if WASP were to choose the units other than the 700 MW CCGT unit in S-2, the results will not differ much from the results obtained by our Excel model. This is so because in the absence of fuels other than gas the best solution selected will be the same – CCGT – though maybe with a different capacity and year of construction. But that will not change the fact that the Self-Sufficiency Scenarios are the most expensive ones compared to all other scenarios examined. In Self-Sufficiency-1 the share of total capacity of each power plant is determined by the goal of fuel diversification (coal and gas), not by which type of plant 47 is economically more advantageous. In other words, the capacity of CCGT and CPP are predetermined and fixed in that scenario. Multi-Criteria Decision Analysis The model uses Multi-Criteria Decision Analysis to establish the ranking of the scenarios. MCDA consists of the following steps: (i) identify objectives and criteria including, notably, the PV of investment costs and resulting end-user tariffs; (ii) assess the expected performance of each scenario against the criteria (scoring); (iii) assign weights to each of the criteria to reflect their relative importance in the decision (weighting); (iv) combine the weights in a linear additive manner for each scenario to derive an overall value; (v) examine the results; and (vi) perform sensitivity analyses. The following criteria were taken into consideration for each scenario: (i) net present value of investments made until 2033; (ii) levelized average tariff applied to final consumers until 2033; (iii) security of supply level; (iv) level of competition for cheapest electricity; (v) capacity to transit electricity between East and West leading to lower transport tariff; (vi) environmental impact; and (vii) operational difficulty associated with a given scenario. All these criteria are quantified and the numbers are calculated automatically by the model based on the input data. Scoring is also done automatically by the model, based on the actual values obtained for each scenario. The criteria were defined as follows: 1. The PV of investments was calculated using a 9% discount rate; 2. Levelized tariffs were calculated for 10-year and 20-year periods both starting in 2013 and for the period 2020-2025 when tariffs will be at their maximum levels as the full impact of the investment costs will be reflected in the tariffs; 3. Security of supply level is defined by using Simpson's Index of Diversity42. The higher that index is for a concrete scenario, the higher the security of supply level offered by that scenario; 4. Level of competition is measured by the number of supply sources for a given scenario. The more electric power sources can compete to cover Moldova’s demand the lower the price of energy delivered would normally be. The expected level of competition is assumed to increase with the number of suppliers. The numbers are 0 for the SS scenarios, 1 for most Synchronous scenarios (except S-3 which has 2: Romania and MGRES), and 3 for the Asynchronous scenarios (Romania, Ukraine and MGRES); 5. Capacity to transit between East and West: All Asynchronous Scenarios can transit electricity from East to West with a maximum peak load of 870 MW. From the East two suppliers can use this opportunity: Ukraine and MGRES. Among Synchronous Scenarios only S-3 has this capacity and only MGRES could be a transit supplier. Under Self-Sufficiency Scenarios transit capacity is limited to 220 MW and may be realized on the island principle, as done by MGRES during the last few years; 6. Environmental impact: based on GHG emissions calculations for each scenario (tonnes of CO2 emitted through 2033); and 7. Operational difficulty: the number of interconnection lines to be disconnected, by scenario 42 http://www.countrysideinfo.co.uk/simpsons.htm 48 Annex 4. Scenario Ranking and Sensitivity Analysis43 Scenario ranking Scenario ranking consists of three major steps: Step 1 (Table A4-1): The values of the initial criteria selected for the MCDA are calculated by the Excel model based on quantified input data. The resulting basic data are listed in columns 1-7 of Table A4-1. The numbers are determined also automatically by the model based on the input data and cannot be changed unless the input data are changed, e.g., if the value of a specific investment cost needs to be revised. Step 2 (Table A4-2): The weighting for each criterion by scenario is calculated as follows: • The highest value is assigned 0 points and the lowest value is assigned 100 points, except for the Security of Supply (Criterion 3), which gets 100 and 0 points for highest and lowest values respectively. For example, the PV of the investments cost for SS-1 (US$1,023 million – the highest) gets 0 points, and PV for S-3 (US$242 million – the lowest) gets 100 points. • Values in the remaining cells are calculated automatically by the model based on the following formula: (highest investment cost of all scenarios – specific investment of a given scenario)/(highest investment cost of all scenarios – lowest investment cost of all scenarios). For example, the weighting for the PV of the investment cost for A-2 is calculated as: 1,023 (highest) – 511 (A-2) / 1,023 (highest) – 242 (lowest) = 512/781 = 0.66. Thus, the PV of the investment cost weighting for A-2 is calculated as 66 points. • The importance of each criterion (to be assigned by stakeholders if changes are desired) is shown in the cells marked in yellow44. A score of 100 indicates the highest level of importance, zero the lowest. Following this rule, values are fixed for each criterion as shown in Table A4-2, here totaling a score of 455 (100 + 100 + 60 + 90 + 50 + 5 + 50). • The weighting ratios for each criterion are calculated by dividing the stakeholders’ individual criteria weighting score (the row marked in yellow) by 455 (the total score). For example, for the “PV of Investments� for A-2 it would be 100/455 = 0.22 (cells marked in blue). The weighting ratios will then be used to calculate the score of each criterion by scenario under Step 3. Step 3 (Table A4-3): The final ranking is calculated at this stage. Based on the numbers in Table A4-2, the weighting ratio for each criterion is multiplied by their weighting under each scenario to get the respective scoring of each criterion by scenario in the same cell in Table A4-3. For example, the 14.4 for the “PV of investments� under scenario A-2 is determined by multiplying the weighting 66, located in the same cell but in Table A4-2 by the weighting ratio of 0.22 for that criterion in the bottom cell. Then, the total score for each scenario (column 8 of Table A4-3) is the sum of the calculated individual criterion scores for each scenario. In the ‘Ranking’ column (column 9 of Table A4-3) the highest ranking is number 1, the lowest is number 8, as there are eight scenarios considered. Asynchronous 2 has the highest score. Given the criteria, their weighting and their scoring in this study’s MCDA model, Asynchronous-2 ranks number 1 among the scenarios with a score of 74.4. 43 This sensitivity analysis was performed prior to the May 2015 Workshop on this Study and does not include the A-3 scenario that was included in the main text following the feedback received during the Workshop. However, this does not affect the overall validity of the analysis. 44 Values for each criterion are assigned based on perceived level of importance. A subsequent sensitivity analysis demonstrated that changing the weightings does not change the ranking of the scenarios. 49 Table A4-1. Step 1: Basic data for criteria calculation Operational Level of Capacity to CO2 difficulty PV of 20-year Security of competition transit emissions (number of Investments levelized supply (number of electricity Scenarios 2020-2033 35-400 kV (million tariff (US$ (Simpson main supply between (million lines to be US$) cents/kWh) index) interconnect East&West, tons) disconnected ions) MW ) 1 2 3 4 5 6 7 SS-1, CCGT + CPP, connection to 1,023 16.60 0.718 0 220 30.6 0 ENTSO-E after 2033 SS-2, CCGT, no CPP, connection to 700 16.31 0.667 0 220 18.6 0 ENTSO-E after 2033 S-1, Suceava - Balti, Vulcanesti - 285 15.01 0.364 1 0 29.2 23 Chisinau S-2, Suceava - Balti, Stefan - Voda - 266 14.96 0.364 1 0 29.2 23 Ursoaia S-3,Suceava - Balti, MGRES 242 14.94 0.601 2 660 25.7 15 S-4, Isaccia - Vulcanesti, Vulcanesti - 322 15.07 0.364 1 0 29.2 23 Chisinau 2 x 400 kV A-1, 2 x BtB: one LCC at Straseni and one VSC at Vulcanesti, 2 x 400 kV 529 15.58 0.713 3 1,250 27.8 0 Vulcanesti-Chisinau A-2, 2xBtB at Balti and Straseni 511 15.46 0.713 3 1,250 27.8 0 50 Table A4-2. Step 2: Criteria weighting Capacity to Competition for transit PV of 20-year Security of Operational Scenarios least-cost electricity CO2 emissions Investments levelized tariff supply difficulty electricity between East&West 1 2 3 4 5 6 7 SS-1 0 0 100 0 25.3 0 100.0 SS-2 41 17 85.4 0 25.3 100 100.0 S-1 95 96 0.0 33.3 0.0 11.64 0.0 S-2 97 99 0.0 33.3 0.0 11.64 0.0 S-3 100 100 67.0 66.7 100.0 40.36 34.8 S-4 90 92 0.0 33.3 0.0 11.64 0 A-1 63 62 98.6 100.0 100.0 23.46 100 A-2 66 69 98.6 100.0 100.0 23.46 100 100 100 60 90 50 5 50 Criteria weighting 0.22 0.22 0.132 0.198 0.110 0.011 0.110 • The highest value is assigned 0 points and the lowest value is assigned 100 points, except for the Security of Supply, Criterion 3, which gets 100 and 0 points for highest and lowest values respectively. For example, the PV of investments for SS-1 (US$1,023 million – the highest) gets 0 points, and the PV for S-3 (US$242 million – the lowest) gets 100 points. Values in the remaining cells are calculated automatically by the model based on the following formula: (highest investment cost of all scenarios – specific investment of a given scenario) / (highest investment cost of all scenarios – lowest investment cost of all scenarios). For example, the weighting for the PV of the investment cost for A-2 is calculated as: 1,023 (highest) – 511 (A-2) / 1,023 (highest) – 242 (lowest) = 512/781 = 0.66. Thus, the PV of the investment cost weighting for A-2 is calculated as 66 points. • The importance of each criterion (to be assigned by stakeholders if changes are desired) is shown in the cells marked in yellow. A score of 100 indicates the highest level of importance, zero the lowest. Following this rule, values are fixed for each criterion as shown in Table A4-2, here totaling a score of 455 (100 + 100 + 60 + 90 + 50 + 5 + 50). • The weighting ratios for each criterion are calculated by dividing the stakeholders’ individual criteria weighting score (the row marked in yellow) by 455 (the total score). For example, for the “PV of Investments� for A-2 it would be 100/455 = 0.22 (cells marked in blue). The weighting ratios will then be used to calculate the score of each criterion by scenario. 51 Table A4-3. Step 3: Final ranking calculation based on criteria scoring Capacity to 20-year Competition transit PV of Security of CO2 Operational Total Scenarios levelized for least-cost electricity Ranking Investments supply emissions dificulty score tariff electricity between East&West 1 2 3 4 5 6 7 8 9 SS-1 0.0 0.0 13.2 0.0 1.9 0 11.0 26.1 8 SS-2 9.1 3.8 11.3 0.0 1.9 1.1 11.0 27.2 7 S-1 20.8 21.1 0.0 6.6 0.0 0.1 0.0 48.6 5 S-2 21.3 21.8 0.0 6.6 0.0 0.1 0.0 49.8 4 S-3 22.0 22.0 8.8 13.2 5.8 0.4 3.8 72.2 2 S-4 19.7 20.3 0.0 6.6 0.0 0.1 0.0 46.7 6 A-1 13.9 13.6 13.0 19.8 11.0 0.3 11.0 71.5 3 A-2 14.4 15.1 13.0 19.8 11.0 0.3 11.0 73.6 1 • Based on the numbers in Table A4-2, the weighting ratio for each criterion is multiplied by their weighting under each scenario to get the respective scoring of each criterion by scenario in the same cell in Table A4-3. For example, the 14.4 for the “PV of investments� under scenario A-2 is determined by multiplying the weighting 66, located in the same cell but in Table A4-2 by the weighting ratio of 0.22 for that criterion in the bottom cell. The total score for each scenario (column 8 of Table A4-3) is the sum of the calculated individual criterion scores for each scenario. In the ‘Ranking’ column (column 9 of Table A4-3) the highest ranking is number 1, the lowest is number 8, as there are eight scenarios considered. 52 Tariff Sensitivity Analysis A sensitivity analysis was done to determine how variations in the main parameters would impact end-user tariffs in the different scenarios. The parameters examined are: (i) investment costs of CCGT and CPP; (ii) natural gas price; (iii) price of imported electricity; and (iv) investment costs of BtB stations. The impact of changes in these parameters was evaluated for the levelized tariffs over a 20 year period. Investment Costs of CCGT and CPP Investments costs in CCGT and CPP vary significantly by scenario. The numbers used in our calculation (base case) are based on IEA data45. We examined whether a 25% reduction in the investment costs for CCGT and CPP could equalize the tariff levels of the Self-Sufficiency scenarios with those of the Asynchronous scenarios (US$750/kW for CCGT and US$1,575/kW for CPP). The analysis shows that a 25% reduction in the cost of investments produces a 2.6% and 1.6% tariff decrease for SS-1 and SS-2, respectively, which is minor (Table A4-4). Table A4-4. Impact of the reduced cost of investments on the tariff level difference between Self-Sufficiency and Asynchronous scenarios 20-year levelized tariff (US$ cents/kW) Scenarios Tariff decrease, % Base case 25% reduction SS-1 16.60 16.20 2.5 SS-2 16.30 16.10 1.6 A-1 15.58 15.58 A-2 15.46 15.46 Natural Gas Price A reduction of 0.89%/year in natural gas prices was used as base-case when calculating the levelized 20-year tariff for each scenario46. However, given the volatility of gas prices two additional calculations were made: a 1 %/year increase and a 3 %/year increase. The analysis shows that the change in annual gas price variations from –0.89%/year to +1%/year would increase the tariffs of Self-Sufficiency scenarios by 4.5 – 6.9% and those of other scenarios (Synchronous and Asynchronous) by around 3%. At increases greater than 1%/year the gap would become even more pronounced. Table A4-5. Impact of increases in gas price Levelized 20 year tariffs (US$ cts/kWh) Scenarios Base case 1%/year increase in gas price 3%/year increase in gas price SS-1 16.6 17.3 18.3 SS-2 16.3 17.4 19.0 SyS-1 15.0 15.5 16.1 SyS-2 15.0 15.4 16.0 SyS-3 14.9 15.4 16.0 SyS-4 15.5 16.0 16.6 A-1 15.6 16.0 16.6 A-2 15.5 15.9 16.5 45 http://iea-etsap.org 46 Sources: WB Commodity Price Forecast (January 15, 2013). 53 Electricity Import Price A sensitivity analysis on the electricity import price was done to determine the break-even point for domestic generation compared to imports for the 20-year levelized tariffs. Scenarios were combined for that purpose as shown in Table A4-6. The analysis shows that electricity import prices would have to increase by US$9.65 cents/kWh for the Self-Sufficiency tariffs to equal the other scenarios. The 2014 import price is US$6.8 cents/kWh. Synchronous and Asynchronous would break even if the import price for the Asynchronous scenarios would decrease by about US$1.0 cent/kWh. Table A4-6. Impact of increase in electricity import price Combination of Scenarios SS-1/A-2 SS-2/A-2 A-2/S-4 A-2/S-3 2020 import price (base-case) US$ cents/kWh 6.5 2020 break-even import price US$ cents/kWh 9.65 8.85 5.06 5.43 US$ cents/kWh 3.15 2.35 -1.44 -1.07 Price increase % 48 36 -22 -16 Investment Cost of BtB Stations The estimated investment cost of BtB stations varies considerably among different sources. The Energy Strategy estimates the cost of BtB station at US$180/kW. However, the cost of the Lithuania – Poland BtB47 station currently under construction is about US$220/kW. The estimated cost of a BtB station in Georgia48 (now under construction) having the same capacity as the BtB stations in this study is US$257/kW. We used this unit cost to calculate the cost of the BtB stations proposed under A-1 and A-2 (base case), and compared it with the cost of Lithuania – Poland BtB, which is 14% lower. A 14% reduction in investment cost does not have a significant impact on tariffs, which would change by only 0.43% and 0.36% for A-1 and A-2 respectively (see Table A4-7). Table A4-7. Impact of lower investment cost for BtBs Levelized 20 year tariffs (US$ cents/kWh) Tariff decrease (%) Scenarios US$ 257/kW US$ 220/kW SS-1 16.60 16.60 SS-2 16.31 16.31 SyS-1 15.01 15.01 SyS-2 14.96 14.96 SyS-3 14.94 14.94 SyS-4 15.07 15.07 A-1 15.58 15.51 0.43 A-2 15.46 15.40 0.36 47 http://new.abb.com/systems/hvdc/references/litpol-link 48http://www.siemens.com/press/en/pressrelease/?press=/en/pressrelease/2010/power_transmission/ept201008116.htm 54 Additional sensitivity analyses Additional sensitivity analyses were carried out to assess the impact of different electricity demand growth rates and other economic variables and reducing the number and weighting of the criteria used in the MCDA. The main goal was to test the robustness of the proposed optimal scenario rankings. The additional sensitivity analyses determined the impact of the following on the scenario rankings: 1. Different demand growth scenarios around the base-case (“medium�) used in the MCDA with the existing criteria and weightings; 2. Additional increases in the price of imported electricity; 3. Higher annual increases in the price of natural gas than those used in the base case; 4. Using only the PV of investment costs as a ranking criterion; 5. Using the PV of investments and the resulting end-user tariffs (capex and opex included), weighted 40 and 60 respectively; 6. Finally, the break-even point for domestic generation compared to imports was determined for the synchronous and asynchronous scenarios. The following input data were used for the analyses: • Annual electricity demand growth: 0%; 2.1% (base-case); 5%; and 7%. • Annual gas price increase: 0.89% (base case); 1%; 3%; and 10%. • Annual electricity import price increase: 1% (base-case); 3%; 5%; and 10%. • Annual increase in cost of investments: 0% (base-case); 5%; 10%; and 20%. The results of the additional sensitivity analyses were the following: 1) Impact of different demand growth scenarios. a) All scenarios retain essentially the same rankings with a few minor changes. A-2 keeps its first position, while S-3 ranks fourth except for 0%/year demand growth, when it becomes third. 2) Impact of additional increases in the electricity import price. a) Regardless of demand growth, A-2 keeps its top ranking when the import price increases by up to 10%/year. b) Self-Sufficiency scenarios rank higher with a higher increase in the price of imported electricity, but not higher than middle rankings. 3) Impact of higher annual increases in the gas price. a) Higher gas prices do not affect the asynchronous and synchronous scenarios ranking. 4) Ranking based solely on the PV of investments. a) Higher investment costs place A-2 behind the synchronous scenarios. The A-2 scenario would rank fifth. However, given the constraints of the synchronous scenarios, A-2 keeps its de facto lead position. 5) Ranking based on the PV of investments and the resulting end-user tariff (capex and opex included). 55 a) Higher investment costs and hence increased tariffs place A-2 behind the synchronous scenarios. However, given the constraints of synchronous scenarios A-2 keeps its de facto lead position. 6) Break-even (optimal) point for domestic generation compared to imports. a) Self-Sufficiency scenarios break even compared to imports when the increase in the price of imported electricity varies between 3.25% and 6.46%/year, depending on the assumed electricity demand growth rate. b) The end-user tariff break-even point is reached when the 20 years levelized tariffs vary between US$ 7.73 cents/kWh and US$ 11.29 cents/kWh. c) A-2 breaks-even with SS-1 at a levelized import price of US$8.76 cents/kWh for a 2.1% annual demand growth (base-case) and US$9.8 cents/kWh at an annual demand growth rate of 5%. Conclusions The additional sensitivity analyses confirmed the robustness of the Asynchronous 2 scenario. Different demand growth scenarios using the seven criteria MCDA as per the main report have little or no impact on scenario ranking, as shown in Table A4-8 below. MCDA shows greater consistency in the ranking of the scenarios when more than one or two criteria are considered. The A-2 scenario ranks highest in most of the alternative sensitivity analyses that were run, except if the PV of investments or PV of investments plus tariffs are used as sole criteria. Using these criteria would rank A-2 behind all Synchronous scenarios analyzed. However, considering the constraints of the Synchronous scenarios, A-2 remains the recommended option. Table A4-8. Impact of different demand growth rates on scenario ranking Average annual electricity demand growth Scenarios 0% 2.1% (base-line) 5% 7% SS-1 8 8 8 7 SS-2 7 7 7 8 S-1 6 5 5 5 S-2 4 4 4 4 S-3 2 3 3 3 S-4 7 6 6 6 A-1 3 2 2 2 A-2 1 1 1 1 56 Annex 5: Alternative Scenarios: Self-Sufficiency and Synchronous Interconnection Self-Sufficiency Scenarios The Self-Sufficiency Scenarios assume the construction of power capacities in Moldova sufficient to satisfy its future load demand. Electricity imports, including from MGRES, are not planned or would be insignificant. As soon as the self-sufficiency target is reached, Moldova would be capable of being solely responsible for frequency control (primary and secondary), which is the main technical requirement for joining ENTSO-E49. Moldova can rely on only two main types of fuel to produce electricity: natural gas and coal. The target being to reach self-sufficiency by 2020, power plants firing one or more of those fuels should have been built by then. The first Self-Sufficiency scenario (SS-1) assumes the use of both types of fuels leading to diversification of imported fuels, thus somewhat increasing the country’s energy security. The second Self-Sufficiency scenario (SS-2) is based exclusively on natural gas utilization and would actually decrease energy security, assuming the supplier is Gazprom. The evolution of Moldova’s power generation capacities for these scenarios through 2033 is shown in Tables A5-1 and A5-3 respectively. The electricity they produce during the same time period is shown in Tables A5-2 and A5-4. Table A5-1. Self-Sufficiency 1 (SS-1): Right Bank available capacity development, MW 2013 2014 2019 2020 2021 2025 2030 2033 Forecasted available capacity needed 833 849 911 925 939 999 1,085 1,143 HPP 0 0 0 0 0 0 0 0 CHP-1 27 25 25 0 0 0 0 0 CHP-2 162 202 202 0 0 0 0 0 CHP-3 0 0 0 250 250 250 250 250 CHP-Nord 20 20 20 20 20 20 20 20 CCPP 0 0 0 300 300 300 300 300 CPP 0 0 0 400 400 400 400 400 RES 0 0 0 3 3 3 3 3 TOTAL Local available capacity 209 247 247 973 973 973 973 973 Import 624 602 664 -48 -34 26 112 170 49 Article 6 of “Articles of Association�. 2011 Edition, 28.06.2011. ENTSO-E 57 Table A5-2. Self-Sufficiency 1 (SS-1): Right Bank electricity demand balancing, million kWh 2013 2014 2019 2020 2021 2025 2030 2033 Total electricity delivered at DAF, Edaf 4,072 4,170 4,584 4,675 4,769 5,177 5,766 6,168 HPP 70 70 70 70 70 70 70 70 CHP-1 50 50 50 0 0 0 0 0 CHP-2 701 701 710 0 0 0 0 0 CHP-3 0 0 0 1,625 1,625 1,625 1,625 1,625 CHP-Nord 48 48 44 44 44 44 44 44 CCPP 0 0 0 1,083 1,123 1,289 1,505 1,652 CPP 0 0 0 1,444 1,498 1,719 2,006 2,203 RES 0 5 282 405 405 406 406 406 Other (Elteprod+Sugar CHP) 4 4 4 4 4 4 4 4 TOTAL Local PPs 873 879 1,160 4,675 4,769 5,157 5,660 6,003 Tm of electricity imported, h 5,699 5,689 5,389 0 0 1,000 1,000 1,000 Import, mil kWh 3,199 3,291 3,424 0 0 20 107 165 Import, % from Demand 79 79 75 0 0 0.4 1.8 2.7 Table A5-3. Self-Sufficiency 2 (SS-2): Right Bank available capacity development, MW 2013 2014 2019 2020 2021 2025 2030 2033 Forecasted available capacity needed 833 849 911 925 939 999 1,085 1,143 HPP 0 0 0 0 0 0 0 0 CHP-1 27 25 25 0 0 0 0 0 CHP-2 162 202 202 0 0 0 0 0 CHP-3 0 0 0 250 250 250 250 250 CHP-Nord 20 20 20 20 20 20 20 20 CCPP 0 0 0 700 700 700 700 700 CPP 0 0 0 0 0 0 0 0 RES 0 0 0 3 3 3 3 3 TOTAL Local available capacity 209 247 247 973 973 973 973 973 Import 624 602 664 -48 -34 26 112 170 Table A5-4. Self-Sufficiency 2 (SS-2): Right Bank electricity demand balancing, million kWh 2013 2014 2019 2020 2021 2025 2030 2033 Total electricity delivered at DAF, Edaf 4,072 4,170 4,584 4,675 4,769 5,177 5,766 6,168 HPP 70 70 70 70 70 70 70 70 CHP-1 50 50 50 0 0 0 0 0 CHP-2 veche 701 701 710 0 0 0 0 0 CHP-2 noua (CHP-3) 0 0 0 1,625 1,625 1,625 1,625 1,625 CHP-Nord 48 48 44 44 44 44 44 44 CCPP 0 0 0 2,527 2,621 3,008 3,511 3,854 CPP 0 0 0 0 0 0 0 0 RES 0 5 282 405 405 406 406 406 Other (Elteprod+Sugar CHP) 4 4 4 4 4 4 4 4 TOTAL Local PPs 873 879 1,160 4,675 4,769 5,157 5,660 6,003 Import, mil kWh 3,199 3,291 3,424 0 0 20 107 165 Import, % from Demand 79 79 75 0 0 0.4 1.8 2.7 58 Synchronous Scenarios Synchronous-1 This scenario assumes that Romania covers both the entire capacity deficit and all ancillary services of Moldova’s power system, thus respecting ENTSO -E requirements regarding Moldova’s eventual integration into ENTSO-E. It implies the construction of new power plants as in the SS-2 scenario. Implementation of S-1 requires the construction of the following 110/330/400 kV components of the power transmission grid: - One 400 kV HVL Suceava (Romania) – Balti (Moldova) of 650 MW (870 MW (the forecasted deficit by 2033) - 220 MW (3 x 110 kV capacity), in order to meet the n-1 criterion if Vulcanesti – Isaccea HVL fails); the total line length is 115 km; - One 400/330 kV power transformer at Balti substation; - One 400 kV HVL Vulcanesti – Chisinau of 422 MW (870 MW (the forecasted deficit by 2033) - 228 MW own consumption by the Vulcanesti substation - 220 MW of 3 x 110 kV capacity, in order to meet the n-1 criterion if Suceava – Balti fails); the total line length is 160 km; - One 400/330 kV power transformer at Chisinau Substation; - Bays and other elements at the above listed power transformer substations’ locations. The following interconnection lines should be disconnected: - One 400 kV HVL Vulcanesti – MGRES; - Two 330 kV HVL Balti – Dnestrovskaia GAES (Ukraine); - Two 330 kV HVL Chisinau – MGRES; - 110 kV lines Moldova (RB) – Moldova (LB) as listed in Table A5-7; and - 110 kV lines Moldova (RB) – Ukraine as listed in Table A5-8; 59 Table A5-5. Synchronous-1: Moldova - available capacity development (MW) 2013 2014 2015 2016 2017 2018 2019 2020 2021 2025 2030 2033 Forecasted available capacity needed 833 849 862 873 886 898 911 925 939 999 1085 1143 HPP 0 0 0 0 0 0 0 0 0 0 0 0 CHP-1 27 25 25 25 25 25 25 0 0 0 0 0 CHP-2 162 202 202 202 202 202 202 0 0 0 0 0 CHP-3 0 0 0 0 0 0 0 250 250 250 250 250 CHP-Nord 20 20 20 20 20 20 20 20 20 20 20 20 CCPP 0 0 0 0 0 0 0 0 0 0 0 0 CPP 0 0 0 0 0 0 0 0 0 0 0 0 RES 0 0 0 0 0 0 0 3 3 3 3 3 TOTAL Local available capacity 209 247 247 247 247 247 247 273 273 273 273 273 Import 624 602 615 626 639 651 664 652 666 726 812 870 Table A5-6. Synchronous-1: Moldova - electricity demand balancing (million kWh) 2013 2014 2015 2016 2017 2018 2019 2020 2021 2025 2030 2033 Total electricity delivered at DAF, Edaf 4,072 4,170 4,248 4,328 4,410 4,496 4,584 4,675 4,769 5,177 5,766 6,168 HPP 70 70 70 70 70 70 70 70 70 70 70 70 CHP-1 50 50 50 50 50 50 50 0 0 0 0 0 CHP-2 701 701 705 705 710 710 710 0 0 0 0 0 CHP-3 0 0 0 0 0 0 0 1,625 1,625 1,625 1,625 1,625 CHP-Nord 48 48 45 45 45 44 44 44 44 44 44 44 CCPP 0 0 0 0 0 0 0 0 0 0 0 0 CPP 0 0 0 0 0 0 0 0 0 0 0 0 RES 0 5 32 74 130 199 282 405 405 406 406 406 Other (Elteprod+Sugar CHP) 4 4 4 4 4 4 4 4 4 4 4 4 TOTAL Local PPs 873 879 906 948 1,008 1,077 1,160 2,148 2,148 2,148 2,149 2,149 Import, mil kWh 3,199 3,291 3,342 3,380 3,402 3,419 3,424 2,527 2,621 3,029 3,617 4,019 Import, % from Demand 79 79 79 78 77 76 75 54 55 59 63 65 60 Table A5-7. 110 kV lines Moldova (RB)-Moldova (LB) and the impact of their disconnection to implement S-1 Line 110 kV Moldova (RB) Current no. Impact by disconnecting – Moldova (LB) status 1. Vertiujeni – Kuzimin (Tr) connected n-1 violated. RB Affects: villages Vertiujeni and Varancau; LB: Kuzimin 2. Floresti – Camenca, 110 kV connected n-1 violated. Affects LB: town Camenca 3. Cuguresti – Camenca, 35 kV disconnected 4. Rezina – Ribnita connected n-1 violated. Affects RB: towns Soldanesti and Rezina, ГКС, Rezina, village Ignatei 5. Orhei – Rabnita connected n-1 violated. Affects RB: town Rezina, village Cinesueti 6. Orhei – HPP Dubasari disconnected n-1 violated. Affects RB: villages Marcauti 7. CHP-2 – Dubasari connected n-1 violated. Affects RB: Vadul-lui-Voda. Voltage level in Criuleni and the main Water Pumping Station50 may be too low 8. Vadul-lui-Voda – Dubasari connected n-1 violated. Affects RB: Vadul-lui-Voda. Lower voltage level in Criuleni and at the main Water Pumping Station in Vadul-lui-Voda.. 9. Lesnaia – Grigoriopol connected Affects RB: Total lack of 110 kV in Lesnaia 10. Varnita – HBK connected n-1 violated. Affects RB: Varnita, Calfa, Buliboaca, Anenii-Noi, Singera, Serpeni. Lower voltage level in some locations. 11. Causeni – HBK, MGRES – connected Affects RB: Total lack of 110 kV in Ursoaia, Stefan-Voda Causeni, Stefan Voda, Rascaitii Noi, 12. Ciobruci – MGRES connected Affects RB: Total lack of 110 kV in Ciobruci 13. Olanesti – MGRES connected Affects RB: Total lack of 110 kV in Olanesti, Purcari, Caplani, and other Table A5-8. 110 kV interconnection lines with Ukraine and the impact of their disconnection 110 kV lines Moldova no. Current status Impact by disconnecting (RB) – Ukraine n-1 violated. Affects Larga, Lipcani, 1. 110 kV Larga – Nelipovty disconnected Beleavinty (MD RB) n-I not violated, but a large number of urban 110 kV Briceni – 2. connected and rural locations will get poorer quality Dnestrovsk HPP supply 3. 110 kV Oknita – Sahta connected n-I violated. Affects Ocnita (MD) 4. 110 kV Otaci – Nemia connected n-I violated. Affects Nemia (UA) 5. 110 kV Soroca – Poroghi connected n-I violated. Affects Poroghi, Iampoli (UA) 110 kV MGRES – Not to be disconnected, as it is supplying 6. connected Starokazacie Moldova (RB). 110 kV Vulcanesti – 7. connected No significant impact if disconnected. Bolgrad 50 The Main Water Pumping Station in Vadul-lui-Voda supplies most of the Capital City of Chisinau. 61 To ensure that the n-1 criterion for the 110 kV network remains operational in the radial power supply after the Moldova (RB) – Moldova (LB) and Moldova (RB) – Ukraine 110 kV lines are disconnected, appropriate transmission grid reinforcement is needed. The following power transmission grid components have to be constructed as listed in Table A5-9. Table A5-9. The required 110 kV power transmission grid reinforcement in S-1 Capacity, Investments, New grid elements Length, km MW US$ million Larga – Briceni 70 20 0.6 Briceni – Ocnita 70 30 0.9 Ocnita – Lencauti 70 12 0.4 Raduleni – Soroca 70 20 0.6 Vertiujeni – Camenca 70 8 0.2 Rezina Cement Factory – Rezina substation 10 70 10 0.3 Greblesti – Orhei 70 25 0.8 Dubasari (LB) – Criuleni 70 7 0.2 Varnita – Ursoaia 70 10 0.3 Stefan - Voda – Rascaietii Noi 70 15 0.75 330/110kV substation at Lencauti 2 x 125 6 400/110kV substation at Stefan-Voda 2 x 125 7.3 TOTAL 157 21.1 62 G N L B Stanca - Costesti 110 kV O Kotovsc Suceava Ribnita UKRAINE Balti Tutora - Ungheni 110 kV 188 MW Iasi Straseni Chisinau Cioara - Husi 110 kV 259 MW MGRES ROMANIA Synchronous 1 Scenario 228 MW 400 kV Isaccea Vulcanesti 330 kV 110 kV new HVL х - disconnection Power absorbed from 330 - 400 kV grid Figure A5-1. Synchronous-1 63 Synchronous-2 S-2 assumes the same as S-1 except it would have different interconnection points and required transmission lines, including the construction of one 400 kV HVL Stefan-Voda – Ursoaia of 30 km and the appropriate substation equipment in Stefan-Voda and Ursoaia (Figure A5-2). Stanca - Costesti 110 kV Kotovsc Suceava Ribnita UKRAINE Balti Tutora - Ungheni 110 kV 188 MW Iasi Straseni Chisinau Cioara - Husi 110 kV 259 MW Stefa n-Voda MGRES ROMANIA Urs oaia Synchronous 2 Scenario 400 kV 228 MW 330 kV Isaccea Vulcanesti 110 kV new HVL х - disconnection Power absorbed from 330 - 400 kV grid Figure A5-2. Synchronous-2 64 Synchronous-3 S-3 assumes that the power deficit would be covered by both Romania and MGRES, while the ancillary services would be covered by Romania only. The entire Moldovan power system, including most assets located on the Left Bank, would be connected synchronously with ENTSO- E, and disconnected from the IPS/UPS (Figure A5-3). It implies the construction of new power plants as in SS-2 scenario. Implementation of S-3 requires the construction of 110/330/400 kV components for the power transmission grid as listed below: 1. One 400 kV HVL Suceava (Romania) – Balti (Moldova) of 650 MW (870 MW (the forecasted deficit by 2033) - 220 MW (3 x 110 kV capacity), in order to meet the n-1 criterion if Vulcanesti – Isaccea HVL fails); the line length is 115 km; and 2. Four 110 kV HVL and appropriate substation equipment as listed in the Table A5-10 below to respect the n-1 criterion for grid segments operating in radial mode once the 110 kV HVL between Moldova and Ukraine are disconnected. Table A5-10. The required 110 kV transmission grid reinforcement under Synchronous-3 Investments N Capacit Length, New grid elements , US$ Comments o y, MW km million 1. Larga – Briceni 70 20 1 2. Briceni – Ocnita 70 30 1.5 3. Ocnita – Lencauti 70 12 0.6 Most industrial facilities in Rezina Cement Factory – 4. 70 10 0.4 Rezina and Ribnita will stay Rezina substation no.10 connected to Ukraine. 330/110 kV substation at 5. 2 x 125 6 Lencauti TOTAL 72 9.5 S-3 will require disconnection of HVLs between Moldova and Ukraine as listed bellow: - 330 kV line MGRES – Usatovo (Ukraine); - 330 kV line MGRES – N.Odeskaia (Ukraine); - 330 kV line MGRES – Kotovsc (Ukraine). The three HVL listed above should stay connected to the MGRES’s 330 kV bus-bar to ensure the static stability of the regional grid in Ukraine. - 330 kV line Balti (Moldova RB) – Dnestrovskaia GAES (Ukraine); - 110 kV line Dubasari (Moldova LB) – Kotovsk; - 110 kV MGRES – Starokazacie; - 110 kV MGRES – Beleaevka; - 110 kV MGRES – Razdelinaia; - 110 kV lines - Moldova (RB), according to the list from Table A5-8. Another HVL connecting Moldova LB to Ukraine double-circuit line, 2 x 330kV Kotovsk (Ukraine) – Ribnita (Moldova LB), could not be disconnected from Ukraine, unless an appropriate HVL is built between Balti (Moldova RB) and Ribnita (Moldova LB), which is very costly and exposed to significant financial risks. Therefore several industrial facilities in Rezina (Right Bank), Ribnita (Left Bank) and the adjacent grid would stay connected with Ukraine. 65 S-3 looks more attractive compared to the same scenario without MGRES, as it covers the country’s electricity demand and ensures an acceptable degree of competition to sell electricity. However, the assumption that MGRES might join the ENTSO-E along with the rest of Moldovan Right Bank’s power system is not realistic in view of the current political realities in Moldova. Stanca - Costesti 110 kV Kotovsc Suceava Ribnita UKRAINE Balti Tutora - Ungheni 110 kV 188 MW Iasi Straseni Chisinau Cioara - Husi 110 kV 259 MW MGRES ROMANIA Synchronous 3 Scenario 228 MW 400kV Isaccea Vulcanesti 330kV 110kV new HVL х - disconnection Power absorbed from 330 - 400 kV grid Figure A5-3. Synchronous-3 66 Synchronous-4 S-4 assumes that Romania will cover the entire power deficit and all ancillary services similarly to S-1, but it would require much larger investments in the domestic transmission grid to enable synchronous operation with Romania and to ensure that the n-1 criterion is met as required by ENTSO-E. The evolution of available capacity and electricity produced by local power plants is similar to S-1. The implementation of S-4 requires the construction of power system components as listed below and as shown in Figure A5-4: - The 2nd 400 kV HVL Vulcanesti – Isaccea of 650 MW (870 MW (deficit by 2033) - 220 MW of 3x110 kV capacity to meet the n-1 criterion if the existing 400 kV HVL Vulcanesti – Isaccea fails). The total length is 55km; - Two 400 kV HVL Vulcanesti – Chisinau of 422 MW each (870 MW (deficit by 2033) - 228 MW Vulcanesti substation own consumption - 220 MW of 3x110 kV, to meet the n-1 criterion if one of one 400 kV HVL Vulcanesti – Chisinau fails). The total length is 160 km; - The 2nd 330 kV HVL Chisinau – Straseni of 340 MW (195 MW Balti load + 188MW Straseni load - 44 MW the share of 3 x 110 kV 220 MW to Balti - 41 MW the share of 3x110 kV 220 MW to Straseni; the lowest capacity of 330 kV lines (by current) according to IPS/UPS standards) is equal to 270 MW (2 cables ACO-240); The difference of 40 - 60 MW (Surge Impedance Loading of this line is 360 MW) will be used to supply new Lepcauti substation listed in the Table A5-10; - The 2nd 330 kV HVL Balti – Straseni of 340 MW (Balti demand is about 151 MW (195 MW Balti load - 44 MW the share of 3x110 kV 220 MW to Balti; 340 MW is the lowest capacity requirement for the 330 kV lines (by current) according to IPS/UPS standards); The difference of 189 MW (340 - 151) will be used to supply the new Lepcauti substation listed in the Table A5-10; - Two 400/330 kV automated transformers at Chisinau substation of 422 MW each; - Bays and other components at appropriate substations. The following interconnection lines would be disconnected: - 400 kV line Vulcanesti – MGRES; - 330 kV line Balti – Dnestrovskaia GAES (Ukraine); - Two 330 kV lines Chisinau – MGRES; - 110 kV lines between the Right Bank and the Left Bank, as it is shown in Table A5-7; - 110 kV lines between Moldova (RB) and Ukraine, as it is shown in Table A5-8; The construction of additional system components is required to meet the n-1 criterion for the 110 kV network remaining operational in the radial power supply after the Moldova (RB) – Moldova (LB), Moldova (RB) - Ukraine 110 kV lines are disconnected, as listed in the Table A5-9 above. 67 Grid New Larg Bric Lencauti Ocn Stanca - Costesti 110 kV Rad Kotovsc Suceava Ribnita UKRAINE Balti Tutora - Ungheni 110 kV 188 MW Iasi Straseni Chisinau Cioara - Husi 110 kV 259 MW Stefan-Voda MGRES ROMANIA Synchronous 4 Scenario 400kV 330kV 228 MW 110kV Isaccea Vulcanesti new HVL х - disconnection Power absorbed from 330 - 400 kV grid Figure A5-4. Synchronous-4 68 Annex 6: Asynchronous Interconnection Scenarios Asynchronous 1 (A-1) Implementation of A-1 requires the construction of two BtB stations: one based on LCC technology in Straseni, another based on VSC technology in Vulcanesti, three 400 kV lines and the appropriate substation equipment (Figure A6-1): - One 400 kV BtB station at Vulcanesti (Moldova) substation based on VSC technology, capacity 3 x 175 MW (525 MW). VSC has higher electricity losses than LCC technology: Output power of Vulcanesti BtB station should be 525 MW. It has been determined based on the following rationale. In order to ensure the import of 870 MW and to respect the n-1 criterion, three units each of 174 MW of BtB should be installed at the Vulcanesti and Straseni substations. If one unit fails (n-1 criterion), the remaining 5 units can transmit 5 x 174 = 870 MW. However, since VSC has 0.5% higher electricity losses than LCC technology, the unit capacity of the Vulcanesti BtB station should be 175 MW (174 x (1+0.5%)); - One 400 kV BtB station of three units each of 174 MW at Straseni (Moldova) substation with a total capacity of 522 MW; - A double-circuit 400 kV HVL Straseni (Moldova) – Iasi (Romania); 2 x 348 = 696 MW capacity; 100 km in length (of which 80 km are within Moldova). A total number of three 400 kV circuits with Romania have to be built under this scenario, one already existing, to ensure the reliability and security of supply. When 1 circuit fails, the other 3 should ensure the transmission of 870 MW, 348 (one circuit) + 522 (BtB) = 870 MW); - One additional single-circuit 400 kV line Vulcanesti –Isaccea of 348 MW. - A double-circuit 400 kV HVL Vulcanesti – Chisinau of 2 x 149 = 298 MW; 160 km in length. (298 = 522 – 224, where 522 MW is the output capacity of Vulcanesti BtB and 224 MW is load of Vulcanesti HV substation); and - 400kV line bays at Vulcanesti and Chisinau for Vulcanesti– Chisinau 400 kV HVL and 400/330kV transformers and associated bays at Chisinau. The 522MW capacity for BtB stations and HVL is required to meet the n-1 criterion, i.e. if one of the above mentioned units fails, the two remaining would ensure that Moldova’s power deficit of 870 MW by 2033 can be met. The following lines would be disconnected: • Tutora (Romania) – Ungheni (Moldova), 110 kV; • Husi (Romania) – Cioara (Moldova), 110 kV; and • Stanca (Romania) – Costesti (Moldova), 110 kV. The development of domestic generation and the volume of electricity imports are similar to the Synchronous-1 scenario (see the line ‘Import’ in Tables A5-1 and A5-2, Annex 5). Due to the weakness of the southern part of the Moldovan power system, VSC technology is proposed for the Vulcanesti BtB station. VSC has some advantages over LCC such as black-start capability and independent reactive power control. However, VSC is a relatively new technology and there is therefore limited operational experience with it worldwide, especially with regard to large rated 69 capacities in excess of 500 MW. Moldelectrica might face operational challenges such as the interaction between VSC and LCC, which should be carefully analyzed in a feasibility study. In addition, since a limited number of suppliers manufactures VSC, the actual price of the technology will very much depend on local and market conditions. Figure A6-1. Asynchronous-1 70 Asynchronous 2 (A-2) Implementation of A-2 involves the construction of two BtB stations based on LCC technology, three 400 kV lines, two 330 kV lines, and the appropriate substation equipment (Figure A6-2), all needed to meet the n-1 criterion and to ensure the transmission capacity of 870MW with Romania to satisfy Moldova’s power demand: - One 400 kV BtB station at Balti substation (Moldova) of 522MW. In order to ensure the import of 870 MW and to meet the n-1 criterion, three units each of 174MW of BtB should be installed at Balti (and Straseni) substation. If one unit fails the remaining 5 units can transmit 870MW (5 x 174 = 870 MW); - One 400 kV BtB station at Straseni substation (Moldova) of capacity 522 MW. In order to ensure the import of 870 MW and to meet the n-1 criterion, three units each of 174 MW of BtB should be installed at Straseni (and Balti) substation. If one unit fails the remaining 5 unit can transmit 870 MW (5 x 174 = 870 MW); - A double-circuit 400 kV HVL Suceava (Romania) – Balti (Moldova) of 348 MW each, 2 x 348 = 696 MW. The length is 115 km (of which 55 km are within Moldova); and - A double-circuit 400 kV HVL Iasi (Romania) – Straseni (Moldova) of 348 MW each, 2 x 348 = 696 MW. The length is 100 km (of which 80 km are within Moldova). This scenario includes two double-circuit 400 kV HVL with Romania in order to meet the n-1 criterion. If one circuit fails, the remaining three circuits would enable transmission of 870 MW through the two BtB stations (348 (one circuit) + 522 (BtB) = 870 MW). - A single-circuit 400 kV HVL Vulcanesti – Chisinau of 224 MW, which equals Vulcanesti substation’s own consumption. If this line fails, Vulcanesti load of 224 MW will be covered by the 400 kV line Vulcanesti – MGRES, thus respecting the n-1 criterion. The length is 160 km; - The 2nd 330 kV HVL Balti – Straseni of 156 MW. When the existing 330 kV circuit Balti – Straseni fails, the remaining circuit should have the capacity to transmit 156 MW = 870 MW – 522 MW - 192 MW (the load absorbed by Balti). The length is 103 km; - The 2nd 330 kV HVL Straseni – Chisinau of 478 MW. The needed capacity is determined by the load absorbed by Chisinau and Vulcanesti if the existing Straseni – Chisinau line fails, i.e. 478=254 (Chisinau) + 224 (Vulcanesti). The length is 41 km; and - 400 kV line bays at Vulcanesti and Chisinau for the 400 kV HVL Vulcanesti – Chisinau, 330 kV line bays at Balti, Straseni and Chisinau for the 330 kV HVL Balti- Straseni and Straseni – Chisinau, and 400/330 kV transformers and associated bays at Chisinau. The following lines would be disconnected: - Isaccea (Romania) – Vulcanesti (Moldova), 400 kV - Tutora (Romania) – Ungheni (Moldova), 110 kV; - Husi (Romania) – Cioara (Moldova), 110 kV; and - Stanca (Romania) – Costesti (Moldova), 110 kV. The development of domestic generation and the volume of electricity imports are similar to the Synchronous-1 Scenario (see the line ‘Import’ in Tables A5-1 and A5-2, Annex 5). 71 The relatively robust AC power system in the North and Center of Moldova enables the use of LCC- based BtB stations. LCC has been used much longer than VSC and is a mature technology. In addition, LCC is suitable for large capacity converters in the range of hundreds of MVA. However, since LCC is not able to independently control reactive power, the impacts on the existing AC network (including voltage stability, over-voltages, resonances and recovery from disturbances) should be carefully analyzed in a feasibility study. Stanca-Costesti 110 kV Kotovsc Suceava Ribnita UKRAINE Balti BtB 3x Tutora - Ungheni 110 kV N-1 BtB 185 MW Iasi Straseni Ne 2x Chisinau 1x 1x Cioara - Husi 110 kV 254 MW Tot MGRES ROMANIA 2x 2x Asynchronous 2 Isaccea 224 MW 400kV Vulcanesti 330kV 110kV new HVL х - disconnection Power absorbed from 330 - 400 kV grid Back-to-Back station (BtB) Figure A6-2. Asynchronous-2 72 Asynchronous 3 (A-3) Implementation of A-3 requires the construction of two BtB stations: one based on LCC technology in Balti, another based on VSC technology in Vulcanesti, three 400 kV lines one 330kV lines and the appropriate substation equipment (Figure A6-3): - One 400 kV BtB station at Vulcanesti (Moldova) substation based on VSC technology, capacity 3 x 175 MW (525 MW). As is the case with A-1, VSC has 0.5% higher electricity losses than LCC technology, the unit capacity of Vulcanesti BtB station should be 175MW (174 x (1+0.5%)); - One 400 kV BtB station of three units each of 174 MW at Balti (Moldova) substation with a total capacity of 522 MW; - A double-circuit 400 kV HVL Suceava (Romania) – Balti (Moldova) of 348 MW each, 2 x 348 = 696 MW. The length is 115 km (of which 55 km are within Moldova) km; - One additional single-circuit 400 kV line Vulcanesti –Isaccea of 348 MW; - A double-circuit 400 kV HVL Vulcanesti – Chisinau of 2 x 149 = 298 MW; 160 km in length (298 = 522 – 224); and - 400kV line bays at Vulcanesti and Chisinau for Vulcanesti– Chisinau 400 kV HVL, 330kV line bays at Balti and Straseni for the 330kV HVL Balti- Straseni, and 400/330kV transformers and associated bays at Chisinau. The following lines would be disconnected: • Tutora (Romania) – Ungheni (Moldova), 110 kV; • Husi (Romania) – Cioara (Moldova), 110 kV; and • Stanca (Romania) – Costesti (Moldova), 110 kV. The development of domestic generation and the volume of electricity imports are similar to the Synchronous-1 scenario (see the line ‘Import’ in Tables A5-1 and A5-2, Annex 5). A-3 requires more domestic transmission system reinforcement than A-1 and A-2, resulting in increased investment costs under that scenario. On the other hand, given the [reportedly]51 near- readiness of the grid on the Romanian side, the implementation period for A-3 could be shorter than that for other scenarios. As discussed under the A-1 scenario, while VSC technology has various advantages over LCC, technical and operational challenges are expected to be significant and should be carefully studied in a feasibility study. 51 As advised by the Transelectrica representatives during the May 2015 dissemination Workshop. 73 Stanca-Cosesti 110 kV Kotovsc Suceava Ribnita UKRAINE Balti Tutora - Ungheni 110 kV 185 MW Iasi Straseni Chisinau Cioara - Husi 110 kV 254 MW MGRES ROMANIA Asynchronous 3 (Gov) Isaccea 224 MW 400kV 330kV Vulcanesti 110kV new HVL х - disconnection Power absorbed from 330 - 400 kV grid Back-to-Back station (BtB) Figure A6-3. Asynchronous-3 74 Short circuit requirements for BtB station implementation Voltage/power stability is a critical issue for a HVDC transmission link based on conventional LCCs, if the receiving end of the transmission link is connected to an AC system having low short circuit capacity. The lower the short circuit capacity of the connected AC system as compared with the power rating of the HVDC converter, the more problems can be expected related to voltage/power stability. The physical mechanism causing this voltage instability is the inability of the power system to provide the reactive power needed by the converters to maintain an acceptable system voltage level. Effective Short-Circuit Ratio (ESCR) is often used to describe the strength and reliability of an AC system connected to an HVDC converter. In general, most system planners are using an ESCR of 2.5 as the lowest acceptable value for the interconnection of two transmission systems via HVDC as to ensure their stable operation52. However, given the condition of the Moldovan grid, this study assumes that the minimum acceptable ESCR should be 3.0 or higher at this very early stage of BtB station planning. Table A6-1 presents the calculations and values used to assess the feasibility of asynchronous scenarios based on this requirement. Input data used were: (i) current short circuit values at the high voltage bus-bar substations for each location where a BtB station is considered: Balti, Straseni, and Vulcanesti; and (ii) the capacity of BtB stations for each of the Asynchronous scenarios considered in the study. As shown in the table below, the ESCR exceeds the 3.0 value for Balti and Straseni, but it is much lower for Vulcanesti. Therefore, VSC53 technology is being proposed there in the A-1 and A-3 scenarios. Table A6-1. Moldova 330 – 400 kV bus-bar Short Circuit data Volt Short circuit Short circuit Effective SCR Effective SCR Elements BtB Capacity Substation age, current, kA power, MW (at Min) (at Max) disconnected kV Min Max Min Max A-1 A-2 A-1 A-2 A-1 A-2 HVL 330kV Balti- Straseni, 1AT Balti, Balti 330 3.92 8.2 2237 4675 522 3.7 8.4 No generation at Dn HPP HVL 330kV Straseni-Chisinau, Straseni 330 1AT to Balti, No 3.93 10.3 2246 5878 522 522 3.7 3.7 10.7 10.7 generation at Dn HPP 110 kV line, 1AT 400 Vulcanesti, No 2.53 4.7 1752 3256 522 2.8 5.6 MGRES generation 400 kV line, 1AT Vulcanesti 400 0.92 4.7 637 3256 522 0.6 5.6 Vulcanesti 400 kV line, 1AT 400 Vulcanesti, 110 kV 0.48 4.7 332 3256 522 0.04 5.6 line 400 kV line (Vulcanesti – 400 3.42 4.7 2369 3256 522 3.9454 5.6 Chisinau in operation) Source: Moldelectrica 52 Panelists: P.C.S. Krishnayya at al, ‘Report of a panel discussion sponsored by the Working Group on interaction with Low Shor t Circuit Ratio AC Systems of the IEEE DC Transmission Subcommittee’, IEEE Transactions on Power Delivery, Vol. PWRD -1, No. 3, July 1986. 53 The new VSC technology substations can operate independently from the SCMVA at the connection point. 54 If the planned Chisinau – Vulcanesti line is connected with the AC system, the ESCR will exceed 3.0, which is the minimum threshold required for LCC. However, if the line is disconnected due to events such as maintenance or faults, then the ESCR would be far below 3.0 and in that case LCC operation is not feasible. The study proposes a VSC-based BtB station at Vulcanesti in order to avoid that the AC system becomes uncontrollable under certain conditions. 75 Annex 7: Market Design Options and Evaluation For Moldova three possible market design options to ensure wholesale market competition were analyzed, all three compatible with the EU Target Model. For each of them the security and affordability they would provide were analyzed. The three options are market-driven but correspond to the three scenarios for interconnection development: 1. A standalone competitive wholesale market. This corresponds to synchronous connection to ENTSO-E combined with system self-sufficiency. The share of electricity that would be subject to competition (in the long term) would to a large extent be produced inside the country. 2. A competitive wholesale market with appropriate rules but without an appropriate market structure. This corresponds to asynchronous interconnection with ENTSO-E while the interconnection with Ukraine and MGRES would also remain sources of supply. Moldovan suppliers would be able to procure electricity from East or West, depending on price. For the most part competitively priced electricity would come from outside Moldova and its wholesale market. 3. Merging with an already competitive wholesale market. This corresponds to synchronous interconnection to ENTSO-E without aiming for self-sufficiency. With the Moldovan market merging with the Romanian market under this option, the electricity would be produced in this common market territory but not necessarily in Moldova. Market design option 1: A standalone competitive wholesale market. This market design option could be implemented under a Self-Sufficiency scenario. i. Market Structure. A quantitative assessment of market structure could use Herfindall- Hirschman Index (HHI) and C3 (the share of the market held by the largest three producers) criteria to evaluate market concentration on both the sell and buy sides: power exchange (PX) platform, national, or regional market. Few EU countries have achieved acceptable values for such competition indicators in their national market, but one of those countries is Romania. To build such a market structure Moldova would have to focus on both sides: • To build an acceptable buy side, market opening is required in order to attract alternative suppliers in addition to the incumbents. • An acceptable sell side could be built by enlarging the domestic generation base. For new capacity one could use either the authorization procedure (art.7 of Directive 2009/72/EC) or the tendering procedure (art.8). These procurement methods have very different implications for competitive market development. For capacities built on a tender basis the organizers have to guarantee power purchases at a fixed price over many years. During that period those quantities will be missing from the competitive wholesale market. For that reason it is better to avoid the tender procedure. Although the stand-alone market option builds theoretically on self-sufficiency of the system, which does not necessarily include interconnection with ENTSO-E, a self-sufficiency alternative might be difficult to ensure without connection to a large, competitive wholesale 76 market. Otherwise one of the most important investment incentives into the stand-alone market would be missing. The likelihood that a significant part of generation capacity would be built through the authorization procedure, thereby providing a basis for real competition, is low. ii. Market rules. The appropriate market rules would comply with network code provisions and best practice. Energy trading would be based on medium and long term bilateral contracts to provide stability and on day-ahead market contracts to discover the price. The allocation of cross-border capacities has to comply with the Acquis on both borders, Romania being a EU Member State and Ukraine an EnC Contracting Party. Here cooperation with neighboring TSOs and regulators is necessary. If ongoing efforts to create a regional Coordinated Auction Office (CAO) for the 8th region are successful55, adherence by Moldova to that auction office would be helpful. During its transitional period, the CAO would calculate and allocate cross- border capacities using the coordinated Net Transmission Capacity (NTC) method, which raises no concern on Moldova’s borders. iii. Balancing. Whether built under authorization or tender procedure, the new generation capacity will be able to provide balancing means, including balancing mechanisms and ancillary services. Taking into consideration the limited hydro reserves of Moldova which are not used for balancing but for base-load, synchronous interconnection with ENTSO-E would allow procurement not only of tertiary reserves but also of all other reserves and services. However, even in Romania only the tertiary reserves are procured mostly competitively, primary and secondary reserves being rather regulated because Hydroelectrica has about 80% of that market. The Romanian energy law forbids generators to bid outside the framework created by the energy regulator. However, Moldelectrica could seek a TSO-TSO agreement in order to be allowed to procure such reserves by organizing tenders on the ancillary services trading platform that Transelectrica is developing. A further sharing of balancing resources based on the TSO-TSO trade model would enhance Moldelectrica’s ability to balance its system and to back up intermittent generation of RES-E sources. The utilization of tenders to integrate RES-E will allow decision makers to limit installed capacity to the power system’s capacity to balance, including the interconnector capacity to transfer tertiary reserves when needed. An equitable system should be in place to calculate imbalances and charge the cost to all generators, including RES-E generators. iv. Institutions. A market operator would need to be created for wholesale market trading improvement. In addition, the planning capacity of the TSO has to be improved and its ability to manage balancing mechanisms has to be increased. Optionally, a separate entity could be created to gather RES-E generation output and to: (i) distribute that to suppliers and collect the payment; or (ii) sell it into the wholesale market (if sufficiently liquid) and to pay/collect differences then socializing them to all end consumers56. 55 The 19th Athens Forum meeting (June 2-3, 2014) announced a pilot allocation of monthly capacities starting October 2014. Also, allocation of yearly capacities for 2015 will start in November 2014 for all SEE CAO participating TSOs. However the Forum also noted that “lack of participation by the network operators in Bulgaria, FYRoM and Serbia (hindering participation of Romania) undermines the effectiveness of the SEE CAO project, contradicts Energy Community Treaty obligations and disregards the upcoming EU harmonization of forward trading rules.“ 56 It will play the role the distribution companies have in Germany and a specialized agency has in Austria. 77 Coupling that standalone market with other markets would represent optimization. While that will not improve the domestic market structure it will improve liquidity, mitigate Day Ahead Market (DAM) price volatility and help limit the investment cost component of the price of electricity from which otherwise additional investment costs would need to be recovered. Market design option 2. A competitive wholesale market with appropriate rules but without an appropriate market structure. This option could be implemented under either: (i) an asynchronous interconnection with ENTSO-E; or (ii) a synchronous interconnection with ENTSO-E if both self- sufficiency is not achieved (as option 1 requires) and the conditions to operate the electricity systems in Moldova and Romania as one are not met (as option 3 requires). i. Market structure. If the conditions for system self-sufficiency are not met, a functional standalone wholesale market cannot be built due to limited competition on the sell side even in the long term. Option 2 does not assume an appropriate market structure while the high cost of investment combined with low consumption discourages investment via the authorization procedure. The Government would use tendering for RES-E, rehabilitation, refurbishment, or replacement of CHPs, and gas turbines. Accordingly, the amount of electricity brought into the competitive wholesale market by domestic generation would be very limited as the regulator would continue to regulate prices and quantities of domestic generation57. However, even then organizing a competitive market that is highly dependent on power exchanges with more mature and liquid markets makes sense. To have competition on the sell side, thus making the existing competition rules in the Moldovan wholesale market effective, requires an inflow of electricity from the West. Coupling with the Romanian day-ahead market mimics the submarine cable connection of Poland with Sweden that allowed coupling of Poland with NordPool. It is also similar to the planned asynchronous interconnection between Lithuania and Poland. However, it will not necessarily improve domestic wholesale competition, because the flows may refer not only to traders’ activity, but mainly to the activity of domestic suppliers who take electricity from the Romanian/EnC wholesale markets and move it directly into the retail market. In that case the retail market in Moldova will increasingly be the main beneficiary of the competition on the Romanian/EnC wholesale market, thus gradually improving conditions for market opening. ii. Market rules. In this case appropriate market rules can still be adopted by replacing domestic generators on the sell side, as envisaged under option 1, with foreign/domestic traders who move electricity from abroad, either West (asynchronously) or East (synchronously). Of paramount importance is to ensure sufficient interconnection capacity with ENTSO-E where the electricity will come across the border. Although competition does not currently exist in the Ukrainian market and a monopolistic export situation may persist there despite EnC rules, from time to time an opportunity to buy cheap electricity from Ukraine may come up and compete with EnC sources of electricity. In case option 2 is adopted the rules of cross-border capacity allocation should mix explicit and implicit allocations, reflecting the breakdown of available cross-border capacity as decided by the regulator. Even when only implicit auction is the rule, explicit allocation has to remain a fall-back option. Adherence to the CAO would 57 There are three (non exclusive) alternatives for the electricity from refurbished CHPs to enter a competitive market: a) partly, if not all its generation capacity will be granted a purchase obligation at regulated tariff; b) entirely, if a cogeneration bonus scheme is in place; and c) entirely, after investment costs have been recovered. Without rehabilitation/refurbishment that generation will not be able to compete and regulated price and purchase obligations will have to be maintained. 78 be desirable, its role not being limited only to coordinated explicit allocation but also to coordinated available capacity calculation. iii. Balancing. Regarding balancing capacity, the obligation to develop RES-E to 150 MW remains, independent of the extent of new generation based on conventional sources (CHP-3 and GT). Under option 2 the balancing capacity of the domestic system would be much lower than in the case of a self-sufficient standalone market. However, the interconnection capacity to ENTSO-E, as well as the quest for tertiary reserves, become much more important, while other reserves would continue to be acquired from Ukraine. iv. Institutions. The reason for building a market operator is to develop, organize and administer at least the day-ahead and centralized forward markets. In the case of asynchronous connection and a missing appropriate market structure on the sell side, the existing and potential suppliers acting as buyers will have the obligation to purchase electricity from domestic generators and the opportunity to buy electricity from the Ukrainian or EnC wholesale markets. The Moldovan centralized trading platform (if any) will not benefit from the presence of Romanian electricity producers if the latter are not allowed to sell electricity outside the centralized market in Romania. On the other hand the Romanian centralized markets are much more liquid. Whether setting up separate centralized platforms in Moldova can be successful is debatable. If the attempt to create a separate Moldovan market operator is not successful it will bring stranded costs and negative signals for market development. It would be better to negotiate the opening of a subsidiary of OPCOM in Chisinau. In that case, if domestic centralized platforms are not successful the stranded costs will be only administrative. Market design option 3. Merging with an already competitive wholesale market. This option could be implemented under a synchronous interconnection with ENTSO-E. However, interconnection capacity should be sufficient to ensure having no cross-border congestion. i. Market structure. This option requires full synchronization with ENTSO-E and no congestion. The Romanian TSO will provide all the ancillary services. However, if there is congestion in the synchronous operation the conditions for market organization would be similar to those described in market design option 2 for the asynchronous interconnection. Without congestion, Moldova and Romania would represent a unique bidding zone. ii. Market rules. To become part of the Romanian market requires harmonizing Moldovan legislation, adhering to Romanian market rules, and using the same market operator, possibly even sharing its ownership. Coupling with Romania is not applicable but the merger with the Romanian bidding zone will intermediate coupling with the Hungary-Czech-Slovakia zone. There would be no need for implementation of cross-border capacity allocation mechanisms on the Moldova-Romania border, but only on the Moldova-Ukraine border, if it remains asynchronously connected. Since the Moldovan electricity network was not built as a standalone system but deeply integrated into the Ukrainian network as part of IPS-UPS, it remains to be defined what the interconnector Moldova-Ukraine really means. This is also an important question with regard to using a BtB solution on the border with Ukraine, to ensure that importing from Ukraine remains an option in case cheaper prices are available there. 79 iii. Balancing. The Romanian TSO would ensure control of the Moldovan system. This means inclusion of Moldova’s generation assets in the balancing market operated by Transelectrica and ensuring that metering data are transferred to the Transelectrica data base. iv. Institutions. Option 3 would not require the creation of a domestic market operator. However, as in option 2, the presence of an OPCOM subsidiary in Chisinau makes sense in order to better manage relations with participants from Moldova. Equity participation of Moldelectrica in OPCOM (the only licensed electricity market operator in Romania and one of two licensed natural gas market operators there) might be negotiable. Market Design Options Evaluation The criteria used for options evaluation are the strategy objectives of the EU/EnC and GoM, namely: (i) security of supply; (ii) level of competition; (iii) affordability; (iv) compliance with regional integration objectives; and (v) sustainability. To those semi-quantitative criteria two qualitative criteria were added, namely: (vi) likelihood of implementation; and (vii) quick win potential. Market design option 1: A standalone competitive wholesale market. This option assumes that electricity demand will be met by increased domestic generation in Moldova and imports from Romania and other EnC members/contracting parties after synchronous interconnection to ENTSO-E. 1. Security of supply. At first sight, Option 1 would score very high on security of supply because it would reduce dependence on electricity imports more than all other options. However, this only replaces dependence on electricity imports with dependence on fuel imports. Any additional gas-fired generation capacity would increase dependence on natural gas imports, while coal-burning plant would introduce a new type of import dependence. Thus, Option 1 moves the focus from the electricity market to the gas market/routes. The apparent high ranking of Option 1 in terms of security of supply is undermined by Moldova’s current lack of alternative sources/routes of gas and the real possibility of political intervention in the supply of gas. At the same time, the EU electricity market is much more developed and stable in terms of pricing than the EU gas market. Therefore, importing substantial amounts of electricity from the EnC makes more sense for Moldova than sharply increasing gas-fired domestic generation capacity to the point of self-sufficiency. 2. Competition. It is assumed that old (refurbished or rehabilitated) and new domestic generation capacity, if built under the authorization procedure, will be just enough to cover demand and needing only occasional injection from East/West. A degree of overcapacity – enough to provide real competition - will be missing and concentration on the sell side will be high. Theoretically competition will exist but at a low level. On the other hand, the RES-E market share (>10%) will not be subject to competition. CHP capacities will remain regulated, so that about 25% of the market will not be subject to competition. Any power plant built based on the tender procedure (like RES-E) additional to this 25% will not only raise the average electricity price but will also further reduce the share of competition in the wholesale market because of the need for long-term power purchase agreements. This threatens implementation of a competitive market under all options, but option 1 will be most vulnerable because under that option the non-competitive share of the market is likely to be >35% and the remaining “competitive� share of the market (<65%) is domestic, while under the other two options competition will come from outside. 80 3. Affordability. If the remaining additional capacity (other than the above-mentioned RES-E and new CHP) will be built based on the tender procedure the price will be high and competition will either be limited or missing. This will have a major impact on end-user tariffs. Tariffs will be affordable only if the authorization procedure is used. However, that will make it less likely that this capacity will be built. 4. Compliance. One major objective of the EnC is cooperation and harmonization, both of which would facilitate market integration and encourage investment where justified. However, instead of enabling a sharing of resources through interconnection, option 1 assumes unnecessary (from the perspective of the regional market) investment in domestic generation capacity, given large overcapacity in Romania. 5. Sustainability. Option 1 seems to score high here. However, the cost is too high and the eventual success depends on too many risky choices. Also it would not be low-carbon if coal were chosen as a fuel for some generation capacity. 6. Likelihood. Except where the tender procedure for generation investment is used, implementation of option 1 would depend exclusively on private sector decisions. Thus, its likelihood of being achieved is the lowest of all three options. 7. Quick wins. Quick wins are not likely under this option: implementing competition rules without having effective competition will not result in reduced end-user electricity prices. Market design option 2: A competitive wholesale market with appropriate rules but without an appropriate market structure. This option would build on asynchronous interconnection with ENTSO-E as a way to eventually meet most demand by importing electricity from the EU internal electricity market. In addition, it assumes that a limited amount of domestic generation will contribute to meeting demand. 1. Security of supply. Demand could be met from three sources: (i) synchronously transferred supplies from Ukraine/MGRES; (ii) domestic generators supplying as participants in the competitive market if their efficiency enables them to compete, plus 400 MW regulated for various reasons (inefficiency or tender-based built); and (iii) asynchronously imported supplies from Romania/EnC. The system would decrease its dependence on natural gas price/routes and will not risk increasing emissions. The competitive procurement of tertiary reserves from the West would support RES-E integration. However, procurement of other ancillary services should include Ukrainian sources and MGRES. 2. Competition. Competition in the domestic wholesale market is not expected to significantly improve, but the price of electricity imported from Romania would be the result of a higher level of competition. Electricity procured from Romania could be sold by traders into the Moldovan wholesale market, which means trading twice, or directly into the retail market if procured directly from Romania by suppliers to Moldovan end-users, i.e., trading once. As mentioned before, the main beneficiary will be the retail market. The conditions for effective market opening will improve along with increased interconnection capacity with ENTSO-E and if competitive procurement by SOLR is planned to increase gradually in parallel, as in Romania. 81 3. Affordability. Electricity injection from a competitive market (EnC, via Romania) will set the price. Accordingly, the price of electricity from the East will have to decrease or such imports will disappear altogether (except ancillary services). The decrease of the commodity price as a component of the end-user price would at least partially compensate for the increase in transmission costs due to interconnector investment. 4. Compliance. The existence of a reliable asynchronous connection providing support to market coupling with Romania and other markets is in line with the provisions of the envisaged network codes, as well as with the provisions of the EnC Regional Action Plan. Regional East-West transit can happen in both directions. 5. Sustainability. After the interconnection investment cost has been recovered the positive impact on commodity prices will remain and economic welfare would be achieved in the long term. The RES-E facilities would have back-up support and additional CO2 emissions would be avoided. 6. Likelihood. The main reason to adopt this option is exactly the high likelihood that it will happen. It requires only Moldelectrica investments, which can be politically mandated. 7. Quick wins. Design option 2 provides the best prospects for quick wins. In fact this option is the only option that can be expected to result in quick wins in terms of criteria 1-5. Market design option 3: Merging with an already competitive wholesale market. This option is an extension of earlier plans that assumed parallel adherence of Moldova and Ukraine to the EnC. However, the current political situation in the region requires more reflection on the problems that separation of the Ukrainian and Russian systems might encounter. An alternative solution, namely, Moldova separately joining ENTSO-E under synchronous operation exists. However, it would involve difficult discussions and decisions otherwise lack of coordination between ENTSO-E, Romania and Ukraine could mean losing time and incurring stranded costs. 1. Security of supply. This option provides an additional component to the security of system operation, namely, the Romanian TSO assuming control of the Moldovan power system. This would provide access to a competitive market without encountering the difficulties of building a standalone one, and avoids increased dependence on natural gas imports or a new dependence on coal imports. It provides also the best support for secure integration of RES-E. However, until its full implementation this option means continuation of the existing situation. 2. Competition. The level of competition achieved in the Romanian market will not be possible in Moldova because of the limited share of competition in its market. In contrast to Option 2, Option 3 does not import competition but simply enables sharing it. 3. Affordability. Once fully implemented this option would provide the greatest affordability. However, during the transition period when consumers would have to support the investment cost without a compensating reduced commodity price it could provide the worst affordability, similar to Option 1. This cost would have a component related to RES-E integration, whose back-up energy cannot be procured competitively. 82 4. Compliance. This option provides the best compliance with regional/EU integration objectives as well as the best results. However, during the transition period there would be no support towards effective market opening. If not complemented by an asynchronous connection with Ukraine, this option would not be fully compliant with a regional vision. 5. Sustainability. The option has obvious long-term advantages, so its long-term impact is positive. Also by avoiding investments in generating plants that are not gas-fired it provides the best basis for climate change abatement. However, this solution is not suitable for RES-E integration back-up during the transition period. 6. Likelihood. In contrast to design option 2, tangible results will not come for a very long time. During this period, the implementation costs will gradually increase the end-user’s price without any offsetting price decreases. Decision makers may find it hard to resist the political pressure those increased end-user prices will bring. 7. Quick wins. This option does not provide quick wins. 83 Annex 8: Requirements for Joining ENTSO-E Minimum requirements. Art. 6 of ENTSO-E’s Articles of Association58 state that its Assembly may decide to admit new Members subject to the following minimum requirements: • the proposed Member is a legal person constituted under the laws of his country of origin; • the proposed Member is designated as a TSO according to any Regulation or Directive in force concerning common rules for the IEM; • the TSO is solely responsible for frequency control (primary and secondary) and for maintaining the power interchange at the scheduled value within a given area ("Control Area") which is located within the European Union or in a country that has entered into an agreement with the European Union governing its relationship with the IEM; • the TSO shall belong to a country or Control Area relevant to the IEM in terms of market conditions and/or the physical reality of its transmission interconnections; • the TSO disposes of or has access to the financial means needed to fulfill the obligations which directly or indirectly arise from its membership of the Association; • the TSO complies with the technical criteria and standards of the synchronous area to which it is or will be connected, in order to safeguard the stability and quality of operations of that synchronous area. The technical requirements refer to a set of conditions the candidate joining ENTSO-E should meet, among which are: Frequency Quality (Quality Design Parameters, Restoration Control Defining Parameters, Quality Evaluation Criteria, etc); Load-Frequency Control (Operational Reserves, Frequency Containment Reserves, Frequency Restoration Reserves, Replacement Reserves, etc.); Exchange and Sharing of Reserves; Time Control Process; Requirements for Grid Connection of Generators, etc. – all reflected into ENTSO-E Grid Codes. The specific measures to be taken to meet those requirements will be defined by ENTSO-E’s technical studies on the Moldovan power system’s eventual synchronization with ENTSO-E through Romania. A TSO that is not a Member of the Association may be granted Observer status . Observership application by a TSO designated as a TSO in compliance with Regulation 714/200959 and/or Directive 2009/72/EC shall be considered positively by the Assembly in light of Article 4 of Regulation 714/2009, even if the TSO does not comply with the technical criteria and standards of the relevant synchronous area. In order to be eligible for admission as an Observer, all candidates should fulfill at least the following minimum requirements: • the candidate acts as a Transmission System Operator; and • an assessment performed by the Association, based on technical, regulatory and market conditions, has confirmed that there is a reasonable expectation that the candidate will qualify for Membership in the near future. 58“Articles of Association�. 2011 Edition, 28.06.2011. ENTSO-E 59Regulation (EC) No 714/2009 of EP and of the Council of 13 July 2009 on conditions for access to the network for cross-border exchanges in electricity and repealing Regulation (EC) No 1228/2003 84 Studies needed The studies needed to join ENTSO-E for each scenario are generally determined by relevant ENTSO- E procedures. The first study would look at the technical aspects of enabling Moldova to join ENTSO- E alone (i.e., without Ukraine joining at the same time), after Moldova submits such a request. Normal and transient regimes, needed to determine the level of grid node voltages and system static and dynamic stability, would be covered by this study too. Currently one of the major questions remaining without clear answers is how RES-E development in Moldova will be integrated into its unique power system. The issue is mainly related to where the necessary balancing power will come from and what the impact will be on end-user tariffs. The answers to these questions will determine the magnitude of further RES-E development in the country, since it must be consistent with consumers’ capacity to pay. Legislation needed Prior to joining ENTSO-E all of Moldova’s secondary legislation should be in compliance with ENTSO-E grid codes, including60: • Network Code on Capacity Allocation and Congestion Management; • Network Code on Requirements for Grid Connection applicable to all Generators; • Network Code on Electricity Balancing; • Network Code on Forward Capacity Allocation; • Demand Connection Code; • Network Code on Operational Security; • Network Code on Operational Planning and Scheduling; • Network Code on Load Frequency Control and Reserves; and • Network Code on HVDC Connections The legal framework should also incorporate all EU Acquis related to RES-E development and other Community principles. Recommendations on this were proposed by experts in 201461. 60https://www.entsoe.eu 61Technical Assistance for the implementation of the Sector Policy Support Program “Support to Reform the Energy Sector� (TA - SPSP Energy) 85